Improving existing power stations to comply with emerging

lEA COAL RESEARCH

Improving existing power stations to comply with emerging emissions standards

Improving existing power stations to comply with emerging emissions standards

David H Scott

IEACR/92 March 1997 lEA Coal Research, London, UK

Copyright © lEA Coal Research 1997

ISBN 92-9029-284-9

This report, produced by lEA Coal Research - The Clean Coal Centre, has been reviewed in draft form by nominated experts in member countries and their comments have been taken into consideration. It has been approved for distribution by the Executive Committee of lEA Coal Research.

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Abstract

Environmental standards for utility power plant are gradually being tightened. At many locations, air quality is failing to meet newly agreed national standards. Local authorities are supplementing national emissions standards with more stringent local requirements. In consequence, existing plant may have to be modified to secure compliance.

A range of technologies is available for improving the performance of existing units. Optimisation of combustion conditions can be a low cost option but the scope is plant and fuel specific. More substantial reductions in emissions may be achieved by flue gas treatment. The costs involved are considerable and problems may be created in the beneficial disposal of large quantities of solid by-products. However, it has been demonstrated that operators of utility scale pulverised coal fired power stations can achieve compliance with the most stringent current emission standards.

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Contents

List of figures 7

List of tables 9

Acronyms and abbreviations 10

1 Introduction 11

2 Power plant and its emissions 12

2.1 Atmospheric emissions 12

2.1.1 C02 12

2.1.2 CO 13

2.1.3 Sulphur oxides 13

2.1.4 Nitrogen oxides 13

2.1.5 NH3 14

2.1.6 Halogens 14

2.1.7 Particulates and trace elements 14

2.2 Solid by-products 15

2.2.1 Mill rejects 15

2.2.2 Ash 16

2.2.3 Other solid by-products 16

3 Review of regulations and standards 17

3.1 S02 and NOx emission standards 17

3.1.1 National S02 and NOx standards 17

3.1.2 Local control of S02 and NOx emissions 19

3.2 C02 and CO 20

3.3 Particulate emissions 20

3.4 Coal combustion by-products 21

3.5 Continuous emission monitoring 21

3.6 Assessing the effects of abatement measures 22

3.7 Discussion 23

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4 Optimising combustion conditions for the control of S02 and NOx 24

4.1 The fonnation of NOx in utility boilers 24

4.1.1 Thermal NOx fonnation 24

4.1.2 Fuel NOx fonnation 25

4.2 The control of NOx from boilers fired by low-rank coal 25

4.2.1 New brown coal fired boilers in Gennany 27

4.3 The control of NOx from boilers fired by hard coal 27 4.3.1 Boiler tuning 28

4.3.2 Low NOx burners: tangentially-fired systems 29

4.3.3 Low NOx burners: wall-fired systems 30

4.4 Coal pulverising and distribution 32

4.4.1 Coal pulverising 32

4.4.2 Air and coal distribution 32

4.4.3 Coal and air flow: instrumentation and control 34

4.5 Rebuming 35

4.6 S02 control by fuel switching: combustion effects 37

5 Flue gas treatment 39

5.1 Boiler safety: implosion hazard 39

5.2 Control of S02 emissions 40

5.2.1 Flue gas desulphurisation scrubbers 40

5.2.2 Sorbent injection processes 45

5.2.3 Spray dry scrubbers 45

5.3 Control of NOx emissions 46

5.3.1 Selective catalytic reduction (SCR) 46

5.3.2 Selective non catalytic reduction (SNCR) 48

5.3.3 SNCRISCR hybrid systems 50

5.3.4 The relative merits of SCR, SNCR and hybrid systems 51

5.4 Particulates control 52

5.4.1 Electrostatic precipitators: factors affecting their perfonnance 52

5.4.2 Optimising ESPs 54

5.4.3 Wet ESPs 58

5.4.4 Fabric filters: baghouses 59

5.4.5 Flue gas conditioning for fabric filters 60

5.4.6 FGD wet scrubbers and the fortuitous removal of particulates and trace elements 61

6 Residue considerations 63

6.1 FGD by-products 63

6.1.1 FGD gypsum 63

6.1.2 Sorbent injection and spray dry scrubber by-products 64

6.2 Fly ash quality 65

6.2.1 Effects of low NOx burners 65

6.2.2 Effects of SCR and SNCR 65

6.2.3 SCR catalyst 66

7 Conclusions 67

8 References 69

6

5

10

15

20

25

Figures

Carbon monoxide and oxygen concentrations in a boiler stack 13

2 Typical ash distribution 15

3 The relationship between NOx emissions and fuel ratio (VMhhr) x fuel nitrogen 25

4 Residence time as a function of unit capacity 26

The relationship between NOx• CO, excess air at various sections up alSO MWt boiler 26

6 VEAG 800 MWe boiler 27

7 Comparison of plan views of conventional and concentric tangential firing systems 30

8 Babcock S-type burner 31

9 Babcock dual register burner 30

DRB-XCUM low NOx burner 31

II MIT-RSFC low NOx burner 32

12 PC flow control: adjustable orifice 33

13 Predicted stoichiometric ratio (SR) versus actual SR before and after training for a low NOx burner 35

14 Typical reburning installation on a wall-fired boiler 36

Gas reburning on Cherokee unit 3 36

16 Fuel trip transient before installation of a wet scrubber 39

17 Fuel trip transient after installation of a wet scrubber 39

18 Flow diagram of a recent type of wet lime/limestone wet scrubber system 40

19 Utilisation characteristics for normally and finely ground limestone 42

Teruel FGD: absorber configuration 43

21 DCFS configuration diagram 44

22 In-stack wet scrubber system 44

23 S03 concentration from boiler to stack - bituminous coal firing 47

24 High dust SCR arrangement at Heilbronn Unit 7 48

Montaup Electric: full load NH3 slip versus NOx reduction 49

26 PSE&G Mercer in-duct SCR and SNCR test locations 50

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27 Particle charging and collection within an ESP 52

28 a) Effect of resistivity on precipitator size

29 a) Effect of particle size distribution on precipitator size

b) Effect of cohesivity factor on precipitator size 53

b) Effect of particulate space charge on precipitator size 54

30 Equilibrium between S03 and H2S04 versus temperature 55

3I Automatic S03 trim control 56

32 ESP power supply system 57

33 Coal-fired boiler with wet ESP: process units 59

34 Schematic arrangement of a reverse-air filter 59

35 Example of a particle charging baghouse 60

36 Capital costs of conventional and electrica]]y enhanced baghouses 61

37 Yearly operating costs of conventional and electrica]]y enhanced baghouses 61

38 FGD gypsum production in Germany 64

39 Ammonia concentration in the air inside a confined room after pouring a concrete tloor 66

8

Tables

Corinair90: Air emission estimates in Europe - summary of results 12

2 Classification of elements by relative enrichment factor 15

3 Kema classification of elements 15

4 Ceilings and reduction targets for overall emissions of S02 from existing plants 18

5 Ceilings and reduction targets for overall emissions of NOx from existing plants 18

6 Proposed NO x emission limits for Phase II 19

7 US CAAA 1990: classification and attainment dates for 1989 ozone non-attainment areas 20

8 National and regional criteria for CEM 22

9 S02 and NOx CEM requirements 22

10 Performance test results at Hemweg 28

11 Caballo Rojo Powder River Basin coal: analyses 37

12 Total FGD orders in the USA (Institute of Clean Air Companies) 41

13 Performance data for Konin wet FGD 45

14 LIMB system: S02 removal efficiency 45

15 Results from performance tests at Fynsvrerket, Denmark 46

16 SCR plant: specification and technical data 49

17 SNCR ammonia slip measurements at Salem Harbour No 2 during a load reduction 50

18 Advantages and disadvantages of flue gas NOx reduction systems 51

19 Experimental results of narrow pulse energisation tests: industrial ESP 58

20 Breakdown by method of power station desulphurisation capacity (post-combustion measures) 63

9

Acronyms and abbreviations

A/C BACT CAA CAAA CCBS CEM CLR COHPAC CR DAHS EMEP EPRI ESP FGD HHV ID IIASA MCR mmd MWe MWt NAAQS NOx NSPS OFA PC PlB PM PM2.5 PMlo RACT RAINS SCA SCR stp TR TSP UN/ECE VOC

Air to cloth Best available control technology Clean Air Act (USA) Clean Air Act Amendments (USA) Coal combustion by-products Continuous emission monitoring Current limiting reactor Compact hybrid filter Control rectifiers Data acquisition and handling system European Monitoring and Evaluation Programme Electric Power Research Institute (USA) Electrostatic precipitator Flue gas desulphurisation Higher heating value Induced draft International Institute for Applied Systems Analysis Maximum continuous rating Mass median diameter Output MW electrical Input MW thermal National Ambient Air Quality Standard (USA) NO and N02 New Source Performance Standards (USA) Overfire air Pulverised coal Pulse jet baghouse Particulate matter Particulate matter less than 2.5 11m in diameter Particulate matter less than 10 11m in diameter Reasonably achievable control technology (USA) Regional Acidification Information and Simulation Specific collection area Selective catalytic reduction standard temperature and pressure Transformer/rectifier Total suspended particulates United Nations Economic Commission for Europe Volatile organic compound(s)

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1 Introduction

This report is concerned with optimising the control of atmospheric emissions from existing, utility scale, pulverised coal-fired boilers. The combustion of fossil fuel results inevitably in the production of C02 and water vapour. Other by-products arise from elements fortuitously present in the fuel, from incomplete combustion and from unwanted reactions between oxygen and nitrogen. In optimising the control of emissions to the atmosphere, due regard has to be paid to the effects on the quantity and properties of solid coal combustion by-products. The major by-products from coal combustion are described in Chapter 2. Solids marketing and disposal considerations are discussed in Chapter 6.

Regulations governing emissions from utility boilers are aimed to address global, regional and local issues of air quality. At many locations, ambient air quality fails to meet national standards and the local authorities are required to secure improvements. National emission standards are supplemented by provision for more stringent local requirements. In consequence, utilities may be required to reduce emissions because factors outside their control have caused a deterioration of air quality.

Utilities usually have a range of options for improving emissions control. For units that have only a limited life, capital cost may be a decisive factor. For units with longer life expectancy, the choice of pollution control technology can be more difficult. In many cases, new standards are obliging utilities to modify existing plant and it is possible that further tightening of standards may make newly installed control equipment obsolete. Where practicable it may be prudent to select upgrade options that provide a route to further upgrading. This report describes a number of options that have given immediate improvements and can provide a basis for securing further improvements.

The reduction of emissions is discussed starting with the least

costly options involving relatively simple changes in combustion control and operating practice. The potential for controlling S02 emissions from pulverised coal (PC) boilers by combustion modifications is limited but the option of switching to a low sulphur coal may in itself require combustion modifications. Utilities have reported significant reductions of NOx emissions, sufficient to secure compliance with current legislation, by optimising the operation of existing equipment. Further primary measures, involving more substantial modifications and/or the fitting of new equipment, are considered next.

Apart from fuel switching in the USA, flue gas desulphurisation is the most widely used means for reducing S02 emissions. The main desulphurisation technologies are discussed in Chapter 5. The technology of the dominant wet limestone/gypsum process is developing rapidly. For plants already equipped with wet scrubbers performance optimisation may increase removal efficiency with a modest increase in costs. For plants that need to retrofit wet scrubbers, recent designs are more compact and offer reduced capital and operating costs. Spray dry scrubbers have also been used at some locations but the marketability of their solid product is questionable. Selective catalytic reduction, the ultimate and also the most expensive technology for NOx reduction, is considered next with selective non catalytic reduction and hybrid processes. The final sections of Chapter 5 are concerned with the control of the emissions of particulates. The operation of dust control equipment may be affected both by tighter emissions standards and by the consequential effects of measures to control non particulate emissions. The pollution control equipment used at a power station can also affect the quantity and quality of the solid by-products produced. Some of the implications for the disposal and beneficial use of residues are discussed in Chapter 6.

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2 Power plant and its emissions

Emissions from coal-fired boilers vary considerably depending on the properties of the coal. the type of boiler and the emissions control equipment fitted. The combustion process leads inevitably to the production of COz and water vapour but other by-products result from impurities present in the coal, from incomplete combustion and from unwanted reactions between oxygen and nitrogen.

2.1 Atmospheric emissions

The flue gas from coal-fired boilers consists mainly of Nz, HzO and COz. Depending on the analysis of the coal, combustion conditions and the abatement equipment fitted, they may also emit SOz, S03, NO, NOz, CO, HCl and NH3 together with a range of trace emissions.

Corinair, a part of the 1985-90 EC 'CaRINE' research programme, fumished the results presented in Table I for the aggregate emission levels of various pollutants in

29 European countries (the 15 countries of the ED plus Norway, Switzerland, Bulgaria, Croatia, Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta, Poland, Romania, Slovakia and Slovenia).

Power generation using fossil fuels is the major source of anthropogenic COz in the atmosphere and the major source of SOz although other sources are also important.

2.1.1 C02

The carbon content of the spectrum of fossil fuels known as coal ranges from approximately 60% to more than 90% by weight of the combustible matter. Hence COz is the major combustion product by weight and its production is inseparable from the process of generating heat by burning coal. A 500 MWe power station buming coal with a HHV of 27.9 MJ/kg at an efficiency of 34% HHV would consume around 1.3 million tonnes of coal per year and, assuming

Table 1 Corinair90: Air emission estimates in Europe - summary of results (From data presented in EEA Annual Report, 1995)

Europe (29 countries)

Source categories Emissions in kilotonnes

S02 NO, as N02 VOC

Public power, cogeneration and district heating

Commercial, institutional and residential combustion Industrial combustion Production processes

Extraction and distribution of fossil fuels Solvent use

Road transport

Other mobile sources and machinery Waste treatment and disposal Agriculture

Nature

15.017 3,065 7,041

924 45 0

725 571

89 I

573

3,768 759

2,457 393

82 I

7,874 2.331

241 50 50

55 989 154

1,220 1,376 4,920 6,766

677 506 759

4,347

1,331,956 849,641

J,141,187 179,916 27,048

379 695,497 138,733 83,173 22,450

294,779

Total 28,051 18,006 21,770 4,764,759

-~----_._--

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Power plant and its emissions

60% carbon content, would produce around 2.9 million tonnes of C02 per year. Low rank coals have a lower carbon to hydrogen ratio than bituminous coals but the specific C02 emissions of power stations fuelled by low rank coals tend to be higher because of lower overall efficiency. If the power station efficiency of 34% HHV, which is typical for existing coal-fired power stations using bituminous coals, were generally increased to the 42% HHV efficiency attained by existing state of the art PC power stations, C02 emissions would be reduced by 19%. At reunification, Germany inherited a legacy of brown coal fired power stations with efficiencies around 32% LHV (-30% HHV). As a part of their programme for reducing C02 emissions some of these are being shut down and they are upgrading the efficiency of the remaining stations to more than 35% LHV (over 33% HHV) (Eitz, 1995).

Increasing thermal efficiency is currently the only financially feasible route to reduced C02 emissions at a given rate of power generation. Several technologies have been developed for the capture of C02 but, at present, economics are a considerable disincentive to their deployment (see Riemer, 1993; Smith and Thambimuthu, 1991).

2.1.2 CO

Historically, emissions of CO from efficiently operated PC boilers were considered negligible. Combustion of carbon to form CO yields 7831 calories/g. The combustion of CO to C02 yields a further 2415 calories/g. The presence of CO in flue gas indicates inefficient combustion incurring a loss of chemical energy. The presence of CO may also indicate the existence of local zones within the boiler with a reducing atmosphere. This can adversely affect boiler availability by promoting corrosion. Hence, it is normal practice to ensure conversion of CO to C02 by supplying the boiler with a greater than stoichiometric ratio of air to fuel; around 20% excess air which leaves around 4% of 02 in the dry flue gas. Figure I shows the relationship between carbon monoxide and oxygen in the flue gas from a 100 MWe, corner fired burner burning pulverised bituminous coal (Levy and others, 1993).

300

E 200 0. 0.

o ()

100

Economiser 0", %

Figure 1 Carbon monoxide and oxygen concentrations in a boiler stack (Levy and others, 1993)

Paradoxically, emission control measures can increase CO emissions. The control of NOx emissions by primary measures generally involves minimising excess air and reducing combustion temperatures. Both of these can lead to increased CO emissions. The optimum burner zone stoichiometry for several large brown coal fired boilers was found to be approximately 0.8. This gave NOx concentrations of around 100 mg/m3 but also lead to excessive CO formation. A higher air to fuel ratio (-0.95) gave NOx emissions that were still within the legal requirements «200 mg/m3) with CO emissions of the order of 100 mg/m3

(Reidick, 1993).

2.1.3 Sulphur oxides

Burning most coals converts their sulphur content to S02 and S03. Generally, if no FGD is provided, 90% or more of the sulphur originally present is emitted to the atmosphere as sulphur oxides. If a coal contains I% sulphur and has a HHV of 29 MJ/kg uncontrolled emissions of S02 of around 700 g/MJ would be expected. By this calculation, a 'compliance coal,' to meet the US Phase I average sulphur emission limit of 500 mg/MJ without other measures, must have a sulphur content of 0.7% or less. To meet the 400 mg/m3 (-140 mg/MJ) standard applying in much of continental Europe, the sulphur content would have to be around 0.2%. However, some coals give lower than expected sulphur emissions because they contain appreciable concentrations of alkaline earth metals. Some 'natural desulphurisation' may occur if such coals are burned at relatively low furnace temperatures or if there is sufficient contact between the ash and the flue gas at lower temperatures. The fly ash from British coals has typically been found to contain 12-18% of the sulphur originally present in the coal in the form of sulphates (Kang and others, 1994). For a power station firing Greek lignite with a sulphur content of 0.42-0.6%, the S02 concentration in the flue gas was 120-170 ppm. On the basis of the sulphur content, an uncontrolled S02 content of around 230 ppm would have been expected. The lignite yielded around 18% ash and the ash had a calcium content (expressed as CaO) of around 35% (Kakaras and others, 1991).

Most of the sulphur in the flue gas is present as S02. The formation of S03 in a boiler is complex and is believed to occur through the oxidation of S02 by molecular oxygen, oxidation of S02 in the flame by atomic oxygen and catalytic oxidation of S02. Generally the ratio of S02:S03 in combustion gas is in the range 20: I to 30: 1 (Singer, 1991). Treatment of the flue gas by selective catalytic reduction, to reduce NOx emissions, may also catalyse the conversion of S02 to S03 (see Section 5.3.1).

2.1.4 Nitrogen oxides

Various nitrogen oxides are produced during combustion. Environmental regulations are usually expressed in terms of NOx emissions with NOx defined as NO + N02. For measurement and control purposes, it is conventional to express NOx concentrations on the assumption that 'x' = 2 (ie NO is assayed as N02). In common with internal combustion engines, the mixture actually produced by PC

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boilers consists predominantly of NO and contains only around 10% of NOz. The oxidation of NO to NOz in the gas phase is second order in NO involving the formation of a transient dimer (NOh that subsequently collides with an oxygen molecule.

2NO~(NOh

(NOh + Oz ~ NZ04 ~ 2NOz

Hence, the oxidation of NO in dilute form in the atmosphere is a slow process (Schriver and others, 1994). Small amounts of NzO are also produced but, for PC utility boilers concentrations are normally less than 20 mg/m3 (Hjalmarsson, 1992).

The concentration of NOx in the flue gas is affected by boiler design and operating conditions as well as by the nature of the coal. Combustion of coal generates NOx by high temperature reactions between oxygen and nitrogen in the air and in the coal. In uncontrolled combustion, around 80% of the NOx originates from the nitrogen in the coal (Stultz and Kitto, 1992a).

Existing PC-fired boiler furnaces may be classified as:

wall fired, including single wall fired and opposed wall fired: uncontrolled NOx emissions in the range 800-2150 mg/m3; tangentially fired: uncontrolled NOx emissions in the range 310-1200 mg/m3; wet-bottom or slag tap furnaces including cyclone furnaces: uncontrolled NOx emissions in the range 820-1850 mg/m3 (Hjalmarsson, 1990).

These data relate to older PC-fired boilers designed without consideration of the question of NOx control. Suitably designed lignite or brown coal fired boilers achieve primary NOx emissions of less than 200 mg/m3 (see Section 4.2).

2.1.5 NH3

During normal combustion in utility boilers, any NH3 emitted from the coal is burned. However, some processes for controlling NOx involve addition of NH3 to the flue gas (see

Section 5.3) and an ammonia slip can result.

For most countries in Europe the amount of nitrogen emitted as NH3 is of a similar magnitude to the amount emitted as NOx' Emissions of nitrogen as ammonia come mainly from agriculture (>90% for most countries in Europe) (UN/ECE, 1995). In pollution terms NH3 is classified as an acidifying substance because the nitrification of NH3 releases H+ ions. The relative acidifying potency of SOz, NOx and NH3 have been quoted as 0.0313, 0.0217 and 0.0588 respectively (Evers and others, 1995).

2.1.6 Halogens

Chlorine is the most abundant halogen in coal although some coals contain appreciable quantities of fluorine (Davidson, 1996). TIle nornlal range for the contents for the halogens in coal is 50-2000 ppm for chlorine, 20-500 ppm for fluorine,

0.5-90 ppm for bromine and 0.5-15 ppm for iodine. During combustion, it has been estimated that 94% of the chlorine is volatilised, generally being emitted as HCI. Coal can be the major source of atmospheric chlorine (as HC\) in countries that rely on coal for a large percentage of their electricity generation. According to Gibb (1983), the flue gases contain around 80 ppmv for each 0.1 % of chlorine in the coal. An uncontrolled (no FGD), 500 MWe, power station using 0.12% chloride coal would emit about 1300 tiy of HCl (Chow and others, 1992). The fluorine in coal is found in the mineral matter and the type of mineral may affect the emission rate of HF from the combustion zone. When fluorine is present mainly in fluorite, emission of up to 90% of the fluorine as HF can occur. Preliminary work indicates that emissions may be reduced by a factor of ten or more when fluorine is present as fluorapatite. Industrial sources such as aluminium smelters and blast furnaces are thought to be the main sources of fluorine in the environment.

2.1.7 Particulates and trace elements

In developed countries, most PC-fired power stations are fitted with particulate control systems that are more than 99% efficient. The fly ash entering the control equipment consists mainly of small, glassy, spherical particles with diameters ranging from 0.01 to 100 Ilm. Particulate control systems and trace element emissions are discussed further in Section 5.4. TIle emission standards for new large combustion plant in various countries generally require particulate emissions of less than 50 mg/m3 (Soud, 1995). TIlis typically requires more than 99.5% of the particulates to be retained. The material emitted from the stack tends to be finer than the material retained by the control system and may also contain entrained material produced by post combustion treatment of the flue gas (see Section 5.4.6). In addition to the primary particulate mater emitted from the stack, fine particles less than 10 Ilm in diameter (PMIO) are created in the atmosphere by the reactions involving SOz and NOx• However, these are not strictly 'emissions' and control measures are essentially SOz and NOx control.

Eleven elements commonly found in coal are among the 189 substances identified as 'hazardous pollutants' in Title III of the 1990 US CAAA: As, Be, Cd, Co, Cr, Hg, Ni, Mn, Pb, Sb, Se. TIlese elements (or their compounds) are usually present at concentrations of less than 0.01 % of the weight of the coal and are commonly referred to as trace elements (see

Davidson and Clarke, 1996). The ash remaining after combustion generally contains the same elements that were present in the coal but their concentration may be enhanced or reduced depending on conditions in the boiler, the volatility of the elements and their affinity for coal ash. If the affinity of the trace elements for the ash were perfect then the concentration of each element in the ash would be enriched by a factor of 100/(ash content in %). Meij (1994) defined a relative enrichment factor RE such that:

(element concentration in ash) (% ash content in coal)RE = x

(element concentration in coal) 100

A wide range of trace elements in coal can then be assigned to one of three main classes according to their RE factors (see Tables 2 and 3).

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I~----H----------

Based on coal: 10% ash, 27.91 MJ/kg Unit: 500 MW, 10.55 MJ/kWh

Coal Mill Bottom Economiser Cyclone ESPI Stack

ash ash ash baghouse emissionsrejects

Mass, kg/kJ 3.58 0.03 0.72 0.18 2.61 0.02

Mass, % 100.0 1.0 20.0 5.0 73.4 0.6

Flow rate, tlh 19.05 0.19 3.81 0.95 13.98 0.12

Figure 2 Typical ash distribution (Folsom and others, 1986)

Class I elements were defined as those that do not vaporise during combustion. Class II elements vaporise in the boiler but condense before leaving the ESP. Class III elements only condense if the plant is equipped with a wet scrubber. Class I elements are present in the same concentration in all the ash types. Class II elements condense on the surface of ash particles. They can also condense by nucleation of vaporised

Table 2 Classification of elements by relative enrichment factor (Melj, 1994)

Class Bottom ash ESP ash Fly ash Behaviour

I ~\ ~I ~I not volatile IIa <0.7 ~I >4 volatile but

condensing on ash particles within the installation

lIb <0.7 ~I >2 <4 lIc <0.7 ~l >1.3 <2 III «~I «I very volatile

Table 3 Kema classification of elements (Meij, 1994)

Class I (Non volatile) AI, Ca, Ce, Eu, Fe, Hf, K, La, Mg, Sc, Sm, Si, Sr, Th, Ti

Class lIc Ba, Cr, Mn, Na, Rb Class lIb Be, Co, Cu, Ni, P, U, V, W, Class lIa As, Cd, Ge, Mo, Pb, Sb, TI, Zn Class III (Volatile) B, Br, C, CI, F, Hg, 1, N, S, Se

Elements in bold type are US CAAA 1990 'hazardous air pollutants'

material and growth through deposition and coalescence. Since the smallest particles have the largest specific area, the weight distribution of the condensing elements is skewed in favour of the smallest particles. These are found in the final hoppers of the ESP and in the gases emitted from the stack (Meij, 1994). DeVito and others (1994) found that, for a cyclone boiler and a front-fired boiler, the efficiency of col1ection of most of the trace elements was similar to the overall particulate col1ection efficiency. The notable exceptions were Hg and Se with As also showing a somewhat greater emission from the front-fired boiler.

2.2 Solid by-products When coal is burned in a modern PC-fired power station, most of the mineral matter is captured and removed as solid material. Only a small percentage of the mineral matter escapes as fine particulates or as volatile species. Figure 2 shows a typical distribution of solid by-products from a US, pre-NSPS, dry bottom PC boiler without FGD or SCR.

Starting with the receipt of coal into the powerhouse, the first stage in the combustion process involves drying and pulverising the coal. Mill rejects are the first waste stream that is created.

2.2.1 Mill rejects

Mill rejects are produced from vertical spindle mills. Generally, at bituminous coal-fired power stations, the coal is pulverised using either tube mills or vertical spindle mil1s (Scott, 1995). Any material that enters a tube mil1 becomes part of the grinding media until it has been ground

15


sufficiently finely to leave the mill as 'pulverised coal'. Vertical spindle mills feature intemal air classification and the first stage of the classifying process is designed to reject any unusually hard material such as small pieces of tramp iron that might cause impact damage to the grinding surfaces. Coarse particles of dense material such as iron pyrites (FeSz) are also selectively rejected. If the mill is operating within normal parameters the rejects will have a high iron and sulphur content but, since the process is not 100% efficient, an appreciable fine coal content will also be present. The material falls into the pyrite trap at the base of the mill. It is essential that the material is removed efficiently from the pyrite trap because accumulations of material can cause mill fires or explosions through spontaneous combustion. Because of its high pyrite content, this material does not benefit from the favourable treatment usually given to coal combustion by-products; it is classified as a hazardous waste (see

Section 3.4). Under normal operating conditions, the rate of production of mill rejects is small and labour intensive means, such as waste skips, are used to remove the accumulated material from the pyrite hopper. An appreciable increase in the quantity of mill rejects may be an indication of mill malfunction or overloading.

2.2.2 Ash

Typically, around 60-90% of the coal ash from a PC-fired unit with a dry-bottom furnace leaves the boiler with the flue gas (Singer, 1991; Stultz and Kitto, 1992b). The balance of

the ash leaves through the bottom-ash handling system. For older slag-tap furnaces 50-60% of the ash leaves the bottom of the furnace as molten slag (Hjalmarsson, 1990). This proportion can be increased to almost 100% by recycling fly ash to the furnace (Kather and others, 1995).

The major components commonly present in the ash are compounds of aluminium, silicon, and iron with sulphur and oxygen. Some coal ash also contains a significant proportion of alkali and/or alkaline earth metals and, depending on the efficiency of combustion, there will also be some residual carbon content.

2.2.3 Other solid by-products

Flue gas desulphurisation (FGD) systems fitted to utility boilers may generate substantial quantities of solid by-products. The question of disposal of these products can be a deciding factor in the choice of an emissions control technology. FGD systems are efficient in removing SOz from flue gas but they generate large quantities of solid material or aqueous slurry. Typical products are:

FGD gypsum (wet or dry) from forced oxidation operations; scrubber sludge, a mixture of calcium sulphite and calcium sulphate; calcium sulphite from inhibited oxidation operations.

16

3 Review of regulations and standards

Environmental legislation is complex and voluminous. IEA Coal Research, has produced a lengthy handbook which was developed and is now maintained as a database. The handbook is mainly concerned with national emission standards. These standards, designed to address national issues, may be inappropriate at locations with particular pollution problems. Hence, for each country, more exacting local standards can be imposed where necessary.

3.1 502 and NOx emission standards

S02 and NOx emissions became an issue because of the long range effects of these pollutants (UN/ECE, 1995). Governments in Europe, the CIS and North America have engaged in treaties to reduce regional emissions of S02 and NOx' National emission standards and caps on total national emissions have been used in the plans to comply with these treaties. Local emission standards are usually justified by some form of assessment of the effect of a local emission source on local air quality standards.

3.1.1 National 502 and NOx standards

Two major strategies have been identified for the control of national emissions: the 'command and control' approach and the 'market orientated' approach.

In the EU the command and control approach has been widely used. The ceilings and reductions defined for S02 and NO x emissions from various countries in the EU are summarised in Tables 4 and 5.

The basis of EU policy in terms of S02 and NOx emissions is the Directive on the Limitation of Pollutants Emitted by Large Combustion Plants which was approved by the Council of Ministers in 1988 (COM 88/609/EEC). The Directive applies to combustion plants having a thermal input greater

than 50 MWt. New plants using solid fuel and with an input greater than 500 MWt, (ie most new utility power station boilers) are required to control S02 emissions below 400 mg/m3 and NOx emissions below 650 mg/m3 (all figures at 6% 02). Exceptions are made for new plants burning high sulphur indigenous solid fuel. A percentage sulphur removal is stipulated for such plants depending on thermal input. This increases from a minimum of 40% removal for a 100 MWt plant to a minimum of 85% removal for plants over 500 MWt.

In practice, a number of EU countries have chosen to enact national standards that are considerably more severe than the EU limits. For new utility scale power stations, NOx

emissions are generally required to be below 200 mg/m3 and S02 emissions below 400 mg/m 3. A significant proportion also insisted that existing plants should be upgraded to meet, at least, those standards. Among the countries that required plants to be upgraded are: Austria, Belgium, France (S02 only), Germany, Italy, the Netherlands, and Sweden. Sweden is also using taxation as a means for promoting the reduction of NOx emissions. At the beginning of 1992, a tax of 40 SEK/kg (US$ 3/1b) was levied on the two hundred or so plants that had an input of at least 10 MWt and generated more than 50 GWh per year. From January 1996 the scope of the tax was widened to include all plants with annual production >40 GWh, regardless of input, and from January 1997 it was further extended to plants >25 GWh. If a plant lacks the capability to monitor its NOx emissions to the accuracy demanded by Swedish regulations a rate of 250 mg/MJ (-715 mg/m3) is assumed. This rate is sufficiently high to provide the incentive to acquire the necessary continuous monitoring capability. The total sum collected is redistributed to the power generators proportionately to the amount of power each has generated. Hence, units that produce electricity at a lower than average NOx rate receive a tax credit and producers that have higher than average emissions receive an invoice (Hjalmarsson, 1996; Svedberg, 1995). Similarly, Sweden also has a tax

17

Review of regulations and standards

Table 4 Ceilings and reduction targets for overall emissions of 502 from existing plants (Boucher, 1990)

Member State S02 Emissions ceiling (ktonnes/year) % change from 1980 emissions emissions ktly, 1980 Phase I Phase II Phase III Phase I Phase II Phase III

1993 1998 2003 1993 1998 2003

Belgium 530 318 212 159 -40 -60 -70 Denmark 323 213 141 106 -34 -56 -67 Germany 2,225 1,335 890 668 -40 -60 -70 Greece 303 320 320 320 5 6 +6 Spain 2,290 2,290 1,730 1,440 0 -24 -37 France 1,910 1,146 764 573 -40 -60 -70 Ireland 99 124 124 124 25 25 +25 Italy 2,450 1,800 1,500 900 -27 -39 -63 Luxemburg 3 1.8 1.5 1.5 -40 -50 -50 The Netherlands 299 180 120 90 -40 -60 -70 Portugal 115 232 270 206 102 135 +79 United Kingdom 3,883 3,106 2,330 1,553 -20 -40 -60

Table 5 Ceilings and reduction targets for overall emissions of NOx from existing plants (Boucher, 1990)

Member State NO, Emissions ceiling (ktonnes/year) % change from 1980 emissions

Belgium Denmark Germany Greece Spain France Ireland Italy Luxemburg The Netherlands Portugal United Kingdom

emissions kt/y, 1980

110 124 870 36 366 400 28 580 3 122 23 1,016

Phase I 1993

88 121 696 70 368 320 50 570 2.4 98 59 864

Phase II 1998

66 81 522 70 277 240 50 428 1.8 73 64 712

Phase I Phase II 1993 1998

-20 -40 -3 -35 -20 -40 +94 +94 +1 -24 -20 -40 +79 +79 -2 -26 -20 -40 -20 -40 +157 +178 -15 -30

based on the sulphur content of the fuel. The presentation of convincing data proving that actual emissions were less than the sulphur content of the fuel qualifies the owners for a tax refund. De facto standards may also be introduced by private agreements. For example, the Dutch Electricity Generating Board has entered into a covenant to reduce S02 and NOx emissions by 90% and 60% respectively (van der Kooij, 1994).

In the USA, the goals of the acid rain control programme are a 10 million tons per year reduction in S02 emissions (to about 50% of 1980 levels) and a two million tons per year reduction in NOx emissions. It was planned to accomplish the reduction of S02 emissions in two phases. Phase I of their CAAA 1990 involved the 110 utility plants in 21 states in the eastern USA with the greatest S02 emission. They were allocated tradeable emissions allowances based on historic emissions. For Phase I the average S02 allowance allocation level was set at I. I g/MJ of energy input based on the higher heating value of the coal (2.5 Ib of S02 per million Btu). For Phase II, which comes into force in the year 2000, approximately 2300 electricity generating units with capacities of 25 MWe or greater are involved. The average

emission allowance level will be 0.5 g/MJ (1.2 Ib/million Btu) (Keeth and others, 1995). However, where there is a commitment to install FGD scrubbers, the deadline for Phase I compliance is extended from 1995 to 1997 and units that commit to use a specific clean coal technology can obtain a deferment of Phase II implementation to December 2003. A total reduction of 2 Mt/y in comparison with 1980 NOx emissions was required by I January 1995. This represented a 25% reduction in total emissions of which coal-based power generation accounted for about one third.

Hence a market-based approach was adopted for the control of overall S02 emissions. The philosophy behind the market approach is that, provided a sufficient degree of freedom is allowed, market forces will direct operators to the least cost solution for a given problem. Utilities may exceed the average S02 emission level at some units if they achieve lower than average emissions at their other units and thereby avoid exceeding the sum of their S02 allowances. If the utilities involved wish to install additional generating capacity they will either have to reduce the emissions from existing capacity or purchase more allowances. A market in

18


allowances was created by permitting utilities that do not use all of their allowances to sell the excess to other utilities or to retain them for use in subsequent years. The US Environmental Protection Agency (US EPA) also administers a reserve of allowances that are saleable at a maximum price of $1500 each (Schorr, 1992). However, this maximum has proved to be of theoretical interest only; market prices for emission allowances are an order of magnitude lower.

The units affected in Phase I by the requirement to reduce S02 emissions were also required to observe NOx emission limits. The limits were different for different types of boiler. After 1 January 1995 it became iIlegal for the affected boilers to emit more than the prescribed amounts of NOx:

0.45 Ib/miIlion Btu for tangentially-fired boilers (554 mg/m-'); 0.50 Ib/million Btu (615 mg/m-') for dry bottom wall-fired boilers (other than units applying cell burner technology)

It was envisaged that these limits would be met by using low NOx burners but a number of options were offered. If they so wished, a utility might choose to average the emission rates of two or more boilers and over comply at units where it is technically easier and less expensive to do so. Provision was also made that a higher rate might be set for any type of utility boiler if it is found that the maximum listed rate for that type of boiler cannot be met by low NOx burner technology. However, the setting of a higher limit would have to be based on evidence that the control equipment was properly designed, installed, and operated during a demonstration period (US EPA, 1996a). For future reductions in NOx emissions Title IV also provided that, not later than January 1997, the EPA should establish annual emissions limitations which were more stringent if the EPA believes that more effective low NOx burner technology is available. The EPA found that all of the 33 boilers that were identified as having been fitted with simple low NOx burners had met the emission standards (US EPA, 1996b). Based on analysis of information on low NOx burner installations to date the EPA has published the proposed emission limits shown in Table 6.

The 1990 CAAA suggests that the upgrading of existing

Table 6 Proposed NOx emission limits for Phase II (US EPA, 1996b)

Boiler types Number of boilers Proposed Phase II involved emission limits

lb/106 Btu mg/m'

Group 1 Dry bottom wall-fired 284 0.45 554 Tangential 296 0.38 467 Group 2 Cell burners 35 0.68 836 Cyclones 88 0.94 1156 Wet bottom wall-fired 38 0.86 1058 Vertically-fired 29 0.80 984 Fluidised bed combustors 5 0.29 357

boilers should be based on the installation of low NOx burners - hence, in this context low NOx burners are defined as reasonably available control technology (RACT). However, there appears to be some disagreement whether further NOx reduction by the provision of overfire air (the injection of secondary air above the burners) should also be required (Harrison, 1993). The US EPA has delegated this decision to the states. Some have decided that RACT is satisfied by the installation of low NOx burners, others have specified low NOx burners in conjunction with overfire air (Siegel and Kalagnanam, 1995).

3.1.2 Local control of 502 and NOx emissions

The rationale for separate local emission standards is based on the requirement to secure acceptable air quality in the locality. Local air quality depends on a balance between pollution entering from outside the area, the sum of emissions within the area and the dispersion of pollution to other areas. The latter may be heavily dependent on meteorological conditions. In a UK DOE draft document, it was noted that the highest peaks of S02 concentrations observed in the UK are mainly caused by plumes from large combustion plants that occasionally reach ground level during particular meteorological conditions. In consequence, these large S02 sources can contribute significantly to episodic high concentrations. UK legislation requires that plant operators use the 'best practical means not entailing excessive cost' (BATNEEC) to control pollution. The plant operator should select the combination of primary process, pollution abatement and waste treatment and disposal which constitutes the best practical environmental option minimising the pollution that may be caused to the environment as a whole. Authorisations to operate large combustion plant are given on a plant by plant basis following discussions between plant operators and the authorities (Soud, 1991). In recognition of the new perception of the effects of stack plumes on local air quality, authorisations under the UK's Integrated PoJ]ution Control regulations may be revised (UK DOE, 1996).

The US EPA has set National Air Quality Standards for six principal poJ]utants: Ozone, S02, N02, CO, particulates (PM 10), and lead. Air quality standards of significance to power utilities are:

S02 <365 Ilg/m-' (24-hour average), <1.3 mg/m-' (3 hour average); Ozone < 0.121 ppm (I hour average); CO <9.1 Ilg/m-' (8-hour average), 35 mg/m-' (l hour average); PM,o <150 Ilg/m-' (24-hour average), 50 Ilg/m-' annual average.

Ambient N02 concentrations are generally satisfactory and declining in terms of the direct effect of N02 on air quality. In practice, ozone has proved to be the air pollutant that is the commonest cause of exceedance of air quality standards and is the main justification for the tighter control of NOx emissions. In the USA there is a five-tier classification for

19


Table 7 US CAAA 1990: classification and attainment dates for 1989 ozone non-attainment areas (Government Institutes Inc, 1991)

Area class Design value, Primary standard ppb(v) attainment date

Marginal 121-138 3 years after enactment Moderate 138-160 6 years after enactment Serious 160-180 9 years after enactment Severe 180-280 15 years after enactment Extreme 280 and above 20 years after enactment

Design value is based on the fourth highest one hour ozone concentration measured at a site over a three year period. The primary standard is 120 ppb(v)

ozone non-attainment areas. The higher the level of pollution the greater the time allowed to achieve compliance up to a maximum of 20 years (see Table 7).

Approximately 100 urban areas fail to comply with the federal air quality standard for ozone. In addition to these, areas that contribute to the ozone loading of downwind urban areas (ozone transport regions), are also designated non-attainment areas. Hence, the II eastern states north of Virginia plus the Washington, DC, metropolitan area are considered non-attainment areas (Schorr, 1992). The normal approach adopted by the states in formulating air quality management plans is to examine an episode of high ozone concentrations which spanned several days and determine how much the VOC and NOx emissions would have had to be reduced to lower the one hour ozone maximum to 120 ppb. In making this assessment the prevailing meteorological conditions have to be taken into account and, in order to use the assessment for forward planning, projections have to be made of the emissions inventory in future years (Kuklin and Seinfield, 1995). Large reductions of the emissions of both NOx and VOC over a wide area may be expected to reduce ozone concentrations but the effect of controlling NOx alone can be difficult to predict. The legislation reflects this uncertainty:

For moderate non-attainment areas, the requirement to achieve acceptable air quality is based on the control of VOC (including CO). The state has to submit an implementation plan to reduce VOC emissions 15% below the 1990 level by 1996.The plan has to provide for such specific annual reductions in emissions of VOC and NOx as are necessary to attain the required air quality standard by the attainment date. In execution of its implementation plan the state may require utilities to usc RACT for the control of NOx;

For serious non-attainment areas, VOC has to be reduced by at least 3% each year unless the State demonstrates to the EPA that this is impracticable. The US EPA is responsible for issuing guidance on the conditions under which NOx control can be substituted for VOC contro\' or may be combined with VOC control, in order to maximise the reduction in ozone air pollution (CAAA 1990 Title I, Part B, Sec.182 (c) (2) (C». For extreme non-attainment areas, Sec.182 (e) (3)

appears to require that by 1998 NOx emissions from utility coal-fired boilers should be controlled either by the use of SCR, or other comparably effective control technologies or by switching to natural gas.

The tasks set for utilities in achieving specified overall reductions in S02 and NOx emissions are essentially quantifiable. Requirements based on local ambient air quality are more problematic because air quality is affected by many factors outside the control of utilities. A deterioration of air quality, or a redefinition of 'acceptable' air quality may lead to a sudden tightening of emission standards (see Section 3.3).

3.2 C02 and CO There do not appear to be any standards relating to the emission of C02. Taxes have been proposed, and have been implemented at some locations, but at the time of writing of this report no general consensus has been achieved on the global issue of C02 emissions.

As discussed in Section 2.1.2 the control of CO emissions has been motivated primarily by considerations of thermal efficiency and boiler availability. Usually standards for CO emissions are set in a more general industrial context and pose few problems for utility boilers. Victoria, Australia, has a CO emission limit of 2500 mg/m3 (a reduction to 1000 mg/m3 has been proposed). Germany has a limit of 250 mg/m3 for power plants with a thermal capacity in excess of 50 MWt (lEA Coal Research, 1997a).

In future, CO emissions may be regulated because of their direct and indirect contribution to the exceedance of ambient air quality standards. Where air quality standards for CO or ozone are exceeded, and where power plants make a significant contribution to the problem, there may be a requirement to reduce CO emissions as far as is practicable. In the USA a moderate CO non-attainment area is defined as having an ambient air CO concentration of 9.6-16.4 ppm (-19.7-33.7 mg/m3). The UK Expert Panel on Air Quality Standards recommended that the maximum CO content of ambient air should be 10 ppm based on a running 8-hour average calculated from hourly measurements (UK DOE, 1994). The UK DOE report found that power stations only accounted for I % of anthropogenic CO emissions with motor vehicles accounting for 89%. However, as discussed in Section 3.1.2, a boiler stack plume can have an appreciable effect on episodes of poor local air quality.

3.3 Particulate emissions Throughout the OECD countries there are regulations to limit particulate emissions from the stacks of large power stations. There are various guidelines and limits for emissions (see Soud, 1991) but generally levels appear to be of the order of 40-65 mg/m3. Where it is considered appropriate, local limits may be more stringent. For example, coal-fired power stations in the vicinity of large cities in Japan are required to have emissions below 10 mg/m3. This results in a stack with virtually no visible emission (Fujishima and Tsuchiya, 1993).

20


The emphasis on the nature of particulate emissions is changing. Standards were originally designed to avoid the nuisance of dirt and grit deposition downwind of the stack. They are now being modified to reflect a greater current concern with the effects of fine particles that remain suspended in the air. The acceptability or otherwise of a given rate of emission may be determined by local air quality. Currently, air quality standards for particulate matter are usually expressed in terms of PM 10 (particulate matter less than 10 11m in diameter) but there is growing concern about the effects of particles below 2.5Ilm. The USA has a 24-hour PM 10 standard of 150 Ilg/m3 and an annual 24-hour standard of 50 Ilg/m3. The US EPA proposes 'to revise the current suite ofPMIO standards by adding two new primary PM2.5 standards set at 15 !lglm3, annual arithmetic mean, and 50 Ilglm3, 24-hour average, to provide increased protection against the health effects found in the community studies' (US EPA, 1996c). The air quality of 41 counties in 19 states fails to comply with the existing PMIO standards. Under the proposed standards it is estimated that the air quality of approximately 170 counties in 36 states would be out of compliance (US EPA, 1996d).

3.4 Coal combustion by-products The operation of a coal-fired power station inevitably involves the production of large tonnages of solid by products. Dumping is widely practised in the USA where the most important by-products from PC combustion (in terms of tonnage) have been classified as non-hazardous coal combustion by-products (CCBs). In consequence, CCBs are currently exempt from federal hazardous waste regulation but they are also regulated under state law. Most states regulate CCBs as solid waste but several regulate it as hazardous (Jagiella, 1994). The situation is further complicated because US federal legislation appears to allow the possibility of action against 'responsible parties' if the 'non-hazardous' material is subsequently found to be releasing, or 'threatening to release', any hazardous substance (Gorton III and Keller, 1995).

Disposal regulations are stringent at some locations in Europe because of their local problems. For example, groundwater is a major source of drinking water in the Netherlands and this valuable rcsource is vulnerable to contamination because of the high water table. The Dutch government has prohibited the dumping of fly ash and gypsum as part of a policy to encourage reuse and recycling. All of the local production of these by-products is used as construction material (Clarke, 1994; van der Kooij, 1997).

Some countries allow the disposal of coal combustion by-products at landfill sites under strictly specified conditions. However, there appears to be a growing antipathy to the dumping of waste in general. Waste disposal costs are bei~g inflated by fiscal measures. In Denmark there is an excise duty of DKr 195/t on waste delivered to landfill sites. In France, an escalating tax has been imposed with the objective of phasing out all traditional refuse dumps by the year 2002 (OECD, 1996). In the UK, waste disposal was not subject to any special taxation until 1 October 1996. From I October, non-toxic waste attracts a tax of £7/t which will

almost double current gate fees of around £8/t. A special tax rate of £2/t has been agreed for fly ash, FGD gypsum and most other coal combustion by-products (UK Coal Review, 1996). Under the terms of the tax, the landfill operators can donate up to 20% of the tax gathered to 'green trusts' which will carry out projects including reviving land previously use by landfill sites (Woolf, 1996). However, most of the revenue arising from the tax will be used to offset a £500 million reduction in employers' national insurance contributions. Groups said to have some influence on policy makers in the UK have called for landfill taxes to increase to European levels. The Institute for Public policy has suggested £25/t (Rodgers, 1996).

Disposal to landfill is, at best, an option that will become increasingly expensive and leaves the utility hostage to possible future liabilities. At worst, it is not an option at all. It has been demonstrated that beneficial uses can be found for the solid by-products of coal combustion if local regulations provide the imperative.

3.5 Continuous emission monitoring In the past, marginally competent pollution control equipment could demonstrate acceptable performance under ideal conditions (steady state operation immediately following overhaul, etc). Continuous emissions monitoring (CEM) provides data during transient and off design operating conditions. Typical flue gas components whose monitoring is required include NOx, S02, CO and particulates. The requirement for CEM may be either explicit, a statutory requirement to install CEM, or implicit, a requirement to demonstrate that emission standards are being met by collecting data on an hour to hour basis. Similarly, fiscal measures, with fees based on actual emissions or an assumed high rate of emission in the absence of reliable data, may impose an implicit requirement for CEM (see Section 3.1.1). CEM may also be used to provide the data for optimising and controlling emissions abatement equipment. Typical requirements for continuous monitoring in European countries are listed in Table 8.

Regulations in the USA, following the CAAA 1990, initiated a sweeping change in the approach to emissions monitoring. Under Title V of the act, states are obliged to issue operating permits to significant stationary sources of air pollution. The permits must set out the environmental requirements for the source and indicate clearly how the source is expected to comply. The requirement to monitor NOx and 502 emissions is also stated in the Acid Deposition Control section of the CAAA (Title IV). The EPA will initially be responsible for overseeing the development of the states' permitting systems and ensuring that the requirements of the CAAA are met. 'By 1995, the chimneys of all coal-fired power stations must be fitted with equipment to monitor the average emissions of pollutants over fixed time intervals.' Currently, measurements are required for NOx, 502, C02, opacity (particulates) and total flue gas flow. The regulations have tightened monitoring accuracy requirements and allow authorities to enforce the careful recording of data by the provision of penalti~s for incomplete reporting. Table 9 shows the characteristics required for the monitoring of NOx and 502.

21


Table 8 National and regional criteria for CEM (van der Kooij and others, 1997)

Country Pollutant Criteria

Austria

Belgium France

Germany Ireland Italy

Netherlands Poland

Portugal

Spain Sweden

Switzerland UK

NO" S02, CO, dust NO" S02, dust NO" S02, CO dust NO" S02, CO, dust NO" S02 NO" S02, CO dust NO" S02 NO" S02, dust CO NO, S02 CO NO" S02 NO, S02 HCl, CO Hg, NH3, N20, dust NO" SOl, CO, dust (opacity) NO" SOl

CO

>30 MWt >10 MWt >300 MWt >150 kg/h >5 kg/h yes There will be requirements within 2 years >300 MWt (National law) Regional emissions limits >300 MWt (Regional authorities) National emissions limit values, lower values by local authorities emission limits Local authority requirements 30 kg/h 50 kg/h 100 kg/h Large combustion plants Plants >50 MWe producing >50 GWh/y, local authority fees Peat and coal-fired plants >50 MWe producing >50 GWh/y, taxes Waste incineration plants Some local limits National and regional authorities New plants >50 MWt, existing plants >50 MWt within three years, local limits also exist Some new plant >50 MWt

Table 9 502 and NOx CEM requirements (Mitchell, 1994)

Parameter Previous requirements Acid rain (NSPS) requirements

Relative accuracy 20% 10.0% Daily drift 10% max 5.0% max 7 day drift test 5% max 2.5% max Linearity 15% max 5% Volumetric flow monitor Not required Required Data points per hour 4 4 Monitor availability 80% 95% Data availability 80% 100%

A minimum of four datapoints per hour is required for the hourly measurement to be valid. Under the Acid Rain regulations the points have to be equally spaced over the period.

A data acquisition and handling system (DAHS) is required to provide and store data for all operating hours. Since no system is capable of 100% operation, elaborate missing data routines have to be provided so that any missing or suspect data can be estimated accurately. The DAHS for each CEM must also store a database of 50,000 to 75,000 data points per source per quarter. The DAHS must be fully automated and, in common with the sampling and analysis equipment, must be certified by the EPA.

The US electricity generating industry has spent an estimated $1000 million on CEM equipment and will continue to spend approximately $200 million a year to operate and maintain the equipment (Dene, 1995). The need to provide systems to collect, analyse and record the considerable volume of data

from the CEM equipment imposes an additional burden on utilities and CEM has effectively tightened emissions regulations by highlighting any transient departures from

acceptable performance.

3.6 Assessing the effects of abatement measures

In 1989 the EC Commissioner for the Environment presented

the proposal for establishment of the European Environmental Agency (EEA). At the end of 1994 the EC asked the EEA to prepare a state of the environment report for the EU and to contribute to the review of the fifth environmental action programme (5EAP). The main conclusions of the EEA report are that the EU is making progress towards reducing certain pressures on the environment but this is not enough to improve the general quality of the environment and represents even less progress towards the declared aim of sustainability. The report predicts that the EU will not meet the 5EAP targets for the year 2000. Among the areas where attainment is considered uncertain or

unlikely are: C02, NOx, and VOC emissions. In general, population and economic growth show upward trends translating into more energy use, tourism and, in particular, transport. If these trends cannot be combined with sufficient (and cost effective) abatement measures, further decoupling of economic growth from increased energy use is necessary to secure sustainable development (Wieringa, 1995; EEA, 1996). The EC is reported to have drafted an action plan in response to criticism from the EEA. It is promised that a broader mix of instruments will be used to attain environment targets. Instruments to be used include: better

22

-- --------


enforcement, internalisation of external costs, environmental charges, the application of environmental liability, fiscal reform and a framework for voluntary agreements (Grant, 1996). With regard specifical1y to large combustion plant (LCP), it is reported that 'work is welI advanced on a proposed revision of the 1988 LCP directive'. The draft is said to conclude that attainment of a newly defined 50% gap closure target would require application of FGD or equivalent emissions reductions to LCP in almost alI Member States. Catalytic NOx abatement or equivalent emissions reductions would be needed in all northern Member States except Finland and Luxembourg (Mayer, 1997).

In the USA, new, more stringent air quality targets for ozone and fine particulates are proposed (see Section 3.3). The Ozone Transport Commission is expected to recommend reductions of 'regional' NOx emissions in the course of 1997. The US EPA has presented a number of scenarios for achieving acceptable air quality in the course of the next few decades. Their analyses have indicated that national cap and trading/banking approaches for NOx and S02 emissions could provide emission reductions throughout all regions of the USA. Possibilities considered include a further 50-60% lowering of the cap on global S02 emissions and NOx emission rates to be limited to approximately 200--300 mg/m3 (0.15-0.25 Ib/million Btu). It is anticipated that setting emissions at these levels would facilitate execution of state implementation plans for achieving national air quality standards (US EPA, 1996e).

3.7 Discussion It has been said that two different ideological approaches have been used by OECD countries to safeguard the

environment; the 'command and control' approach adopted by the EC and Japan and the 'market-based' approach developed in the USA (Salvaderi and others, 1993). Three years later, it is becoming apparent that the dichotomy is not so great. In the EU 'there is a widespread commitment to the development ofmarket based instruments where these can provide a more cost-effective alternative to the traditional regulatory command and control means ofachieving environmental objectives' (UK DOE, 1996). In the USA, the market cost of S02 allowances is an order of magnitude lower than the maximum price provided in the legislation. One of the factors identified as having motivated over compliance is the command and control approach of local authorities charged with the duty to improve or maintain local air quality standards. Intensified monitoring of emissions on a site by site basis combined with computer modelling wil1 facilitate the identification of the polIution sources that are degrading air quality at any given location. The commission of assaults on the environment will become more obvious and more attributable. In addition to the legal constraints, fiscal impositions, or less formal expressions of public opinion, may oblige utilities to over comply and to observe standards that are not mandated by legislation.

Increasing emphasis on local air quality standards exposes the limitations of a market approach primarily designed to reduce national emissions. However, as discussed in Section 3.6, this objection might be negated by progressively lowering national emission caps until local requirements are met. Since investment decisions concerning power plant usually involve a time span of several decades, prudence may require utilities to try to predict the likely evolution of legislated and de facto standards or to adopt control technologies with the potentia] for further improvement.

23

4 Optimising combustion conditions for the control of 502 and NOx

Modification of combustion conditions is the primary means for controlling NOx emissions. The scope for the primary control of NOx depends on combustion conditions within the boiler and on the design and configuration of the burners. Various arrangements are used for firing PC in utility scale boilers. For a comprehensive review, the reader is referred to textbooks such as Stultz and Kitto (I 992c). The prospect of reducing emissions from a boiler by optimal use of the existing facilities (boiler tuning) or through minor modifications to boiler auxiliaries is attractive because it promises to be a low cost solution. At greater cost, further reductions in emissions can be obtained by fitting low NOx burners, by the provision of overfire air ports and by facilities for injecting a supplementary 'reburn' fuel. However, costs can escalate considerably if expensive modifications to the boiler are required. Treatment of the t1ue gas by selective catalytic reduction (SCR) is the most effective technology that is available for controlling NOx emissions (see

Section 5.3.1). It is also the most expensive option. Even if SCR is subsequently installed, primary measures to reduce NOx emissions help to reduce the capital and operating costs of the installation.

The most basic method for controlling emissions of S02 from a boiler is by controlling the sulphur content of the fuel. Coal switching or blending of existing supplies with lower sulphur coal has emerged as the most generally used technique for reducing sulphur emissions in the USA. However, much of the commercially available, low sulphur, US coal, is also low rank. The use of a lower rank coal has implications for the coal pulverising and handling systems and for combustion and heat distribution within the boiler.

4.1 The formation of NOx in utility boilers

The mechanisms of NOx formation were reviewed by Hjalmarsson (1990). The nitrogen oxides fornled during

combustion are mainly NO and N02 with NO contributing over 90% of the total NOx. The two main mechanisms are thermal NOx formation and the formation of NOx from nitrogen in the fuel.

4.1.1 Thermal NOx formation

Thermal NOx is formed from nitrogen in the air. Conversion starts at temperatures above I300°C and increases markedly with increasing temperature. There are a number of options that can be used to reduce thermal NOx formation during combustion. These include:

decreasing the combustion temperature in all reaction areas below I300°C and decreasing the furnace heat release rate; decreasing the residence time in high temperature zones; decreasing the excess air and hence lowering the concentration of atomic oxygen in high temperature zones.

The combustion temperature is related to combustion conditions and to the rate of heat exchange. The rate of removal of heat from the furnace may be optimised by keeping the heat exchange surfaces as clean as is practicably possible. Booher (1995) reported the results of optimising cleaning at a number of coal-fired boilers in the USA:

At Dairyland Power's 400 MWe (gross), turbo-fired J P Madgett Station, water lances were installed to reduce the flue gas temperature from the economisers and improve the heat rate. As an additional benefit, NOx

emissions were reduced from around 615 mg/m 3

(0.5 Ib/million Btu) to around 455 mg/m3

(0.37 Ib/million Btu). By Dairyland Power's estimation, this saved a cost of $M 11,000 for the installation of additional equipment to secure compliance; Fourteen water lances were installed at Southwestern Public Service's 345 MWe, tangentially-fired Harrington

24

• •

Optimising combustion conditions for the control of S02 and NOx

Station. The installation was designed to decrease furnace exit gas temperature and increase unit availability. It also resulted in a reduction in NOx emission rate from 615 mg/m3 to 370 mg/m3;

A connection between wall cleanliness and NOx emissions was found for a 235 MW wall-fired unit burning Illinois coal. 'Aggressive sootblower operation' reduced the NOx emission rate from 860 mg/m3 to 680 mg/m3 .

Decreasing the heat release rate may be more difficult. Many older boilers were designed around burners that produced rapid combustion in short intense flames and the boilers are correspondingly compact. The relatively 'lazy' flames ,that result from substoichiometric combustion may give problems with incomplete combustion and flame impingement on the boiler walls. Possible problems arising from such combustion conditions are: Increased CO content in the flue gas and increased carbon content in the ash. Boiler tube wastage may also increase if local reducing conditions are created against the water walls. Hence, the potential for controlling thermal NOx by combustion measures may be limited for older boilers.

4.1.2 Fuel NOx formation

Fuel NOx is formed by oxidation of nitrogen in the fuel but the effect of fuel nitrogen content on NOx emissions is a complex issue. Coals of similar nitrogen content may give quite different NOx yields (Benesch and Schnadt, 1995). Some fuel nitrogen is released during devolatilisation. The remainder of the nitrogen remains in the char and is released at a rate similar to that of char combustion. Fuel NOx formation can be reduced by:

promoting devolatilisation in zones of high temperature and low stoichiometry; further decreasing combustion temperature; decreasing oxygen partial pressure; choosing a fuel with a lower nitrogen content.

As coal particles enter a boiler furnace, their surface temperature increases rapidly due to radiative and convective heat transfer from boiler gases and other burning particles. The coal is heated at a rate of approximately 105 eC/s to a temperature of over 1400eC. Various authors report that the volatiles emissions during rapid heating are in the range 1.1 to 1.8 times greater than those predicted by proximate analysis (Knill and others, 1990; Hindmarsh and others, 1993). Jones and others (1995a) found that the ratio between volatile matter yield determined by rapid heating and standard volatile matter yield was different for each of the coals tested and was in the range 1.31-1.791 I. For all the coals, with the equipment used, NOx tended towards a minimum, in the range 300---400 mg/m3, as air staging was increased.

For uncontrolled boilers, substantial differences in NOx emissions have been observed when the coal being fired was changed or blended with other coals but two units with low NOx burners were found to be insensitive to fuel properties. Some manufacturers of low NOx burners claim that their

burners are insensitive to some fuel properties, such as fuel ratio (fixed carbon/volatile matter ratio) while others report significant sensitivity (Wildman and Smouse, 1995). Jones and others (1995a) investigated the effect of coal quality on NOx and unburnt carbon in ash for eight different coals in low NOx systems. The coal volatile matter (% ar) ranged from 28.5 to 33.9 and the fuel ratio from 1.71 to 2.45. The systems used were, a laboratory scale drop tube furnace (DTF), a I MWe combustion test facility (CTF) and a 500 MWe tangentially-fired utility boiler. They found correlations between NOx emissions and the product of fuel nitrogen content and fuel ratio. The correlation was described as 'rough' when volatile matter was determined by the standard proximate analysis technique but was 'much better' when the volatile matter was determined at a high heating rate (VMhhr) more representative of conditions in a boiler furnace (see Figure 3).

360 .....~ "0 •> 340 E • •Q.

•Q. 320 N

0 300 ';$!.0 C')

DO•280 .O%OFA co UJ 260 o 15%OFAc:: 0 0 DO •• 'w .25%OFA240 om •,CQ

•<IJ 220E ...0 z 200 1.00 1.50 2.00 2.50 3.00

Fuel ratio x coal nitrogen, daf

Figure 3 The relationship between NOx emissions and fuel ratio (VMhhr) x fuel nitrogen (Jones and others, 1995a)

A comparison of data from the DTF with data from the CTF was found to support the hypotheses that volatile nitrogen plays only a minor role in NOx formation in staged combustion systems and NOx emissions are primarily related to the nitrogen content of the char. Hence, it might be expected that the control of NOx emissions would be most effective using coals that have a high volatiles content and give a low yield of char.

4.2 The control of NOx from boilers fired by low-rank coal

The brown coal or lignites used in Germany, Southern Australia (Victoria) and Turkey, have high moisture contents and are dried and pulverised using systems that include flue gas recirculation. These factors lower the flame temperature and in consequence a greater radiant heat exchange surface is required. The highly fouling propensities of the coal also dictate generous fumace dimensions and low exit temperatures (Breucker, 1990). These properties have provided fortuitous advantages in the primary control of NOx. Wildman and Smouse (1995) demonstrated a strong relationship between NOx emissions and volumetric heat release rate for a range of units. The intensity of heat release in a boiler may be expressed in terms of the heat release per

25

Optimising combustion conditions for the control of 802 and NOx

14

12

rn 10 ai ..E 8 (1) () c (1) 6"0

'00 (1)

a: 4

2

0

0 500 1000 1500 2000

Added heat, MWt

Figure 4 Residence time as a function of unit capacity (Reidick, 1993)

+ 32.000 m burnout air 2

excess air ratio 0.74/0.95


+ 25.968 m burnout air 1

:m excess air ratio 0.53/0.75

+ 16.500 m vapour burner


secondary air 175 000 m3/h (stp)

main burner

primary air 3/h (stp)

+ 10.000 m

· • -ffi

CI:=j::±j 18750 m

unit of boiler volume or as the heat release per unit of boiler cross sectional area. The latter parameter is valid because the relation between boiler volume and plan area are strongly related in practice. Generously sized boilers provide the volume required for adequate carbon burnout under the controlled combustion conditions that facilitate thermal NOx

suppression and also provide ample space for air staging. Residence time has been identified as a key factor in the simultaneous control of NOx, CO and unburnt carbon. It has been defined as the time during which the gases from the main burners remain at a temperature in excess of 800°e. The calculation of residence time requires an estimation of the mean gas velocity through the boiler and for this purpose it is assumed that the mean temperature of the gases is lOOO°e. Figure 4 shows the relationship found between unit capacity and required residence time for boilers burning Rhenish brown coals.

For boilers where the residence time is marginally

NO,

CO

°2

33m

N02 CO

°2 temperature

29 m

N02 CO

°2 temperature

23m

N02 I CO

°2 temperature

16 m

N02 CO

°2 temperature

emission recorder

178 mg/m3

160 mg/m3

4.9%

231 mg/m3

2057 mg/m3

2.49%

849°C

219 mg/m3

7365 mg/m3

0.35%

1055°C

244 mg/m3

7767 mg/m3

0.83%

1043°C

245 mg/m3

11026 mg/m3

0.70%

1080°C

Figure 5 The relationship between NOx, CO, excess air at various sections up a 150 MWt boiler (Reidick, 1993)

26


insufficient it may effectively be increased by flue gas recirculation in addition to that irillerent in the coal drying process. If residence time is still insufficient compromises may have to be made between NOx, CO and unburnt carbon. Figure 5 presents data from a 150 MWt boiler burning brown coal. The boiler in this example has barely sufficient residence time to achieve the required emissions standards.

Despite leakage air, substoichiometric conditions were maintained up to the second burnout air level. However, the slight increase in NOx, from 219 mg/m3 at the 29 m level to 231 mg/m3 at the 33 m level, indicates that the second addition of burnout air occurs slightly too early. Acceptable emissions were achieved because, in this two pass, brick set boiler, remixing takes place at the turn and high temperatures near the scrubber lead to secondary reduction.

After the reunification of Gennany, major initiatives were launched to upgrade the environment of the fonner Eastern Germany. Brown coal fired power stations were major sources of pollution. VEAG is the supra-regional electricity utility that controls the brown coal fired power stations of the former state of East Gennany. At reunification, the brown coal capacity of VEAG was around 12,750 MWe. Of the existing brown coal fired capacity only the six 500 MWe units at Janschwalde and the two 500 MWe units at Boxberg are expected to have a long term future.

Each of the 500 MWe units at Janschwalde is served by two 815 t/h two pass boilers. Modification of the units to secure compliance with environmental regulations included upgrading of the electrostatic precipitators, the retrofitting of flue gas desulphurisation scrubbers and primary measures to reduce the rate of NOx emissions (Eitz, 1995). The main modifications required to secure NOx emissions below 200 mg/m3 involved giving the main burners, which were situated directly above the ash hopper, a 15° downward tilt and the provision of flue gas recirculation to increase the residence time. The optimisation allowed the modified steam generators to achieve NOx emission rates of 180-190 mg/m3

without flue gas recirculation. With flue gas recirculation the NOx rate was around 160 mg/m3 (Reidick, 1993).

4.2.1 New brown coal fired boilers in Germany

This report is concerned with the optimisation of existing coal-fired boilers. However, when considering the potential of existing boilers for improvement, it is instructive to

consider the perfonnance that is ideally possible. It is planned to supplement German brown coal fired boiler capacity with six new 800 MWe units. All of these units will have to meet the requirements of the German 'Large Furnaces Ordinance'. Among those requirements a maximum NOx emission rate of 200 mg/m3 is specified.

The new 800 MWe tower boilers, being built for VEAG will be 160 m high. Figure 6 shows the arrangement of the 106 m of the radiant section of this boiler, from the ash hopper to the secondary superheater.

+ 5.250 m

0.000 m

Figure 6 VEAG 800 MWe boiler (Reidick, 1993)

The burners are arranged in two planes, one above the other, and fire tangentially on pitch circles of different diameters. The upper burners fire on a circle of smaller diameter than that of the lower burners. This arrangement facilitates even mixing and combustion of the fuel over the large cross sectional area (24 m x 24 m) of the boiler. Above the firing planes there are three separate levels where burnout air is admitted. With a total residence time of 12.6 s, and in view of the encouraging experience with combustion modifications at Janschwalde and Boxberg, it was decided to dispense with additional cold gas recirculation (Reidick, 1993; Eitz and others 1994).

4.3 The control of NOx from boilers fired by hard coal

It has been demonstrated that NOx emissions as low as

27


160 mg/m3 (-0.13 Ib/million Btu) can be achieved, using combustion measures only, for generously sized boilers firing German brown coals. It is also possible to design new boilers fired by hard coal (moist, ash free calorific value >23.86 GJ/t) to achieve low NOx emissions by primary control measures. However, emissions are not quite as low as those achievable for brown coal fired boilers. The 630 MWe Hemweg power station in the Netherlands was commissioned in 1993. Because of its location, near Amsterdam, a maximum NOx emission rate of 300 mg/m3 (6% 02) was specified. It was decided that this rate could be met using primary combustion measures only. The furnace is relatively large and this reduces NOx formation by reducing flame temperature. The design features include second generation low NO x burners and overfire air ports. Coal preparation was also identified as a vital factor. A blend of internationally traded bituminous coals is used to ensure compliance with standards for proximate and ultimate analysis and ash content. Special attention is given to fuel ratio and nitrogen content since these are considered important parameters affecting unburnt carbon loss and NOx emission. Coal particle size is also important and the specification is 88% <75 11m. Table 10 shows the results of performance tests.

During the month of June 1995, the mean 24-hour NOx emission rate was 264 mg/m3 (-0.22 Ib/million Btu). The highest 24-hour rate during the month was 293 mg/m3 and the lowest was 235 mg/m3 (Verhoeff and Kissing, 1996).

These data demonstrate the low NOx emission rates that are ideally achievable by primary combustion measures when the boiler has been designed appropriately. For most older boilers, where NOx control is an afterthought, reduction may be limited by practical constraints. A high volumetric rate of heat release results in a high combustion temperature and a low residence time. NOx control is compromised by a combination of factors that has been called the 'diabolical triangle'. If NO x, fly ash quality and heat exchange in the boiler are notionally placed at the three corners of a triangle it appears that any change in operating conditions (such as pulveriser operation, burner tilt angle, excess air levels, etc) designed to improve one of the corners of the triangle will adversely affect one or both of the other corners. de Kluyver and Gast (1995) found that generally NOx emission rates of 400-450 mg/m3 were attainable by primary conversion measures for existing units fired by bituminous coal. Although these emission rates might be considered

disappointing in comparison with those achieved for brown coal fired boilers, and for the purpose built Hemweg boiler, they do represent a reduction to around 50% of the uncontrolled emission rates.

The following combustion control options, broadly in order of increasing expense, are available for existing boilers:

'tuning' of the existing equipment to achieve optimum setting of dampers and controls; modifications and additional control equipment to facilitate optimisation of combustion conditions; installation of 10w-NOx burners. The effective exploitation of the potential benefits of low NOx burners may require additional instrumentation and control equipment. The facilities for puIverising and distributing coal to the burners may also need improving; provision of overfire air facilities; where there are no existing openings that can be used or modified for overfire air addition modifications to the boiler tube walls will be required; modifications to the installation to use a supplementary 'reburn' fuel.

4.3.1 Boiler tuning

In some cases, the considerable expense of making substantial modifications to a boiler can be deferred or avoided by fine tuning the existing equipment. In any case, even where more expensive modifications have to be made, fine tuning is necessary to obtain full benefit from the improvements. The fine tuning process is facilitated by installing reliable continuous monitoring instruments that can help to make operators aware of NOx emission rates and indicate optimum conditions for low NOx operation.

Experience has shown that tangentially-fired boilers tend to have intrinsically lower NOx emissions than boilers with other firing configurations. However, the traditional design and operation of these boilers still leaves scope for further improvement. Potomac Electric Power Company of MD, USA, in a joint exercise with EPRI, investigated the practicability of complying with tighter NOx emissions limits by fine tuning their corner-fired boilers. This was considered as a potentially more economical alternative to the installation of low NOx burners. In 1991 the unit had been equipped with a digital control system that greatly simplified the control of boiler operating settings such as economiser 02

Table 10 Performance test results at Hemweg (Verhoeff and Kissing, 1996)

Boiler load, %

Water, % as received (ar) Ash, % ar Volatiles, % ar HHV, MJ/kg Fuel ratio

O2• % in stack NO,. mg/m' corrected to 6% O2

Unbumt carbon in ash. %

100 95 80 60 40

9.6 9.64 9.79 9.93 10.26 10.40 10.43 10.10 10.28 10.34

30.36 30.40 30.32 30.51 30.26

27.20 27.18 27.28 27.19 26.99

1.65 1.63 1.64 1.62 1.62

5.1 5.2 4.7 5.3 5.4

299 271 275 264 248

1.9 2.0 4.2 2.5 2.4

28


and burner tilt angle. The unit was also equipped with EPRI's plant monitoring workstation (PMW) for data acquisition, trend analysis and on line performance analysis. For the test programme, a NOx analyser was installed in the stack and the information from the analyser was fed directly to the PMW. Parametric testing was performed to determine the effect of boiler and burner adjustments on NOx, steam temperatures, carbon in ash and plant efficiency. The parameters found to be important at the Potomac River unit were: 02 concentration, burner tilt angle, mill loading pattern and the vertical distribution of air to the auxiliary air and fuel air registers.

The tests confirmed that, by optimising the relevant parameters, it was possible to reduce NOx emissions from the small (108 MWe) tangentially-fired boiler to around 455 mglm3 (0.37 Ib/million Btu), a NOx reduction of approximately 40%. However, low NOx operation required operation of the furnace at 1.6% excess oxygen. A more normal value would be around 3% excess oxygen. The uncomfortably low value gave reason for concern about the long term wastage rates of the furnace water walls. Also, carbon in ash was in the region of 13% which many operators would consider unacceptably high. However, with scope for some further NOx reductions when a number of equipment improvements had been made, it was expected that it would be possible to increase excess oxygen to nearly 2% while still meeting the local emission limit of 467 mg/m3

(0.38 lb/million Btu). The results reported are striking in view of the list of further improvements planned:

the effect of closer control of primary air velocity was being investigated; the air register dampers are to be converted from manual to automatic operation to permit more precise operation as the unit ramps up and down in load; controls will be fine tuned to optimise the rate of change and sequencing of 02, burner tilt angle, mill loadings and air register settings during load transients; the coal/air distribution to the burners will be balanced. This had not been done before the tests because of a lack of outage opportunities (Levy and others, 1993).

The Tennessee Valley Authority (TVA) uses boiler tuning as an integral part of their compliance strategy to meet the requirements of the US CAAA of 1990. The chosen tuning process is a proprietary technology, co-developed by EPRI and the Ultramax Corporation, known as sequential process optimisation. It was used to optimise the performance of six 125 MWe tangentially-fired units that were first commissioned in the 1950s. Although the boilers involved are tangentially fired, the process can be applied to any type of boiler. The method consists of procedures and computer software that utilise data collected from the boiler during normal operations. Minor perturbations from normal settings are exploited to determine their effect on emissions and thermal perfornlance. The software analyses the data after every test run to create statistical models and search for optimum combinations of settings. Because data analysis and model refinement occur after each test run, settings that harm perfornlance can be identified immediately and eliminated from consideration. A key element of the modelling process

involves the weighting of more recent data. This produces a goal oriented model suitable for discovering regions of optimal performance. The refined model also advises appropriate responses to changes in uncontrolled variables such as load, fuel quality and seasonal temperature.

The technique was successful in reducing NOx emissions from the boilers to less than the regulation level of 554 mg/m3 (0.45 lb/million Btu). The net benefit to TVA, including avoidance of retrofitting and average annual fuel savings over 10 years, was estimated at $17.4 million (Boyle and others, 1995).

4.3.2 Low NOx burners: tangentially-fired systems

Epple and others (1995) demonstrated that low NOx emissions (-200 mglm3 ) could be secured using a bituminous coal given the facilities of a modified, tangentially-fired, boiler that was originally designed for lignite. Among the modifications, the original lignite beater mills were replaced by bowl mills with rotary classifiers. This 110 MWe boiler has its burners arranged at three levels in the four corners of the furnace section. The burners and their under and overfire air ports were arranged to reduce NOx emissions by converting the conventional tangential firing system into a concentric firing system with an inner fuel rich zone and an outer air rich zone (see Figure 7).

For each burner, there is a secondary air port located beneath the burner and two secondary air ports located above it. The air from the lower port is directed towards the furnace wall. The first upper secondary air port directs its air towards the combustion tangent. The second upper air port is divided; half of the air is directed towards the tangent and half is directed along the furnace wall. With this arrangement it was possible to reduce the combustion stoichiometry to 0.74 in the combustion zone while maintaining oxidising conditions in the region of the furnace walls. For normal operation, NOx emissions around 200 mg/m3 were obtained at a burner zone stoichiometry of 0.74 and an overall stoichiometry of 1.15.

ABB Combustion engineering have also been developing a low NOx concentric firing system for tangentially-fired boilers (LNCSTM). The LNCS system designs that carry their registered trademark are offered for the retrofitting of existing boilers. Three design options are offered. The differences between the options result from different evaluations of the relative importance of minimising NOx

emissions at the expense of CO emissions, carbon in ash and modifications costs. The degree of reduction of NOx

emissions achievable in practice is also dependent on the original design of the boiler and the type of fuel being fired (Speirs and others, 1994). United Illuminating of CT, USA, are operating a 390 MWe tangentially-fired boiler. They are using an eastern USA, low sulphur bituminous coal. Uncontrolled NOx emissions were in the range 677-738 mg/m3 (0.55-0.60 Ib/million Btu). The boiler was retrofitted with a low NOx concentric firing system. The existing pulverisers were also upgraded to give the increased coal fineness required for controlling carbon content in the

29


a) Conventional system

Fuel and air stream

b) Concentric system

Air stream

, -----:I , , ....

, ....I

, ....

.... \

\I I , I I

I'I\ I

Ii\ I I\

I \

\ I I .... \

....

\

\ .... \

\--- ....... \

/

"

Fuel stream

Figure 7 Comparison of plan views of conventional and concentric tangential firing systems (Marion and others, 1993)

ash. After the modifications the boiler NOx emissions were of the order of 308 mg/m3 (0.25 Ib/million Btu) with no increase in unburnt carbon (Buffa and others, 1995). ABB C-E is also developing concentric firing for new boilers with the objective of establishing a combustion technology for tangentially-fired boilers that will enable them to control NOx emissions to less than 200 mg/m3. A new 250 MWe pulverised coal fired unit using this technology is scheduled for commissioning in 1996 (Speirs and others, 1994).

TIle LNCS systems described above are primarily advanced air staging techniques. Experience with wall-fired systems has demonstrated the requirement for a high temperature

rapid devolatilisation zone near the burner for enhanced NOx reduction (see Section 4.3.3). It is claimed that by replacing the coal nozzles on a tangentially-fired boiler with 'flame attached nozzle' (FAN) burners it may be possible to achieve NOx emissions 'as low as 0.14 Ib/million Btu' (-175 mg/m3)

(Allen and Beale, 1995). The FAN burner is based on the principles established during the development and application of wall-fired low NOx burners. Progress in the development of the burner is reported to be encouraging but potential problems of ash deposition within the flame attachment area of the burner have been identified. Savolainen and Dernjatin (1995) also described the advantages of producing a stable, high temperature, reducing flame near the burner tip.

4.3.3 Low NOx burners: wall-fired systems

As with tangentially-fired boilers, NO x emissions from wallfired boilers can be reduced by careful optimisation of the existing burner system. However, in the USA, NO x emission limits for existing large boilers have been set at 554 mg/m3

(0.45 Ib/million Btu) for dry bottom boilers and generally low NOx burners are needed to achieve these levels.

Low NOx burner development Figure 8 shows a conventional Babcock S-type burner. Burners of this and similar designs were standard equipment for wall-fired boilers before the control of NOx became an important consideration.

The design was intended to promote the rapid mixing of fuel and air giving the short flames and high flame temperatures that were compatible with the achievement of efficient combustion in economically compact boilers. The incidental effect of the intense combustion conditions was to produce high NOx concentrations in the flue gas.

In 1972 Babcock developed the dual register burner (DRB) with the objective of reducing NOx production (Figure 9). The dual register burner provided two air zones, each controlled by a separate register. The aim was to produce a stable flame with a substoichiometric core with further air mixing and combustion taking place down stream. This effectively reduced NOx production but also produced a relatively long, lazy flame. For compact boilers there were potential problems of incomplete combustion and flame

Figure 9 Babcock dual register burner (Stultz and Kitto, 1992c)

30


Furnace wall tube Secondary

air

--.-.....-------\--- /l/ ---------IT

Furnace

Sliding air damper

Flame scanner

---'--¥-----f---/l/------------1

Secondary air Impeller Swirled air flow pattern

Pulverised coal and

Primary air from pulveriser

Figure 8 Babcock S-type burner (Stultz and Kitto, 1992c)

@

©

Outer secondary

Sliding air damper

Pulverised coal and primary air

air mixing

® High temperature - fuel rich devolatilisation zone

® Production of reducing species

© NOx decomposition zone @ Char oxidising zone

Figure 10 DRB-XCLn, low NOx burner (Stultz and Kitto, 1992c)

impingement. The development of the second generation of rapid heating and generatc high tcmperatures in the fuel rich low NO, burners addressed these problems while achieving flame core. The rapid heating causcs an enhanced conversion further reductions in NO, emissions. Figure 10 shows the of the coal to volatile mattcr ( Knill and others, 1990) and alTangement of a proprietary second generation low NO, releases a larger proportion of the fuel nitrogen early in the burncr. combustion proccss, leaving less in thc char. Because the

available oxygen in the flame core is limited, NO, formation Second generation low NO, burners are dcsigned to promote is minimised. At the samc time, highly reactive C-H radicals

31


are produced from the volatile materials. These propagate into the flame promoting the conversion of fuel nitrogen to molecular nitrogen.

Two of the six 200 MWe boilers at the Jaworzno III power plant in southern Poland have been retrofitted with second generation low NOx burners. From the beginning of 1998 the limit for NO x emissions in Poland will be 170 mg/MJ (490 mg/m3). Currently the emission rates from their uncontrolled boilers are in the range 250--400 mg/MJ (720--1140 mg/m3). TIle two boilers at Jaworzno were fitted with NR-LCC (NOx reduction in clean coal combustion) burners developed by Babcock-Hitachi KK and IVO International. Each burner is fitted with a pulverised coal concentrator; an aerodynamically shaped obstruction within the central primary air/pulverised coal pipe which is designed to improve the radial distribution of coal particles in the air stream. In the XCL burner a similar function is served by the 'conical diffuser'. TIlese devices are said to improve flame ignition and stability and give better carbon burnout (Saarinen, 1996). The retrofit, which also included modification of the boiler's membrane walls for the provision of overfire air, was successful in reducing NO emissionx rates below 170 mg/MJ. In the first half year of operation after the modifications NOx emission rates have been between 120 and 150 mg/MJ (340--440 mg/m3). Unburnt carbon in fly ash has remained below 5% and there has been no increase of slagging in the furnace. In Autumn 1995 Jawozorno power plant contracted IVO Power to modify their units 4 and 6 (Saarinen, 1996).

4.4 Coal pulverising and distribution For both tangential- and wall-fired boilers, accurate control of the coal fineness and accurate distribution of coal and air is essential for minimising NOx formation and maximising carbon burnout.

4.4.1 Coal pulverising

Authors have reached various conclusions on the direct effect

Tertiary air ~ I

Secondary air

Primary air

of coal fineness on NOx formation (Afonso and others, 1993). In practice, the direct effect appears to be small but the effect on unburnt carbon in the ash, particularly when combustion conditions are designed to minimise NOx formation, can be significant. Fineness, in this context, relates to the absence of coarse particles rather than the presence of ultra-fine particles. Hardman and others (1993) assessed the effects of coal fineness on the performance of a tangentially-fired furnace using the concentric firing system. They assessed coal fineness in terms of the percentage passing 74/lm (200 mesh) and the percentage passing 300 /lm (50 mesh) screens. Their data indicated that, beyond 65% through 74/lm (200 mesh), increasing fineness had little effect on carbon in ash but carbon in ash continued to decrease at an accelerating rate beyond 99% through 300 /lm (50 mesh). Hence, to obtain acceptable carbon in ash under low NOx firing conditions, efficient classification is required rather than hyperfine grinding. In their series of tests on a 180 MWe tangentially-fired boiler the NOx emissions (NOx

30-day achievable emission limit) were reduced from a baseline of 836 mg/m3 (0.68 lb/million Btu) to 541 mg/m3

(0.44 Ib/million Btu).

4.4.2 Air and coal distribution

Having prepared the coal to the required fineness and size distribution, it must be distributed to the burners. The control of NOx by careful control of combustion stoichiometry may be defeated if there is gross maldistribution of coal and air to the burners. For a single burner test installation it is possible to control stoichiometry accurately. Beer and others (1995) reported the results of tests using a 1.47 MWt PC burner with a high volatile bituminous coal. The main features of the burner are shown in Figure 11.

It should be noted that in these MIT tests a distinction is made between transport air and primary air. In normal pulveriser/burner usage this distinction is not made and the terms are used interchangeably. The radially stratified flame core (RSFC) burner has three annuli, primary, secondary and tertiary, with independently adjustable swirl generators. The

Burner quarl

Burner quarl

Swirl generator

-

II ~ ~ ~---------,-----,I

Figure 11 MIT-RSFC low NOx burner (Beer and others, 1995)

32


lowest NOx emissions were obtained without overfire air. Burner stoichiometric ratio was found to have a strong impact on NOx concentration. When the transport air to coal ratio was increased from 1.4 to 1.8 the NOx concentration increased from 215 mg/m3 to 308 mg/m3. When the tertiary air was reduced to compensate for the additional transport air, the exit NOx concentration decreased from about 215 mg/m3 to about 170 mg/m3. Compensating for increases in transport air flow by reducing the primary air instead of the tertiary air gave no reduction in NOx concentration. Using a high volatile bituminous coal it was found possible to reduce the NOx emission rate to 144 mgim3 at 3% oxygen. The lowest NOx emissions were obtained with a radial air flow distribution in which more than 50% of the total air flow was introduced through the transport plus primary air conduits. This resulted in the maximum yield of volatile matter, stable ignition and a steep initial temperature rise, factors that are conducive to the production of a hot flame core (Beer and others, 1995).

The precise control of coal and air is possible for a single burner test rig but a utility scale, multi-burner installation is less amenable to control. Some of the features that militate against the accurate metering of coal and air at utility scale are:

the transport air, more usually described as the primary air, is the medium that dries the coal and transports it

a) Fully open 100% flow area - no restriction

b) Fully closed 10% flow area - maximum control

within the coal pulverising mill. The same air carries the coal through the transport pipes to the burners. The air to coal ratio is determined by safety and availability considerations and varies with throughput; many existing furnaces were designed to accommodate simple burners. The arrangements for distributing secondary air may be correspondingly basic; the coal feed to each pulverising mill can be controlled with reasonable accuracy but each mill supplies several burners. The equal division of coal and air between the burners depends on accurate design of the geometry of the distribution pipes to provide paths of equal aerodynamic impedance. This is an ideal that cannot be achieved in practice; the burner ports on existing boilers may be inconveniently small. Enlargement of the ports may be uneconomic because of the need for expensive modifications to the boiler water walls. controlling NOx is only one of the considerations in the operation of a boiler. At part load, for example, increased rates of excess air may be required to maintain superheat and reheat temperatures at their optimum values.

Primary air distribution The primary air to coal ratio is decided by consideration of safety, economy and plant availability. Excessively high transport velocities cause rapid erosion of the pneumatic

Figure 12 PC flow control: adjustable orifice (Sommer and others, 1993)

33


transport pipes that carry the coal from the pulverisers to the burners. Excessively low velocities allow coal to deposit in horizontal sections of the pipes with the attendant dangers of spontaneous combustion and explosion. The pipes are sized to give a flow velocity of around 25 mls at maximum throughput. As throughput is reduced the air to coal ratio is progressively increased to prevent the transport velocity falling below the safe minimum, usually around 15 m/s. Typically the mass ratio is around 2: I, or more, at low coal flows falling to around 1.6: I at maximum throughput (Scott, 1995).

For most boilers, a single coal pulverising mill serves four or more burners and the stream of coal suspended in air must be accurately split between the burners. Particles suspended in a gas stream do not usually distribute themselves evenly. If a cross section of a flowing stream is sampled, concentrations of particles will be found at some locations with a corresponding scarcity at others. Hence even if the air flow were divided equally, the coal flows might be unequal. Generally, manufacturers of low NOx burners suggest that the coal should be distributed so that each burner receives the mean flow ±I0%. Some boiler operators would prefer the imbalance to be nearer 5% (Knudsen, 1994). The flows are balanced by partly obstructing the pipes which are receiving an excessive proportion of the coal. This may be achieved by inserting orifice plates or, if the flow is divided using splitter boxes, some of the ducts in the boxes can be deliberately blocked. The process is simplified if a variable orifice is installed in the burner supply pipes. Figure 12 shows a proprietary design which has ceramic blades to resist erosion.

However, the accurate balancing of coal and primary air flows for low NOx burners can be a tedious iterative process. Measurements of air and coal mass flows through each coal distribution pipe are followed by re-balancing followed by further measurements and so on until a satisfactory result is achieved. At the end of the process, the final result is likely to be a compromise because an accurate distribution at one rate of coal throughput may become unbalanced at a different throughput. The system is set up to give the best achievable compromise at two selected coal delivery rates and the resulting distribution at other rates has to be accepted (Scott, 1995).

Secondary and tertiary air distribution TIle control of secondary air, tertiary air etc may also present difficulties. In contrast with the MIT burner (see Figure II) thc S-type burner has provision only for primary air and secondary air with thc secondary air delivercd from a windbox that is common to a number of burners. The low NOx burner shown in Figurc 10 has provision for primary, secondary and tertiary air while, if the normal nomenclature is used, the MIT burner has provision for independently controlled primary, sccondary, tertiary and quaternary air.

4.4.3 Coal and air flow: instrumentation and control

In view of thc low NOx levels attainable for tightly controllcd test burners it appears possible that, if the control

of the distribution of coal and air at utility scale could be improved, useful reductions in NOx emissions might result. This would require technology for the on-line measurement and control of the flow of coal and air through the individual burner supply pipes. The measurement of coal flow to individual burners in real time is currently at the research and development stage (Scott, 1995). However, a number of authors have suggested that burner stoichiometry can be inferred by observation of the flame.

Bailey and Carter (1992) described a flame quality analyser based on the spectral emissions of sodium and potassium. The flame is observed using an array of optical probes connected to the data processing equipment by fibre optic cables. The flame temperature is deduced by comparing the relative intensity of the emissions at the two wavelengths. The analyser has been used to measure local flame characteristics in wall-fired and tangentially-fired boilers. It is claimed that, by processing the data using a personal computer, on line information can be generated for burner to burner load balancing, flame envelope control and flame condition monitoring. Miyamae and others (1995) described the use of what appears to be a fundamentally similar system for a 250 MWe PC-fired boiler and a newly-installed 600 MWe boiler. The system was said to give useful infornlation on the behaviour of individual burners. Changing the angle of the swirl vanes in the burners changed both the degree of swirl imparted to the combustion air and, by changing the resistance to air flow, the quantity of combustion air. With the benefit of the processed infornlation from the flame monitoring system it was possible to adjust the swirl and stoichiometric ratio for individual burners thereby minimising NOx in the off-gas and unburnt carbon in the fly ash.

Georgel and others (1994) described a flame analysis system based on the use of video cameras, digitised colour images and image processing software. A competent boiler operator assessing a burner flame 'by eye' might use a number of parameters to describe it such as colour. brightness, stability, whether the flame is close to the burner or lifted off etc. The image analysis software is designed to use such criteria to allow the infornlation from cameras to be translated into objective measurements. The size of the images is set at 256 x 386 pixels and the rate of image acquisition is said to be fast enough to match the changes in the flame. The digitisation step involves a SUN workstation and specialised software. It was claimed that the technique was effective for monitoring the combustion efficicncy of individual burners. However, a need for some furthcr validatory research was declared.

Flamcs present a turbulent, rapidly fluctuating appearance that is apparently chaotic. The flame monitoring systems described by Bailey and Carter (1992) and Georgel and others (1994) use averaging techniques to eliminate the fluctuations. Khesin and othcrs (1995) advocate the use of 'smart flame scanners' to analyse the fluctuating component of thc flame signals. Existing burner flame sensors. that are part of standard burner management systems, were used although it was notcd that visible flame scnsors werc more suitable than infrared scnsors. The principles of the correlation of flamc fluctuation (or 'flickcr') with flame

34


quality are explained as follows. In individual burner flames, the combustion process is dominated by the rate of mixing of fuel and air. Each burner flame consists of many combustion/recirculation cycles of various sizes inside and outside the flame. These eddies contribute to generating the flame flicker at various frequencies as combustion occurs at the edges of the fuel and air jets. Smaller eddies occur more frequently and generate higher frequencies. Larger eddies occur with lower frequency but, because they comprise a greater quantity of fuel and air, they should give a larger emission intensity. Each flame characteristic, for example fuel to air ratio, swirl, mixing rate or combustion efficiency, is associated with a dominant group of eddies which, in turn, generate a dominant radiation segment in the temporal frequency spectrum. Analysis of the spectra depended on the development of a set of computer algorithms. The validity of these algorithms was assessed by a series of tests on coal and oil-fired utility boilers ranging from 85-400 MWe. The results were sufficiently encouraging to justify further development of the technique and tests on well instrumented single burner facilities followed. Algorithm development was the most important aspect of the project. Two principal strategies were used, an empirical approach and a hybrid neural network/fuzzy logic approach. Figure 13 shows how the latter approach can develop a 'trained' system that gives improved correlation between the predicted stoichiometry and the actual burner stoichiometry.

The technique is now offered as the 'SpectraTune™ ' system for practical applications for identifying 'out of tunc' burners and for burner balancing. Further development work is aimed at burner optimisation for selected criteria (eg minimum NOx ).

The US DOE's Pittsburgh Energy Center began a research and development initiative in late 1990 to address the design issues facing new and replacement coal-fired power plants. This programme is known as combustion 2000 and its first

1.40

1.35

1.30

0 before training

• after training ••0

a: (J)

TI (j)

t5 TI (j)

D::

1.25

1.20

1.15

§ 0 0

•

§ 0

•

~ lio 0

•

00

0

1.15 1.20 1.25 1.30 1.35 1.40 Actual SR

Figure 13 Predicted stoichiometric ratio (SR) versus actual SR before and after training for a low NOx bu rner (Khesin and others, 1995)

stage involves the commercialisation of a low emissions boiler system (LEBS). Current objectives of this programme are to develop a plant with emissions of no more than 0.1 Ib/million Btu of S02 (-120 mg/m3), 0.1 Ib/million Btu of NOx, 0.015 Ib/million Btu (-18 mg/m3) of particulates and a net plant efficiency approaching 42% HHV. It is envisaged that NOx will be controlled by primary means alone. Achieving the NOx emission goals, normally below 120 mg/m3 and never exceeding 240 mg/m3 throughout the operating range, will require accurate control of air to coal ratios and accurate balancing of the coal distribution between the burners. The SpectraTune™ system is being assessed as a possible means for monitoring flame conditions to allow accurate control of coal/air ratio (Johnson and others, 1995).

4.5 Reburning Primary NOx emissions may be reduced by injecting a hydrocarbon fuel into the flue gas in an additional 'reburning' or fuel staging zone downstream of the main burner zone. This is an established technology for oil and gas-fired boilers that has more recently been applied to coal-fired boilers (Hjarlmasson, 1990). Figure 14 shows a typical reburning installation on a wall-fired boiler but the principle may also be used for tangentially-fired boilers or cyclone boilers.

The combustion process is divided into three zones. In the primary zone the bulk of the fuel (70-90%) is fired through conventional burners under relatively low excess air conditions. In the reburning zone the supplementary fuel consumes the excess air from the primary zone and produces a slightly fuel-rich region where NOx is reduced by reaction with hydrocarbon radicals. Overfire air is added in the final burnout zone to complete combustion and restore an overall excess air. Any fuel can be used for the reburning stage but gas is technically the easiest supplementary fuel for retrofit applications. The process has two time constants: the rapid decay of NO under reducing conditions and the slow conversion of HCN and NH3 to N2. Mixing limits the reaction rates of the process and the degree of conversion achieved. Theoretical modelling, based on instantaneous mixing, predicts a limit of 80-90% NOx reduction (Tyson, 1995). In practice, the net reduction is normally around 50-60% with reductions as high as 80% in isolated cases.

The percentage reduction of the NOx entering the reburn zone is independent of the inlet concentration. Hence, in principle, having obtained the lowest practicable NO x concentration by burner modifications it should be possible to obtain a further reduction of the NOx concentration by reburning. Figure IS shows the NOx reductions achieved by retrofitting a boiler successively with low NOx burners (LNB) and a gas reburning (GR) system.

Barcikowski (1992) suggests that natural gas, containing virtually no fuel nitrogen, gives optimum emission reduction. Research and development work by ENEL of Italy on oil-fired systems gave similar indications for relatively small scale test furnaces. A 35 MWe test showed that starting from baseline NOx emission rates around 440 mg/m3, it was possible to reduce rates to around 150 mg/m3 by gas

35

250


Overfire air -.

Gas 18% -.

Coal 82% -.

Zone Conditions NOx reduction

Burnout Normal No excess air change

Reburning Slightly HxCy

fuel rich reactions

Main Low Reduced load combustion excess air reduced excess air

Combustion air

Figure 14 Typical reburning installation on a wall·fired boiler (Folsom and others, 1996)

reburn fuel (Dodero and Reynaud, 1995). A 600 MWe unit owned and operated by Scottish Power in Longannet,

1000

750

C'J

E 0, E

5000" z

..... #~• .;.....

O+---~---~--~------,---~

3.53.02.5 4.0 5.04.5

Excess 02, %

• Baseline .. GR-LNB

Figure 15 Gas reburning on Cherokee unit 3(Folsom and others, 1996)

reburning while oil reburning gave rates around 200 mg/m3.

These encouraging results led to a trial on a 160 MWe oil-fired unit and the success of this trial led to the retrofitting of a 320 MWe unit. For both oil and gas reburning, emission rates were reduced from a baseline of 750 mg/m3 to around 150-160 mg/m3. The technology was also found to be effective at low load with NOx emission rates below the legal maximum of 200 mg/m3 from full to half load.

With the aid of funding from the European Union 'Thermie' programme, ENEL is engaged in the development of rcburning for coal-fired plant. TIley plan to retrofit one of their own 320 MWe coal-fired units and use oil or coal as the

Scotland is also being used to test and demonstrate reburn technology with assistance under Thermie. Scottish Power have undertaken the project in partnership with Ansaldo Energia SpA, British Gas pic, Electricite de France, ENEL SpA, Electricity Supply Board of Ireland and Mitsui Babcock Energy Ltd. An initial feasibility study by Scottish Power and British Gas led to the conclusion that gas reburning was a better option than SCR for Longannet. However, the rebum installation will require a substantial programme of upgrading and modification of the boiler and its peripherals. The process design study has determined that 24 gas injectors and 16 overfire air ports would be required in the furnace. Overfire air will be supplied by two new fans. Flue gas will be recirculated from the economiser outlet and hence a recirculation fan protected by a grit an-estor will be needed. The total weight of the new equipment, including the fans and grit arrestor was 720 tonnes. The support of this additional load required the existing structure to be strengthened by the addition of 145 tonnes of reinforcing steelwork and the replacement of some 1500 connecting bolts by higher strength material. Reburning would increase the furnace exit gas temperature (FEGT) by about 35°C. The increase in FEGT together with the increased mass flow rate due to flue gas recirculation would increase the heat absorbed in the superheater and would increase the economiser outlet temperature by soc. A 30% increase in attemperator spray water flow would be needed and boiler efficiency would be reduced by about 0.95%. TIle existing attemperator spray nozzles were replaced with larger nozzles capable of supplying the required flow. In addition to the work supported by Thermie funding a number of other complementary modifications and improvements were made to the boiler and its peripherals:

a programme of work was undertaken to commission and upgrade boiler control loops, particularly those associated with PC mill throughput control, secondary and primary air control;

36


the PC fixed classifiers of the two PC mills serving the top row of burners were replaced by rotating classifiers. The fixed classifiers of the mills serving the three rows of burners below the top row were fitted with new fixed classifiers; a new economiser with additional surface area has been installed. This will prevent the increase in outlet flue gas temperature and minimise the reduction in boiler efficiency associated with gas reburning.

Modifications commenced in December 1995. The bulk of the installation of the rebum equipment was programmed into a scheduled outage which commenced in April 1996. Completion was scheduled for October 1996 (Golland and others, 1996).

As well as the direct effect in reducing emissions, the destruction of NO x, by chemical reaction, gas injection may confer additional benefits:

the replacement of a proportion of the coal by a fuel free of mineral matter gives proportionate reductions in ash and S02 production; where mill capacity is a limiting factor, the use of a supplementary fuel that does not need drying or pulverising may increase maximum output (Mecchia and others, 1995).

4.6 502 control by fuel switching: combustion effects

It is relatively easy to estimate the reduction in S02 emissions that will result from a known change in fuel sulphur content (see Section 2.1.3). For the US CAAA Phase I, the S02 emission average of 1.074 g/MJ (2.5 Ib/million Btu) could be met by using a coal with a heating value of 20 GJ/t and a sulphur content of I %. The Phase II average could be met by using a coal with a sulphur content of 0.5%. The atypically low heating value of 20 GJ/t is quoted because the demand for low sulphur coal has stimulated the production and distribution facilities for low rank coals from the western USA. The operating experience at twelve units from nine utilities that used western coals and/or coal blends was analysed by Gunderson and others (1993). An analysis for Caballo Rojo Powder River Basin (PRB) coal is given in Table II together with the analysis of a bituminous coal which is more typical of the coals that were formerly used as the sole fuel.

However, in addition to the possible fuel cost implications, switching to a blend of coals can have significant effects on boiler operation and maintenance costs. Pulveriser operation, combustion characteristics, heat exchange in the boiler, slagging and fouling potentials and particulate control efficiencies can all be altered (Morgan and Boesen, 1994). The effects of low sulphur blends on the efficiency of ESPs are discussed further in Section 5.4.2.

Although the Hardgrove grindability index of the Caballo Rojo coal is slightly higher than that of the typical coal, mill capacity has proved to be a possible issue when converting to

PRB coal blends. The grindability of coal blends is not necessarily additive; the grindability of a blend may tend to be determined by the grindability of the most resistant component and carbon burnout may be determined by the least combustible component (Carpenter, 1995; Simon and others, 1995). Other factors also tend to increase the demands on the mills. The substantially reduced heating value, when using subbituminous coal, increases the required throughput and hence increases the loading on the coal pulverisers. Increased moisture content tends to reduce the grinding capacity of mills and throughput may also be limited by the drying capacity of the mill.

Subbituminous coals are more reactive than bituminous coals and this may increase the danger of fire or explosion associated with storage and milling. Cannon and others (1993) found that fuel ratio, the ratio of fixed carbon to volatile matter, gave a rough indication of fire and explosion hazards. The ratio ranges from around 20 for anthracites to around 0.5 for lignites. It was suggested that coals with a fuel ratio greater than 1.5 could be safely processed in air using current operating methods. In the range 1.5-1, caution is required and below I some form of intermittent or

Table 11 Caballo Rojo Powder River Basin coal: analyses (Gunderson and others, 1993)

Typical Caballo pre-Phase I coal Rojo coal

Proximate analysis, as received % Moisture 6.00 29.48

Volatile matter 32.50 33.41

Fixed carbon 49.5 32.12

Ash 12.00 4.99

Total 100 100

Ultimate analysis as received % Carbon 67.80 49.41

Hydrogen 3.60 3.27

Nitrogen 1.30 0.73

Oxygen 6.40 11.77

Sulphur 2.90 0.35

Chlorine Ash 12.00 4.99

Moisture 6.00 29.48

Total 100 100

HHV, GJ/t as received 27.45 19.77

Hardgrove grindability index 55 58

Coal ash analysis weight % Si02 50.00 30.91

AhO, 22.80 16.36

Fe2O, 22.20 4.53

Ti02 1.10 1.37

P20 S 0.20 0.83

CaO 1.50 23.75

MgO 0.70 3.94

Na20 0.20 1.49

K2 0 1.10 0.29

SO,1 0.20 15.48

Total 100 98.95

37


continuous inerting is advised (Cannon and others, 1993; Scott, 1995). The data in Table 11 indicate a fuel ratio of 1.51 for the 'typical' coal and 0.96 for the Caballo Rojo coal. With blends containing up to 50% Caballo Rojo no milling throughput limitations were encountered at four of the units surveyed by Gunderson and others (1993). Where limitations on throughput were experienced they were due to lack of drying capacity rather than lack of grinding capacity. There was an increased incidence of smouldering and fires when material was dumped from the pyrite traps. Four of the units added mill inerting or flooding facilities while two of the same units also altered startup and shutdown procedures to promote safe operation. The frequency of incidents was reduced significantly by reducing the pulveriser output set point from the normal 65°C to 57°C. A somewhat increased propensity for slagging and fouling was generally countered by modifications to the soot blowing facilities. Furnace wall slagging was controllable with slightly increased rates of blowing. Convective pass tube fouling was manageable in nearly every case where retractable sootblower coverage was available.

Generally, S02 emission standards are more stringent in continental Europe. A limit of 400 mg/m3 is widely applied for new large boilers. Standards based on mass/unit volume do not strictly relate with standards based on mass/unit energy input but 400 mg/m3 is approximately 140 mglMJ (0.33 Ib/million Btu). Where compliance by using low sulphur coal is allowed, the limit would require a coal sulphur content below 0.2%. This is exceptionally low. The sulphur content specified for internationally traded coal is usually in the range 0.5-1 % (Skorupska, 1993). Even if coals of sufficiently low sulphur content were available at acceptable cost, the coal switching option alone does not satisfy the regulations of some countries because they specify sulphur removal as well as emission control. For example, German regulations require existing large coal-fired boilers to remove at least 85% of the sulphur as well as complying with the 400 mg/m3 limit. In such cases the use of a low sulphur coal might actually cause problems for the operator because it would effectively make the emission limit more stringent.

38

-----------

5 Flue gas treatment

As described in Chapter 4, there are still many locations where the selection of low sulphur coals and the use of primary combustion measures may be sufficient to meet the local pollution requirements for S02 or NOx emissions. At other locations suitable coals are not economically available or the environmental requirements have become too stringent. Where increasingly stringent environmental requirements have made existing facilities for emissions control inadequate it is usually possible to upgrade performance by optimising existing equipment or retrofitting new equipment. However, a major potential hazard has been found in the modification of the flue gas systems of large boilers.

5.1 Boiler safety: implosion hazard It is normal modem practice for power station boilers to maintain a slight negative pressure within the furnace by balancing the delivery of air from the forced draft (FD) fan with the extraction of flue gas by the induced draft (ID) fan. There are three major causes of large negative pressure surges in conventional power station boilers:

flame out, caused by loss of fuel supply; excess ID fan suction, caused by ID fan inlet guide vane fault for example; loss of air supply, caused by inadvertent closure of the FD fan damper or burner air registers for example.

Any flue gas treatment equipment added to an existing boiler installation is likely to increase the resistance to the flow of flue gas. The ID fan then has to work harder to overcome the increased resistance. The addition of a wet scrubber system may increase the pressure drop by 50-70 kPa at boiler maximum continuous rating (Peterson and others, 1991). A booster fan, or possibly a more powerful ID fan, may be needed to maintain the designed boiler pressure. In the case of some malfunction of the system the increased power of the ID fan or fans may give them the capacity to subject the boiler furnace to a negative pressure in excess of its design

pressure. Figures 16 and 17 show the computed effects of a main fuel trip on furnace pressure before and after the installation of a wet scrubber system.

Modifications to allow a boiler to burn low sulphur fuel of lower calorific value than the boiler design fuel can increase the volume of gas to be moved by the ID fan with similar consequences.

Time, S 0-,--==""""------:....-------1 700

Figure 17 Fuel trip transient after installation of a wet scrubber (Forrest and others, 1995)

-1 <tl

~ -2 a.i ~ -3 til Q)

c:: -4

-5

-6+-----.-----.-----,----------,------"-0 5 10 15 20

-- Furnace pressure - - - FO fan flow ... -10 fan flow

Figure 16 Fuel trip transient before installation of a wet scrubber (Forrest and others, 1995)

Time, s0-,--==-----------'-------1700

-1

-2 ~ ~ -3 :; ~ -4 Q)

c:: -5

- 600..." .../

_, ,_ ~ - .- - .' - - - - 500 .!!!.

~ 400 ~

o 300 ~

<tl

200 0

100

600

500 til\ , ~

\ 400 ~ , o 300 ~

<tl

200 0

100

-6+------r----.-----,-------,-----~0 5 10 15 20

Furnace pressure - - - FO fan flow - •• -10 fan flow

39

Flue gas treatment

The first boiler furnace implosion on a power generating unit in the USA occurred in December 1972. By 1976 twelve further serious incidents had been listed. Since then, several other large generating utility boilers have imploded causing damage to furnace pressure parts, casings and duct-work. The first boiler implosion in the UK occurred in November 1976 and there were three more incidents on the same unit during the next six months. After the incidents the furnace design pressures for all stations under construction in the UK were reviewed. Following the review the furnace walls of some boilers were strengthened. The use of control systems to reduce the implosion potential was considered sufficient at other stations. No further incidents resulting in plant damage have been reported in the UK. Recently however, the retrofitting of emissions control equipment has given rise to renewed concern in the USA about the risk of furnace implosion. For some years EPRI has been developing their gas system dynamics modelling system (DUCSYS) for large boilers. The UK utility PowerGen in conjunction with EPRI has used and developed this system for modelling emissions control retrofits.

5.2 Control of 802 emissions With a sulphur emission limit of 400 mg/m3 mandatory in most European countries, at least 80% of the S02 would have to be removed from the flue gas of a unit burning I% sulphur coal. In Germany a minimum of 85% sulphur removal is specified as well as an emission limit of 400 mg/m3. A wide selection of processes have been used for S02 removal including wet scrubbers, spray dry scrubbers, sorbent

Flue gas outlet .--------1

Water ----- -1:~ f:====::::j

injection processes regenerable S02 removal processes and combined S02/NOx processes (Soud and Takeshita, 1994). Wet scrubbers can achieve an S02 removal efficiency in excess of 95% and are the most commonly used FGD system accounting for more than 80% of the installed capacity worldwide.

5.2.1 Flue gas desulphurisation scrubbers

The majority of the wet scrubbers are of the wet lime or limestone/gypsum variety. Figure 18 is a simplified flow diagram of a recent design.

In a typical plant, limestone is ground and mixed with water in a reagent preparation area. The resultant slurry (approximately 10% solids) is pumped to the absorber and sprayed into the flue gas stream. The slurry droplets absorb S02 from the flue gas and fall to the base of the absorber where they are collected in a reaction tank.

In Germany and Japan more than 90% of their coal-fired units with an electrical capacity greater than 250 MWe have been fitted with scrubbers. In the USA, the percentage of equipped units is lower (around 35% of coal-fired units with electrical capacity >250 MWe) but the total capacity is greater because of the USA's huge coal-fired generating capacity. Approximate data are: 89 GWe of equipped units in the USA, 33 in Germany and 17 in Japan (IEA Coal Research, 1997b).

A considerable number of wet scrubber systems were

Water -----.J

Fluegas~ inlet ~ L--J""

Air ----g--~

Limestone ----.I

71 71 71 71 71

Gypsum

Figure 18 Flow diagram of a recent type of wet lime/limestone wet scrubber system (Soud and Takeshita, 1994)

40

Flue gas treatment

Table 12 Total FGD orders in the USA (Institute of Clean Air Companies) (Smith and Dalton, 1995)

1992 1993 1994 1995

Utility 940.1 \01.7 271.7 88 Industrial 127.7 71.7 77.7 80

Totals \067.8 173.4 349.4 168

installed in the USA from the 1970s to the early 1990s. After 1992, with increasing availability of low cost, low sulphur coal and the falling prices of S02 allowances, the rate of installation of new wet scrubber systems declined (see Table 12).

Withum and others (1995) found that the costs (operating cost plus levelised capital cost) for new FGD installations were around $410 per ton of S02 removed. This assumed an inland site, a coal sulphur content of 2.5%, limestone forced oxidation wet FGD and a 250 MWe unit. Because of economies of scale, the cost for a 500 MWe unit was approximately $31 O/t. These costs were quoted by the authors in contrast with the costs of their 'Coolside sorbent injection process' for which the comparable costs were around $260/t and $300/t respectively. Klingspor and Bresowar (I 995a) quoted current costs for limestone FGD scrubbers in the range $250-4001t of S02 removed and compared this with a fuel switching cost of around $150-250 per tonne of S02 emission avoided.

The other alternative in the USA is to purchase emission allowances. The US EPA effectively set a cap on the price of an allowance to emit one ton of S02 at $1500. However, this has proved to be of only theoretical interest. In January 1995 allowances were trading at $100-105 each. In the April 1996 auction the average price bid for Phase I allowances was $68.14. With the cost of new installations to control S02 emissions around 2 1/ 2 to 5 times the cost of emission allowances it is not surprising that such projects are now rare in the USA. However, the cost of controlling emissions cannot be directly equated with cost of avoiding the need to control by purchasing emissions allowances. The latter strategy is attended by an element of risk. Regardless of the requirements of the CAAA 1990, communities may object to utilities buying a 'right to continued pollution of their neighbourhood' (Dalton, 1995). As in the case of Wisconsin (Corcoran, 1991), this dissent can be expressed by the enactment of local emission standards that may render S02 emission allowances unusable. The use of low sulphur coal might be a safer option and hence it has been argued that the fuel switching cost per tonne of S02 emission avoided is a better criterion for FGD economic competitiveness.

Scrubber manufacturers in the USA are therefore presented with the challenge to reduce the cost of S02 removal to the region of $250/t or less. Bresowar and Klingspor (1995) suggested that the range $240-400/t for eastern medium to high sulphur coal was a 'perceived cost' for wet scrubber retrofits. According to Klingspor and Bresowar (1995a), of ABB Environmental Systems, for a location in the USA, it is

feasible to construct an advanced wet scrubber with cost savings of 25-30% compared with conventional wet scrubbers. For boiler sizes over 550 MWe the total operating costs of advanced wet scrubbers are said to be competitive with the alternative of switching to low sulphur coal. It is assumed in the calculation of total operating costs that the utilisation factor is 65%. If a utilisation factor of 90% is assumed, with a 2.6% sulphur coal and 90% S02 removal, the advanced wet scrubber is said to be competitive with fuel switching at boiler sizes above 300 MWe.

Some of the wet scrubber systems installed in the I 970s and 1980s can be profitably upgraded. There have been considerable advances in the technology over the last 25 years. S02 removal efficiencies around 90% were typical for older installations but 95% or better is normal for newer installations (Soud and Takeshita, 1994). Of the existing wet scrubbers in the USA, nearly 23% were designed to scrub 90% or less of the flue gas when the unit was operating at 100% load (Froelich and others, 1995). Modifications to increase the capacity of these units could give increased sulphur removal at a modest incremental cost by allowing all of the gas to be scrubbed. For fully scrubbed units, increasing the efficiency of the scrubber allows the percentage sulphur removal to be increased or the quantity of sulphur emitted to be kept constant while using higher sulphur coal. Increased scrubber efficiency will increase the demands on the reagent preparation and by-product handling systems but, providing the original efficiency of the wet scrubber was around 80-90%, the increased loading will probably be within the original design margins (Weilert and Norton, 1992).

The reactions in the absorber and tank can be represented by the following simplified description:

I S02 + H20 ---7 H2S03 2 H2S03 + CaC03 ---7 CaS03 +C02 + H20

3 CaS03 + 1/202 + 2H20 ---7 CaS0 4.2H20

the S02 dissolves in the liquid phase forming sulphurous acid;

2 the sulphurous acid reacts with dissolved calcium forming calcium sulphite;

3 the calcium sulphite is oxidised to gypsum.

Factors affecting the rate of these reactions are:

slurry alkalinity is determined by the rate at which the limestone dissolves; if the concentration of S02 in the gas stream is high and the rate of dissolution of the limestone is too low, reduced alkalinity of the liquid phase of the slurry may reduce the rate of S02 absorption; gas phase mass transfer; the absorption of S02 requires intimate contact between the flue gas and the slurry droplets. If the concentration of S02 in the gas stream is low, the rate of S02 removal is likely to be determined by gas phase mass transfer (Dalton, 1995).

Optimising solution chemistry S02 removal in tower scrubbers depends strongly on the dissolved (liquid phase) alkali concentration of the slulTy as it

41

Flue gas treatment

enters the scrubber. The contribution of solid phase alkali to overall reactivity is small and is a function of the surface area of the limestone particles. Within the scrubber, dissolution of the limestone content of the slurry is too slow to replenish the dissolved alkali as it is consumed. Hence scrubber performance can be improved by measures that improve the solution chemistry within the scrubber.

Limestone selection may be an important factor if several sources are available. Weilert and others (1992) described commercial and technical factors in the selection of reagents. The reactivity of samples of limestone was assessed by chemical and petrographic analysis. They found that limestones containing a high proportion of fossils and/or pellets supported in a matrix of lime mud or calcite tend to have excellent reactivity.

Magnesium enhanced lime reagents have been found to give improved S02 removal efficiency and their use may be advantageous at locations where FGD gypsum is unsaleable. Each of the three 640 MWe units at Allegheny Power System's Harrison Power Station have been retrofitted with a single large scrubbing tower. The guaranteed S02 removal efficiency is 98% with three reagent recycle pumps operating. Each unit is equipped with a fourth, spare, recycle pump, spray header and waste slurry pump. With four recycle pumps in operation efficiencies in excess of 98% can be achieved (Walsh and Cirillo, 1995).

Solution chemistry may also be improved by grinding the sorbent more finely. Fine particles with their relatively large surface to volume ratio are more efficient as sources of solid phase alkalinity and more effective for replenishing liquid phase alkalinity. Figure 19 shows the results of pilot plant tests comparing results using nOlmally ground limestone (90% <44 Jlm) with results using finely ground limestone (99.5% <44 Jlm).

Limestone utilisation is also improved because coarse

,---------------------,-100100 -Utilisation

98 99for fine grind 96 98

94 97-J2,0

96 <3292Cij c'> 0 90 95 :§E a: Q)

88 94 ~ 586 93Utilisation

84 92for nor~rind 82 91• 80 90

5.0 5.2 5.4 5.6 5.8 6.0 6.2 6.4 pH

• 802 removal • Utilisation

Figure 19 Utilisation characteristics for normally and finely ground limestone (Klingspor and Bresowar, 1995b)

limestone particles make a small contribution to the reactivity of the slurry but a disproportionate contribution to the unreacted limestone passing out with the by-products (Bresowar and Klingspor, 1995).

Organic acid dosing The addition of organic acids to the FGD reagent slurry has been found to give significant improvements in solution chemistry and hence to improve S02 removal efficiency with minimal capital investment. In the early 1980s, in the USA, dibasic acid (a commercial mixture of succinic, adipic and glutaric acids which is usually called DBA) was added to wet scrubber systems to improve the S02 removal capacity of under designed systems. Interest in the use of organic acids was re-kindled in the USA following the passage of the CAAA 1990 as a relatively simple means of gaining bonus removal credits from systems that were already in compliance (Stohs and others, 1993). Chomka and others (1990) described the use of formic acid to buffer scrubber solution acidity in the pH range 4.2-4.5. Benefits claimed are:

increased S02 removal capability; better response to variations in flue gas flow and S02 concentration; high reagent utilisation (Ca:S ratio 1.01-1.03); reduced maintenance and greater availability due to a reduced potential for scaling and plugging within the equipment.

The by-product gypsum can be disposal grade or commercial grade.

Smolenski and others (1993) evaluated the options for upgrading an efficient existing wet scrubber to give exceptionally high (98%) S02 removal. In the baseline tests, S02 removal efficiency was measured as a function of recycle slurry pH, absorber liquid to gas ratio, and flue gas velocity. In the parametric tests, S02 removal efficiency was tested with DBA additive concentration, slurry recycle pH and flue gas velocity as variables. An EPRI computer model (FGDPRISM) was used to estimate S02 removal efficiency at conditions other than those tested. Actual and predicted data were used to evaluate the potential economic benefit of using DBA. They found that, with a reagent cost of $O.73/kg ($O.33I1b), DBA addition was cost effective if the marginal value of removing one tonne of S02 exceeded $55/t ($50/US ton). If the marginal value exceeded $165/t ($150/US ton), DBA addition was cost effective to a removal efficiency of more than 99.5%. As the percentage removal was increased beyond 99.5%, the marginal cost began to escalate rapidly. DBA addition did not appear to have any detrimental effect on wet scrubber operation and the gypsum by-product continued to meet wallboard specifications throughout the tests.

The 500 MWe Ghent Generating Station owned by Kentucky Utilities, USA, has been retrofitted with a wet scrubber system and organic acid dosing was used to increase the S02 removal efficiency. Removal efficiencies of 90% were standard when the decision to install a scrubber was made but Kentucky Utilities specified a higher removal efficiency to secure additional S02 allowances. The specification for the

42

Flue gas treatment

new wet scrubber required an S02 removal efficiency of 90% without acid addition and an efficiency of 95% with acid addition. Three reagents were considered as technically acceptable additives: adipic acid, DBA, and formic acid. Adipic acid was rejected because it would have needed a solids handling system. A liquids handling system was installed suitable for the storage and metered delivery of DBA or formic acid. Unit I of the station has been fitted with three 50% capacity absorbers. As part of Kentucky Utilities' overall compliance plan Unit 2 may be retrofitted by installing two additional absorbers with the two units sharing a common spare absorber (Ruppert and Mitchell, 1995).

Middlekamp and others (1995) described the highlights of a test programme by Hoogovens Technical Services. In cooperation with The Electricity Production Company for the Southern Netherlands (NV EPZ), they tested the use of adipic acid to improve the performance of an existing FGD system. The experiments were performed at NV EPZ's Amer power station. Amer 9 was selected; a 600 MWe plus 350 MWt, coal-fired, combined heat and power unit. Amer 9 is equipped with a single FGD scrubber tower which in normal operation used three of its four spray banks (one spare) to disperse limestone/gypsum slurry. Beneficial effects reported were:

94% desulphurisation was achieved with only two spray banks in operation. This gave a considerable reduction in net power consumption for the installation and may increase availability; operation of three spray banks gave desulphurisation efficiencies up to 97%.

The main adverse effect reported was that the chemical oxygen demand of the wastewater from the installation was 'considerably increased'. It was concluded the tests had been successful so far but that it may be necessary to adapt current wastewater treatment systems before adipic acid can be used in existing FGD installations.

Scrubber design Having optimised solution chemistry, the most obvious way to reduce the size and costs of scrubbers is to increase the gas velocity through the scrubber with a corresponding increase in the slurry recirculation rate so that the liquid/gas ratio is maintained. TIle effect of increased flow rate on scrubbing efficiency is complex. Carey and others (1995) reported that, above gas velocities of 3.7 mis, the S02 removal efficiency of an open spray tower remained constant as the gas rate was increased although the liquid recirculation rate was kept constant. Apparently the gas phase mass transfer characteristics improved sufficiently to compensate for the falling liquid/gas ratio. Klingspor and Bresowar (I 995b) found that, with a suitably designed nozzle system, as the gas tlow rate increased from 2.3 m/s to 4.3 m/s the liquid to gas ratio could be reduced by 32% while maintaining a constant S02 removal. Increased gas flow rate through the scrubber may allow a scrubber designed to serve a single unit to accept part of the gas from a neighbouring unit. Alternatively a unit may be retrofitted with a smaller, less costly scrubber. As well as reducing the cost per tonne of S02 removed, the net efficiency of the power station may also be improved.

Flue gas passes through the ducting to the scrubbers at relatively high speed. It is decelerated to pass through the scrubbers at a lower speed and is accelerated again into the ducting to the stack. This flow interruption causes back pressure and adversely affects the efficiency of the power station by increasing the 'in house' energy consumption. The effect is reduced by making the velocity of the gas through the scrubber as near as possible to the velocity of the gas in the ducting before and after the scrubber. Back pressure is also increased by sudden bends in the ducting. The aerodynamically ideal scrubber would be a straight section of ducting with no change in cross sectional area (the in-duct scrubber). This ideal is not achievable with current scrubber technology without compromising S02 removal efficiency. Designed gas velocity in the ducting is a compromise between the increased materials and fabrication cost for wide ducts and the increased fan and energy costs for driving gas through narrow ducts. Typically the velocity is around 15 m/s. For the older scrubber designs, the gas velocity through the scrubber was limited to 3 m/s by problems arising from increasing droplet entrainment as velocity increased. Since the scrubber is downstream of the ESP it is essential to control particulate emissions from the FGD scrubber. The problem of entrainment appears to be the controlling factor limiting the gas velocity through wet scrubber systems. Klingspor and Bresowar (I 995b) have suggested that improvements in mist eliminator performance may allow gas velocities up to 6.7 m/s for countercurrent tower scrubbers.

Wet scrubber design appears to be evolving at a rate that is relatively rapid for power station technology. Tn 1993 ENDESA, the Spanish electricity utility, began an evaluation exercise to select the most appropriate FGD technology to serve their Teruel power station. The station consists of three identical 350 MWe units that were commissioned in 1979 and 1980. They bum a mixture of indigenous lignite and imported low sulphur coal. The sulphur content of the blend is 4.5%. A Mitsubishi design was chosen. Figure 20 shows the arrangement of the absorber.

t Gas outlet

Mist eliminator Gas inlet

Absorber recirculation pump

Figure 20 Teruel FGD: absorber configuration (Lacarta, 1996)

43

Flue gas treatment

Gas inlet

D Mist

Absorber mist eliminator

eliminator

Spray pipe

Air rotary sparger Absorber Oxidation air blower

Absorber recirculation pump

Stack

Concentration tank

Gas entering the absorber passes down in co-current flow with the slurry from the first set of spray pipes and then up through grid of the counter-current section. The FGD system must achieve 95% desulphurisation with >95% availability between shutdowns which occur at intervals of three years. The main equipment contracts were awarded in 1994 and operation of the first FGD unit is scheduled for July 1988 (Lacarta, 1996).

While the ENDESA engineers were performing their assessment of commercially available FGD systems a more advanced Mitsubishi system was in its demonstration/commercialisation phase. Essentially this advanced FGD (AFGD) version of the Mitsubishi absorber has the grid moved to the co-current position beneath the first set of slurry pipes and no countercurrent scrubbing. Gas velocity through the absorber is around 6 m/s. This $151 million project, selected for demonstration in Round II of the US DOE's Clean Coal Technology Program, involved the retrofitting and the first three years of operation of a single AFGD module serving two coal-fired boilers. The US DOE contributed $63.9 million in support of the project (Coal and Synfuels Technology, 1996). The two units, located at Northern Indiana Public Service Company's Bailly station, have a combined generating capacity of 528 MWe. On 2 June 1992 the AFGD system began to process flue gas. In the first two years of operation the AFGD system demonstrated an availability of 99.99% and exceeded its design target of 95% S02 removal for all the coals tested while producing commercial grade gypsum. The sulphur content of the coals ranged from 2% to 4.5% (Manavi and others, 1995).

Figure 21 shows the arrangement of a further development of this process the 'double contact flow scrubber' (DCFS). This version dispenses with the use of a grid. The required gas/liquid interaction is achieved by the aerodynamicl hydrodynamic interaction between the descending gas and ascending 'fountains' of slurry. The 'gridless' open tower design, with only the distribution pipes and spray nozzles inside, simplifies construction and facilitates maintenance.

Special erosion resistant ceramic spray nozzles are an important feature of the design. Desulphurisation efficiency is said to be equal to that of conventional designs and the de-dusting performance is said to be superior. In 1994, the system was retrofitted to the coal-fired 175 MWe Shimonoseki No I unit in Japan. At full throughput an inlet S02 concentration of 1500 mg/m3 was reduced to an outlet concentration of 54 mg/m3 (96.4% desulphurisation) and an inlet fly ash concentration of 172 mg/m3 was reduced to an outlet particulate concentration of 7.5 mg/m3. The purity of the gypsum from the process was 96.9%. Figure 22 shows a simplified form of the DCFS fitted into the expanded base of a boiler stack.

The first wet scrubber plant based on this system was constructed in Weifang Chemical Plant, Weifang City, China, sponsored by the Japanese Ministry of International Trade and industry. Advantages claimed for the system are:

compact absorber combining the function of a (35 m tall) stack; small pressure drop; no booster fan required.

However, 70% S02 removal efficiency was acceptable for this application with an inlet S02 concentration of 1500 ppm and slaked lime absorbent (Iwashita and others, 1995).

Zawaki and Bengtsson (1996) described an in-stack wet scrubber located in the expanded bottom section of a slip formed concrete stack. The concrete absorber surface will be protected by a butyl rubber lining. The absorber bottom will have a layer of ceramic tiles on top of the rubber to protect it from mechanical damage during overhauls. The overall height of the stack will be 110m. Two units at Konin Power Station in Poland, each with a capacity around 85 MWe, are being fitted with the scrubbers for commissioning in 1997. Gas velocity through 5.7 m diameter flue is quoted as 15 m/s and hence the gas velocity through the 13 m diameter

Treated gas..

Figure 21 DCFS configuration diagram (Iwashita and others, Figure 22 In-stack wet scrubber system (Iwashita and 1995) others, 1995)

44

Flue gas treatment

Table 13 Performance data for Konin wet FGD (Zawacki and Bengtsson, 1996)

FGD inlet data Outlet Specification Limiting data coal coal

S02, mg/m' 4,520 5,017 225 S02 removal efficiency, % 95 Particulates, mg/m3 50 50 30 O2, % by volume 6 6 6

scrubber section is around 3 m/s. The performance specification for the scrubber is shown in Table 13.

The forced oxidation scrubber produces merchantable gypsum.

5.2.2 Sorbent injection processes

While conventional wet scrubbing is a highly effective technology for removing S02 it is also costly. The equipment occupies a large 'footprint' and retrofit applications can be substantially more expensive than FGD scrubbers fitted as original equipment. At some locations, a relatively small decrease in S02 emission rate would be sufficient to bring the boiler into compliance with current standards or would allow a wider range of coals to be used.

The injection of a slurry of finely ground limestone or dolomite into the upper region of the boiler gives a moderate reduction of S02 emissions. The heat of the flue gas calcines the sorbent to form lime and this reacts with the S02 and oxygen in the flue gas to form calcium sulphite and calcium sulphate. The partly sulphated sorbent and the fly ash are separated from the flue gas by the particulates control equipment. Unfortunately, a coherent layer of sulphate forms on the lime particles and inhibits further reaction. In consequence, sorbent utilisation is usually only around 15-18% of the injected calcium (Noguer and others, 1992). Clark and others (1995) described tests of a range of sorbents to reduce S02 emissions from a 180 MWe tangentially-fired boiler. Testing was conducted using an eastern US bituminous coal with a sulphur content of approximately 2.3%. Some of the results are shown in Table 14.

Capital investment for the system was relatively low at $81/kW for a 180 MWe boiler and an estimated $62/kW for a 300 MWe unit. Calcium utilisation was better than that obtained with limestonc injection but lime is usually more

Table 14 LIMB system: 802 removal efficiency (Clark and others, 1995)

Boiler throughput Sorbent CaiS ratio % S removal

FlIllload Hydrated lime 2: I 56 FlIllload Hydrated lime 2.5: I 63 Intermediate load Hydrated lime 2: I 60 Intermediate load Hydrated lime 2.5: I 67

expensive and consumption was still relatively high. In consequence, sulphur removal costs were high with a levelised cost of $859/t of S02 removed. The authors concluded that LIMB alone would be considered a 'niche' technology for units requiring moderate levels of S02 control.

5.2.3 Spray dry scrubbers

If sulphated lime particles are moistened, the lime hydrates and the particles burst exposing fresh surfaces for further S02 adsorption. This principle is exploited by spray dry scrubbers, the second most widely used technology after wet scrubbers. The largest unit using spray dry scrubbing is the Northern States Power Company's 810 MWe unit 3 (Maude and others, 1994).

The process is found in one of two main configurations. In US practice the spray dry scrubbing plant is usually located upstream of the main particle filter and the product is collected together with the fly ash. In European practice, the scrubber is generally located downstream of the main particle filter and an additional filter is provided to collect the product. This configuration is advantageous where the fly ash is used beneficially. In US practice, the flue gas enters a spray dryer/absorber, in which a slurry of lime and recycled reaction products including fly ash is atomised into a cloud of fine droplets. The droplets are dried, while absorbing the acid gases, to give a dry product which is collected together with the fly ash in the ESP or baghouse. The spray dry scrubbing process is most suitable for low sulphur coals. It was originally considered only suitable for low sulphur coals but its potential has been improved by better understanding of the technology. The product material is cementitious. If the flue gas humidity approaches too nearly to saturation, wet material deposits in the dryer hoppers and forms concretions. Hence, the maximum rate of slurry addition is limited by the need to keep the flue gas at least 10°C above its saturation temperature. The efficiency of the absorption process appears to be augmented by the presence of chlorides. The use of fabric filters rather than ESPs is also advantageous. Up to 25% of the S02 may be removed by passage of the gas through the absorbent cake on the filters. However, it has been suggested that the observation that ESPs do not remove S02 applies mainly to ESPs that are undersized by modern practice. The increased residence time in larger ESPs and the effects of 'clectric wind' may tend reduce any difference between ESPs and fabric filters in this respect (Heer and others, 1993). For high sulphur coals (2.4 -4% S), moderate to high chloride concentration and precise control of the flue gas adiabatic saturation temperature are needed if 90% sulphur removal is required (Keeth and others, 1991). The reaction products are mainly calcium sulphite with 25% or less of calcium sulphate. Hence the final product is a dry powder consisting mainly of fly ash, calcium sulphite and calcium sulphate.

Three power plants in western Denmark (at Studstrup and Fynsva::rket) have been equipped with spray dry scrubbers installed downstream of the ESPs. Table 15 presents performance data from tests of the system installed at Fynsva::rket.

45

Flue gas treatment

Table 15 Results from performance tests at Fynsvaarket, Denmark (Felsvang and others, 1995)

Seawater addition Yes No Inlet S02, mg/m3 4010 4020 S02 removal, % 96.5 96.8 ~T'C above saturation temp 14.1 10.6 Lime consumption, kg/h 4899 5502 Molar ratio, Ca(OH)2/S02 inlet 1.14 1.28

The system consists of two spray dryer absorber vessels followed by a pulse-jet fabric filter. The data show the beneficial effects of adding chlorides. The 'seawater makeup' contained 2-3% salt.

Downstream effects Spray dry scrubber systems use the sensible heat in the flue gas to evaporate the water content of the slurry. For maximum SUlphur removal they use as much of the sensible heat as possible by almost saturating the flue gas. Optimum operation also requires the presence of HCI in the flue gas and this is obtained by the use of high chlorine coal or by the addition of chlorides. These factors, together with the additional particulates loading, have implications for the performance of equipment downstream of the absorption vessels. Where the main particle collecting device is located downstream of the scrubber, the presence of the scrubber product increases the loading on the device. This detrimental effect is offset by a number of positive factors that tend to increase the efficiency of particulates collectors:

lower gas temperature; lower gas volume; higher moisture content; lower dust resistivity; increased dust cohesivity.

Landham and others (1992) tested a scrubber installed on a utility boiler burning low sulphur, low chlorine, Western USA, subbituminous coal. They found that, with a CaiS molar ratio of 1.4: I and an average S02 removal of 73%, the total particle mass exiting the scrubber and entering the ESP was 3.7 times that of the normal fly ash concentration. The majority of the particles produced were more than 5 I-lm in diameter. The performance of the ESP was generally good when collecting the scrubber product with average collecting efficiency in excess of 99.9%. Heel' and others (1993) also found that, on the whole, the performance of electrostatic precipitators was not adversely affected by an upstream spray dry scrubber. However, the accumulation of adherent dust deposits was identified as a possible problem. Secondary reactions between lime and HCI in the gas stream can lead to the formation of hard, adherent, deposits that are not dislodged by the normal rapping sequence. In one case a three-fold increase in rapping frequency was effective. In another case it was necessary to modify the discharge electrodes to enable them to withstand heavier rapping blows. Modification of gas flow control devices was also necessary to avoid blockage. A problem with corrosion of the electrodes, through the release of HCI, was solved by changing the material of construction of the electrodes to a

suitable alloy steel (C <0.03%; Cr 21-23%; Mo 2.5-3.5%; Ni 4.5-6.5%; Mn <2%; N 0.08-0.2%; P <0.03%; S <0.02%; Si <1%).

5.3 Control of NOx emissions Primary measures are the preferred method for controlling NOx. For lignites and brown coals primary measures alone have proved sufficient to achieve emissions below 200 mg/m3 from suitably equipped boilers. However, older boilers fired by hard coal are at a double disadvantage. As discussed in Chapter 4, the lower fuel ratio of the harder coals and the relatively compact furnaces used for firing hard coal make NOx control more difficult. For existing large (>300 MWe) boilers, selective catalytic reduction appears to be the only commercial technology that can guarantee NOx emissions below 200 mg/m3 and has the potential to meet further tightening of emission standards.

5.3.1 Selective catalytic reduction (SeR)

The term SCR describes a process for removing NOx by reaction with ammonia and oxygen in the presence of a catalyst. SCR has been widely applied in Europe and Japan. The term 'selective' in SCR implies that the catalyst promotes the desirable reactions that destroy NOx but does not promote the oxidation of ammonia to NOx or the oxidation of S02 to S03 (Hjalmarsson, 1990). In practice the oxidation of ammonia is minimised by the selection of a suitable temperature range and the oxidation of S02 is minimised by using a catalyst formulation that involves some compromise in catalyst activity. If excessive amounts of ammonia are used, or if the reaction is incomplete, ammonia will be present in the gas leaving the SCR module.

Ammonia slip The rate of ammonia injection is varied to give the required level of NOx emission. Provided that the catalyst area and activity are adequate this should be achievable without excessive ammonia slip. Excessive ammonia slip has a number of undesirable consequences affecting downstream equipment. Concretions may be produced in the air heater by the co-deposition of ammonium salts and fly ash. Ammonia may also appear in the waste water from the FGD scrubber. Depending on the type of coal and its preparation, 70% to 100% of the ammonia slip is absorbed by the ash. If the ammonia content of the ash exceeds 150 mg/kg, beneficial use of the ash may be compromised by a tendency to release free ammonia (see Section 6.2).

The main causes of an increasing ammonia slip are:

excessive ammonia addition; uneven ammonia distribution; catalyst fouling; catalyst deactivation.

Excessive ammonia addition may occur if two or more reactors are coupled in parallel and an automatic or manual control system attempts to control NOx at a common outlet. Different flows through the reactors may result in over dosing of the low flow reactor. For a single reactor over

46

70

Flue gas treatment

dosing may be the result of attempting to control NOx to a set point that is beyond the capabilities of the system. Hence, if the system was originally capable of achieving the required NOx reduction, excessive ammonia addition is likely to arise from system deterioration.

Uneven ammonia distribution may occur if, for example, some injection nozzles are blocked or if the flue gas flows preferentially through some parts of the catalyst assembly. If the local ratio of ammonia to NO x approaches or exceeds the stoichiometric value ammonia slip will occur regardless of the active catalyst area. Flow conditions may also encourage fly ash deposition within the reactor with a consequent reduction of the active surface area of the catalyst. In some cases flow conditions have contributed to particle impingement on the plates resulting in destruction of the catalyst by erosion. Schongrundner and others (1995) reported the results of the inspection of a 'honeycomb' SCR catalyst on a 330 MWe lignite-fired boiler after approximately 8000 h operation. A total of 160 catalyst elements in both layers of the first and second rows facing the boiler were eroded to the point that the honeycombs had holes through them. In addition, in the upper layer of the first and second layers, around 80% of the honeycombs were coated with dust. About 10% of the catalyst mass had to be replaced.

The catalyst may be deactivated through poisoning by elements present in the flue gas or the ash. The most important mechanisms are: arsenic poisoning, neutralisation of acid centres by alkali metals, the formation of thin layers

of CaS04, and silicon poisoning (Gutberlet, 1994). Arsenic concentration can be increased by a factor of 20 in slag tap furnaces with ash recirculation and this can cause rapid deactivation of titanium/tungsten catalysts. In this application titanium/molybdenum catalysts are said to give longer service life in spite of initially lower activity (Southam and Johnson, 1995). In Japan calcium poisoning was cited as the main cause of catalyst deactivation. The deactivation mechanism is thought to involve the deposition of CaO on the surface of the catalyst with subsequent sulphation to gypsum in situ (Kunimoto and others, 1990). For a given installation, the ammonia content of the fly ash appears to be a useful indication of the performance of the SCR plant and the state of the catalyst (Schneider and others, 1995; Schongrunder and others, 1995). In most cases the ammonia content of the ash rises steadily and its pattern indicates when remedial measures are necessary.

Conversion of S02 to S03 Excessive conversion of S02 to S03 may cause difficulties with air heater blockage and may also cause a blue plume on the stack especially when high sulphur coal is used. The plume is formed of a fine aerosol of S03 particles that are virtually unaffected by S02 scrubbers. The reaction between S03 and fly ash can be important in suppressing this plume. For older design bituminous coal fired plants retrofitted with an SCR system, tests have shown that 80-90% of the gaseous S03 content is precipitated out in the air heater if the temperature profile through the heater is suitable (see

Figure 23) (Miiller-Odenwald and others, 1995):

-------,, , ,, , ,

FGD system GGH StackBoiler Catalyst Air Electrostatic GGH preheater precipitator

ME OJ E

~35~~~~~~ GGH = gas/gas heat exchange

Figure 23 503 concentration from boiler to stack - bituminous coal firing (MUlier-Odenwald and others, 1995)

47

Flue gas treatment

Optimum S03 removal in the air heater depends on achieving the lowest flue gas outlet temperature that is practicable without causing water to condense on the air heater elements. If condensation occurs the heater rapidly becomes fouled with adherent deposits.

Experiences with this early SCR plant illustrate some of the principles and problems of SCR operation. One of the first industrial scale SCR de-NOx plants in Germany has been in operation since 1985 (Gutberlet, 1994). Most SCR units have been installed in the high dust region after the economiser and before the air preheater. At this location the flue gas temperatures are in the range required for efficient SCR operation (320--400°C). Figure 24 shows the location, and indicates the scale, of a high dust SCR unit which was commissioned in 1986 at the 720 MWe Heilbronn Unit 7 in Gemlany.

The boiler was actually commissioned without the SCR units which were hastily retrofitted to comply with impending German legislation on NOx emissions (Maier and others, 1992). The flue gases (2,300,000 m3/h stp dry) pass through two reactors arranged in parallel. Each reactor contains 413 m3 of catalyst material arranged in three layers. The pressure drop across the SCR plant was around 750 Pa. The original design provided for the installation of a fourth catalyst layer if needed. Primary measures control the NOx at the inlet of the SCR plant below 800 mg/m3 and the plant is required to maintain the outlet NOx below 200 mg/m3. The NOx content is controlled by varying the rate of ammonia addition.

When Heilbronn Unit 7 was commissioned, the NOx reduction was around 80%. The ammonia slip in the flue gas was approximately 1.0 ppm (by volume) and the ESP ash contained around 50 ppm (by weight) of ammonia. S02 to S03 conversion was around 2.2%. After 18,000 h operation

I I I

I I I I

Bdiler I I I I I I I

I I I I I I

I I

Flue gas

DENOXreactor

I I I

I I I

Ir-rF=---- I I r

r=~::::±~:::::;:T::::;::<=;:;r==;:;r==;:;:I--"--"Tl I _ _ ~ _ ~

Figure 24 High dust SCR arrangement at Heilbronn Unit 7 (Maier and others, 1992)

the ammonia content of the ESP ash increased to 100 ppm indicating a decrease in catalyst efficiency. It was found that this loss was mainly due to fouling of the catalyst surface. The first catalyst layer was replaced and soot blowing facilities were improved. In July 1993, after about 36,000 h operation, the ammonia content of the fly ash began to increase again peaking around 150 mg/kg by November. As palliative measures the NOx emission control concentration was increased from 160 mg/m3 to 190 mg/m3 and higher ash coal was used. A fourth layer of catalyst was installed during the Christmas/New year shutdown. Subsequently the ammonia content of the fly-ash decreased to <10 mg/kg. With four layers instead of three the pressure loss increased, as would be expected, from about 750 Pa to 1000 Pa and the S02/S03 conversion rate increased from 2.1 % to 2.7% (Schneider and others, 1995).

Retrofitting SCR to an existing plant is a substantial undertaking. Osterreichische Draukraftwerke' s Voitsberg No 3, 330 MWe, lignite-fired generating unit was retrofitted with an SCR plant in 1990. Technical data for the plant are given in Table 16.

The additional load of approximately 2.000 t was shared by the boiler support structure and the boiler house facade with additional reinforcing (Schongrunder and others, 1995). Both the Voitsberg No 3 boiler and the Heilbronn Unit 7 boiler are tower boilers where it was possible to retrofit the SCR equipment at a location which would be occupied by the second pass of a two pass boiler. For some units, apart from cost considerations, the layout of the existing boiler may be so congested that it is impossible to find space for a full scale SCR system between the economiser and the air heater.

5.3.2 Selective non catalytic reduction (SNCR)

SNCR is a technology that offers the possibility of reducing NOx without major structural alterations to the boiler or flue gas ducting. An aqueous solution of a reagent, ammonia, urea or cyanuric acid, is injected into the upper part of a boiler. Decomposition of the ammonia or other reagent in the presence of oxygen produces free NH2 radicals which react with the NOx:

4NH3 + 02 -7 4NH2 + 2H20 NH2 + NO -7 N2 + H20

The main factors influencing the completion of these reactions in SNCR are temperature, residence time and ammonia concentration. The optimum temperature range is 850--1050°C. The minimum residence time is 0.1 seconds and 0.4 seconds or more is preferred (Fujino and others, 1995). The high temperature used for SNCR causes conversion of some of NH3 to NO, N2 and water and hence the required ratio of NH3 to NOx is 2: I rather than the I: I implied by the equations. Unreacted NH2 radicals form NH3 at the boiler economiser outlet which can react with acid species to form salts. Ammonium salts may contaminate the ash and may cause fouling of downstream equipment. These undesirable effects can be avoided by limiting ammonia slip

\ \ I " \ I I

\II

48

Flue gas treatment

Table 16 SCR plant: specification and technical data ( Schongrundner and others, 1995)

Full load Minimum load

Flue gas volume, stp Flue gas temperature NO, upstream of SCR as NOz NO, downstream of SCR as NOz Ammonia slip after 16,000 h operation Pressure drop (2 layers) Plant dimensions (L x B x H) Catalyst producer (I icenced by) Number of layers Type of catalyst Pitch Volume of catalyst (2 layers) Mass of catalyst Total weight of SCR assembly Space velocity Area gas velocity, stp Linear velocity, stp Linear velocity without catalyst

1,150,000 m3/h 750,000 m3/h 330°C 290°C 450 mglm3 650 mg/m3

::5150 mg/m3

::54 mg/m3

::5600 Pa 13.7mx 17.9mx 19m Porzellanfabrik Frauenthal (Mitsubish Heavy Industries) I dummy layer, 2 active layers, I spare layer Ceramic honeycomb 7.4 mm

3-400 m-270 t -2000 t 3300 m3h- 1/m 3 (hi) 7.7 m3h- 1/m z (mh- I )

6.1 m/s 4.0 m/s

to less than 10 ppm at the economiser outlet (Jones and others, 1995b). In practice this results in the use of a ratio of reagent to NOx with a stoichiometry of around 1.5: I and gives a maximum reduction in the NOx emission rate of around 50%. Since the temperature profile through the boiler varies with boiler load, the effective injection position should be varied with boiler load for optimum performance. This can be accomplished by providing alternative injection sites or by installing nozzles that can be rotated to change the direction of injection. The distribution and mixing of the reagent over the cross section of the boiler is critical to system performance. All of these parameters can be optimised for steady state operation but cunent state of the art control systems may allow excessive ammonia slips when the boiler load varies.

Montaup Electric Company operates a 112 MWe tangentially-fired boiler in Somerset, MA, USA. The boiler is equipped for coal- or oil-firing. Technology requirements (RACT) promulgated by the Commonwealth of Massachusetts obliged Montaup Electric to retrofit their boilers limiting NOx emissions to 0.38 lb/million Btu (467 mg/m 3) or less when firing coal. They evaluated the merits of low NOx burners, SCR and SNCR as control systems. SNCR using aqueous urea solution was selected. The key issues determining the choice were capital and operating cost and performance guarantees over the entire load range from 35% to 100% of boiler maximum continuous rating (MCR). Four injection zones were needed to achieve the required pelformance over the entire load range. A total of 28 solution injectors were installed. Nineteen used existing furnace openings and the nine new openings were provided during a two week planned outage. The system was commissioned and the process guarantees were met. Figure 25 shows the relationship between NO x reduction and ammonia slip at MCR.

At MCR, attempting to achieve NO x reductions in excess of 50% may result in an ammonia slip of more than 10 ppm.

Uncontrolled NOx emissions at full load were typically around 800 mg/m3 (0.65 lb/million Btu) and hence compliance could be achieved with a slip of less than 10 ppm. TIle worst case condition for the boiler is at 80% of MCR where uncontrolled NOx emissions can exceed 1100 mg/m3 (0.9 lb/million Btu). Testing showed that under these conditions, even if a high ammonia slip were tolerated, compliance would be uneconomic because of the high urea dosing rate required. However, the NOx emission rate can be reduced to 0.63 lb/million Btu by adjustment of furnace air distribution. The SNCR system was designed to load follow and maintain NOx emissions compliance over the load range but control loop uses data from the stack CEM system and this causes a lag in the SNCR system response. TIle system consistently stabilises at or below compliance emission rates but it takes about 30 minutes to fully adjust to a major load transient. During this process excursions of high NOx or high ammonia slip may occur. It is anticipated that the installation of in-duct analysers would reduce the response time to seconds (Staudt and others, 1995). Table 17 shows an ammonia slip excursion during a load reduction at New

11

10 9

0 ! 0

8 JD E c. c. .9. v;

'"'c 0 E E «

7

6

5

4

3

!: ;

I f

i

/o I /,£ o::J 0

;~ I I 0

,//

~~~~ I I I I I

0 10 20 30 40 50 60 NOx reduction, %

Figure 25 Montaup Electric: full load NH3 slip versus NOx reduction (Staudt and others, 1995)

49

Flue gas treatment

England Power Service Co's No 2 unit (MCR 84 MWe) at Salem Harbour, MA, USA.

During this test urea dosing was held constant while the unit loading was reduced from 68 MWe to 38 MWe and then adjusted to the normal ratio when the low load condition had stabilised. The differences between the ammonia concentrations at the economiser outlet and at the air heater outlet were taken to indicate ammonium bisulphate deposition at high slips and the release of ammonia as the slip was reduced.

The cost of the fully installed system for Montaup Electric's relatively small boiler was in the range $15-16/kWe. Under full load conditions the cost of the reagent (50% aqueous urea) was around $770-970/tonne of NOx removed; around

1.1-1.3 mils/kWh. Jones and others (l995b) quoted a similar capital cost for a 120 MWe unit with economies of scale reducing the cost for 250-750 MWe units to around $10-7/kWe. Urea is a more costly reagent than ammonia but ammonia is a hazardous chemical; it is highly toxic and can form an explosive mixture with air. The use of urea saves the cost of preparing and implementing risk management plans (Jantzen and Zammit, 1995).

5.3.3 SNCRISCR hybrid systems

The reduction of NOx emission rate achievable by SNCR appears to be limited to around 50% by the problem of ammonia slip. Since SCR also uses ammonia there is the possibility of adding SCR to an SNCR system to use the ammonia slip and further reduce NOx emissions. Ozone

Table 17 SNCR ammonia slip measurements at Salem Harbour No 2 during a load reduction (Frish and others, 1995)

10.20 am 11.30 am 1.50 pm 2.55 pm

Load, MWe Urea flow, Uh Injector location Air heater ou tlet temperature, DC

NH3 ppm at economiser outlet NH3 ppm at air heater outlet

North South

83 765 Upper 260 255 66 25

45 756 Upper 262 255 104 47

38 806 Upper N/A 255 47 91

38 208 Lower N/A 255 10 19

SNCR - Selective non catalytic reduction

Furnace Steam

4 Injectors 1 Elevation

Static mixing

grid

Ammonia

/

NH3 injection

grid -===-+-

Expanded duct

Guide vanes

71 \~ SCR

catalyst banks

Air heater with hot-end

catalyst sectors

Precipitator

Stack

CSCR - Selective catalytic reductionJ Figure 26 PSE&G Mercer in-duct SCR and SNCR test locations (Wallace and others, 1995)

Pumping skid

50

Flue gas treatment

concentrations in the state of New Jersey, USA, are in excess

of the National Ambient Air Quality Standard. An inventory

of emissions determined that Public Services Electric and Gas Company (PSE&G) power plants were the source of 27% of NOx emissions within the state. PSE&G committed themselves to reduce NOx from their power plants by 60% by 1995 and 80% by the year 2000. They fitted SNCR at their Mercer generating station in NJ, USA but, following

demonstration of the system in 1993, it was concluded that the NOx reduction was insufficient. SCR would have given the required reduction but the congested design of the Mercer boilers did not allow space for a conventional SCR installation. Figure 26 shows the hybrid design that was selected for testing.

One of the horizontal ducts between the economiser and the

air preheater was expanded to three times its original cross section to accommodate the catalyst which was also installed in the hot end of the Ljungstrom air preheater. The static mixing grid indicated in Figure 26 was installed because the flue gas velocity at the ammonia grid was skewed by a factor of about 3: 1 across the duct. This prevented the target NH3/NOx distribution being achieved even with some valves

of the ammonia grid fully open and others nearly closed. The static mixer reduced the flow bias to less than 2: I.

The 320 MWe slag-tap boiler which was the subject of the

tests burns low sulphur bituminous coal with natural gas available for startup and as a secondary fuel. Tests were conducted using coal and gas at four nominal outputs: 310, 220, 135 and 80 MWe. Major findings were:

SNCR accounted for up to half of the total NOx reduction. The tests confirmed the role of SNCR for retrofit applications where space is severely limited and primary measures are insufficient; soot blowing was found to have a large effect on NOx emissions and SNCR ammonia slip, indicating a significant effect on fumace exit temperature; the results of the tests indicated that the flue gas temperature at the rear wall injection location was slightly low for optimal SNCR using ammonium hydroxide solution. Options for further optimisation of the SNCR system were identified that can achieve more than 50% NOx reduction; with 40% removal by SNCR the ammonia slip before the

catalyst was 150 ppm; an overall NOx removal of 90% was obtained with an ammonia slip after the air heater of less than 2 ppm; S02 to S03 conversion was moderate averaging 1.7%. The impact of the conversion rate was mitigated because the S03 was removed from the gas stream by reaction with calcium in the ash to form relatively benign calcium sulphate; the average pressure drop from the economiser to the air heater inlet, due to the mixer, the ammonia grid and the catalyst banks, was 800 Pa (3.2 inches waterguage) at full throughput. The existing fans are capable of accepting the increased load. Twice daily soot blowing of the catalyst banks was sufficient to maintain the pressure drop at this lower than expected value (Wallace and others, 1995).

5.3.4 The relative merits of SCR, SNCR and hybrid systems

SCR is the most widely used system for post combustion NOx control. The first plant on a coal-fired unit started operation in 1980 and by 1990 SCR had been installed on nearly 40 GWe of coal-fired capacity. SNCR, the next most

popular system, was installed on approximately 1.5 GWe of

coal-fired capacity. Some advantage and disadvantages of SCR, SNCR and hybrid systems are shown in Table 18.

SCR is an effective and widely used system for controlling NO emissions. With the potential to reduce NOx emissionsx by more than 90% it allows compliance with the most rigorous standards. Given sufficient space, the main objection

to the adoption of SCR appears to be financial although, for SCR in the high dust (hot side) location normally selected, there may also be some degree of commercial risk in using

the system with some high sulphur coals and as described in Section 5.3.1, catalyst deactivation may be a problem for slag tap furnaces with ash recycle. Selection of the low dust location, after the ESP and FGD, would present a lower technical risk but is generally ruled out for dry bottom boilers

Table 18 Advantages and disadvantages of flue gas NOx reduction systems

Advantages Disadvantages

SCR Highly effective High capital cost

for reducing NO x; Hazardous reagent

up to 95% (NH3 or NH40H)

reduction Increased pressure

Established drop from boiler to

technology in a stack number of Coal-specific countries problems of catalyst

poisoning and air heater foul ing

SNCR Relatively low High operating cost

capi tal cost due to high reagent Can be retrofitted consumption where space is NOx reduction

insufficient for generally limited to

SCR -50% by ammonia

Low pressure drop slip Can use relatively Control problems in

benign urea load following solution as reagent operation rather than NH3 Limited experience;

possibility of air heater fouling

Hybrid Achieves the Additional complexity

environmental Hazardous reagent performance of needed for SCR SCR with a section smaller space Overall, greater requirement and reagent usage than

smaller pressure SCR drop. Limited experience;

possibility of air heater fouling

51

•• •

Electrical field

Particles attracted

Flue gas treatment

on cost grounds. Frey (1995) estimated that the capital cost for low dust SCR system for a 480 MWe unit would be $130/kW (1993 US dollars) with a revenue cost of 4.5 mils/kWh. For the same size unit, he estimated that the capital cost of a hot side SCR would be around $60/kW. The quoted range of uncertainty in the estimate was around $25/kW with a 30% probability that the cost would be less than $60/kW and hence a 70% probability that it would be more. The annual revenue cost was estimated to be 2.1 mils/kWh. Comparing these costs with the estimates by Jones and others (l955b): $8/kWe anu 1.2 mils/kWh respectively for SNCR, the cost advantage of the SNCR option where moderate NOx emission standards apply is clear.

The advantages of hybrid systems are less apparent. There can be large variations in the concentrations of NOx and NH3 at the economiser outlet. These variations can be caused by load transients but may also result from varying heat exchange in the boiler through successive fouling and soot blowing cycles. Flow distribution over the cross section of the ducts may also be uneven. In consequence the adjustment of NOx has to be controlleu by ammonia injection after the SNCR zone and before the SCR zone. Hence, additional complexity is introduced and the need to use ammonia for the SCR section negates the benefit of using a more benign reagent for the SNCR section. It appears that the applications for hybrid SNCR may be limited to retrofit installations where high performance is needed and space is a major constraint.

5.4 Particulates control New standards for the control for S02 emissions, with CEM requirements for particulate emissions, have implications for the operation of particulate control equipment. US utilities, affected by the Phase I requirements for reduced S02 emissions, tended to equip large, base loaded units with FGD and change to low sulphur coal for the smaller and usually older units. Further tightening of S02 emission limits as the second phase of the CAAA is implemented may pose further difficulties for units that comply by switching to even lower sulphur coals (Wolniak, 1992). Many of these older units

Collector .......... electrode -...... at positive

polarity

Flue

•••gas flow

••!

Uncharged particles

to collecting electrode and forming dust layer

have pre-NSPS electrostatic precipitators that are inadequate for treating the higher resistivity particulates from lower sulphur fuels. The new regulations require performance to be monitored during transients and off-design operating conditions and this may increase the difficulty of compliance (see Sections 3.3 and 3.5).

5.4.1 Electrostatic precipitators: factors affecting their performance

The horizontal flow plate type electrostatic precipitator is widely used in the electric power industry. The operating principle of these devices is described in Figure 27. The gas stream flows between a number of earthed, parallel plates. Electrodes are suspended midway between the plates and insulated from them. The electrodes are energised to the highest negative potential that is sustainable without causing sparking. Typically this occurs at around 50 kV. The electric field between the electrodes and the plates polarises the gas in the vicinity of the electrodes liberating positive and negative ions and some electrons. The positive ions are immediately captured by the electrodes while the negative ions and electrons are accelerated towards the plates. This 'corona discharge' process causes the characteristic blue corona glow that surrounds the electrodes. Large particles (diameter >2 11m), passing between the plates, collide with the negatively particles, acquire a negative charge themselves, and are driven by the electric field to the collector plates (bombardment charging). Small particles are poorer targets for bombardment and are mainly charged by diffusion or field charging processes. For most power plants the fly ash consists mainly of particles with diameter >2 11m and hence bombardment charging is dominant (Parker and Novogoratz, 1992). A particle subjected to bombardment charging attains 80% of its limiting charge in 100 I1s (Darby and Novogoratz, 1993). The particles arriving at the collector plate are held by their electric charge and by adhesion. From time to time, the plates are mechanically shaken (rapped). The vibration detaches the accumulated layer of particles anu they fall into the collecting hoppers.

An ESP is sized to meet a required particulate collection

Discharge electrode at negative polarity

Clean gasexit

Figure 27 Particle charging and collection within an ESP (Stultz and Kitto, 1992d)

52

Flue gas treatment

efficiency. The Deutsch-Anderson equation relates the total collecting area to the collection efficiency and the gas flow rate:

A= V.ln.[_I_] w l-E

Where: A = collecting surface area, m2

E = particulate removal efficiency, % wtJwt V=gas flow rate, m3/s w = particle migration velocity, mls.

For design purposes, a value is usually assumed for the migration velocity w (the theoretical average velocity of the charged particles towards the collecting surface). It is normally assigned on the basis of empirical experience with similar systems (Stultz and Kitto, 1992d).

The efficiency of an ESP may be defined in terms of the specific collecting area (SCA) required to remove a given percentage of the pmticulates from gas at a given flow rate. For collecting efficiencies in excess of 99.5%, SCA is usually in the range from 60 m- 1s to around 200 m- ls depending on the properties of the fly ash. Hence, an ESP with a SCA of 60 m- I s may prove to be undersized if unanticipated operating conditions are encountered while more generously sized precipitators may provide more scope for optimisation. It may be seen by inspection of the Deutsch-Anderson equation, that the SCA required for a given collection efficiency is inversely proportional to the migration velocity of the particles. The migration velocity is affected by the field strength, particle size and particle charge. The field strength is affected by the electrical resistivity of the layer of particles. If the resistivity of the particles is too high, the layer may accumulate an intense negative charge between rapping cycles. This can produce a corona discharge from the collector into the dust layer (back corona) and a reverse current of positive ions flows from the dust layer to the electrodes. Back corona can substantially reduce the efficiency of the ESP. If the field within the dust layer becomes sufficiently intense, sparking initiated within the dust layer can cross the collector/electrode gap. Electrical breakdown then occurs and the supply voltage has to be interrupted to extinguish the electric arc. Back corona cannot be eliminated by more frequent rapping because the interval between rapping blows is important in controlling re-entrainment; a layer of agglomerated dust has to be collected on the plates to facilitate efficient transfer from the plates to the hoppers (Darby and Novogoratz, 1993).

ESP efficiency may also be affected if the electrical resistivity of the particles is too low. This is most marked if the low resistivity is combined with low dust cohesivity. Figure 28a shows the effect that particle resistivity can have on precipitator size and Figure 28b shows the effect of the cohesivity factor.

For high resistivity dusts the field in the dust cake exceeds the electric field in the gas stream and the electrostatic force on the dust cake is compressive. When the dust resistivity is low, the electrostatic force is negative tending to dislodge the dust which is then only held to the collector by cohesive

forces. For a low resistivity dust the force of repulsion could range from 0.06 to 0.4 Pa while for a high resistivity dust the compressive force would be an order of magnitude higher (Porle and others, 1992). Cohesive forces are more than sufficient to retain the particles under ideal conditions but particles may become re-entrained by the gas flow through aerodynamic scouring. Hence there is an optimum range for dust resistivity from approximately 1010 to 1011 ohm em. Coal ashes with bulk resistivities greater than 5x 1011 ohm em are difficult to collect. Ashes with a bulk resistivity less than 109 ohm em can also be difficult to collect if they combine low resistivity with low cohesivity. Ash with a high carbon content (high loss on ignition) may fall into this category. A

a) 280

240

c: o t5 ~ o 200 u

'if~o-;-'" Cl'l",

~.s 160 0-.. -N ""OE ~ '5

~ 120 <I: o (/)

80

40 --l-----r------,,------,,------,,-----,--

8 9 10 11 12 13

Log resistivity. Ohm _em

b)

140 c:

U o

~

"8 120

60

40 --11---,-----'I---TI---TI--~I~--

o 2 3 4 5

Cohesive force, N/m 2

Figure 28 a) Effect of resistivity on precipitator size b) Effect of cohesivity factor on precipitator size (Feldman and Kumar, 1992)

53

160

Flue gas treatment

manifestation of this problem is the occurrence of opacity 'spikes'. The operation of the ESP rappers causes material to become re-entrained and the dust emission peaks briefly.

The collecting efficiency of an ESP decreases with increasing particle loading and with decreasing mass median diameter (mmd). Increasing particle loading reduces the particle migration velocity because a dense cloud of negatively

a)

140 c o U ~

"8 120

80=360

40 -j---,-------,------r------,-----,-- o 2 4 6 8 10

Mass median diameter microns

b)

70

« o Cf)

60 -F-----,---,---.---------,-----r--- 10 20 30 40 50

Inlet concentration, 91m3

Figure 29 a) Effect of particle size distribution on precipitator size b) Effect of particulate space charge on precipitator size (Feldman and Kumar, 1992)

charged particles creates a space charge that inhibits corona emission at the electrode (Feldman and Kumar, 1992), Since the charge is carried on the surface of the particles and smaller particles have a higher surface to mass ratio, the effect of increased loading is greater for smaller particles. For normal flue gas conditions a minimum in collecting efficiency occurs at an mmd of approximately 0.3 Jlm. A precipitator collecting particles with a mmd of 5 Jlm at an efficiency of 99.6% would theoretically only have an efficiency of 63% for particles with a mmd of 0.5 Jlm but the collection efficiency for 0.05 Jlm particles is around 98%. These effects are shown in Figures 29a and 29b.

For the more typical situation where there is a wide range of particle sizes entering the precipitator some size fractions are collected more efficiently than others. For typical flue gas conditions, with an overall collecting efficiency of 99.9%, the minimum collection efficiency occurs at about 0.3 Jlm and has risen to around 98% at 0.05 Jlm (Feldman and Kumar, 1992).

5.4.2 Optimising ESPs

It has been said that it might be considered fortunate for the US electrostatic precipitator industry that its first attempts to collect fly ash took place in the eastern part of the USA (Ferrigan and others, 1992). The sulphur content and ash composition of the coals then used in the eastern USA are now know to have been important factors that contributed to the success of early ESPs. During combustion, the sulphur in coal is converted mainly to S02 but also, in low concentration, to S03 (see Section 2.1.3). S03 and moisture in the flue gas form sulphuric acid (H2S04) at the air heater outlet temperatures. The acid is adsorbed onto the ash particles and reduces surface resistivity. The presence of H2S04 also tends to increase the cohesivity of the dust. Hence a reduction in the sulphur content of the coal can lead to back corona problems from high resistance and re-entrainment problems due to reduced cohesivity.

The favourable properties of the local coals allowed the utilities in north eastern America to achieve adequate control of particulates using ESPs that were sized assuming SCAs around 60 m-Is. In 1988, Ontario Hydro's power station in Lambton Canada switched from using West Virginia and Pennsylvania coals having a sulphur content of 2.4% to coals from the same locations having sulphur contents less than I %. The switch was effective in reducing sulphur emissions from the plant but it had an adverse effect on particulates control. Particulates control was compromised for two separate reasons: the S03 content of the flue gas was reduced and the carbon content of the ash increased. The latter effect was due to the lower grindability and the reduced heating value of the new coal. In consequence, the pulverisers were overloaded and the fineness of the PC deteriorated. Immediately after switching, the 500 MWe Lambton units had on occasions to be derated by as much as 170 MWe to avoid exceeding opacity limits. The most obvious solution to problems arising from a lack of H2S04 is to inject 503 upstream of the ESP in the expectation that it will react with the water vapour in the gas stream. This was partially successful at Lambton. The fly ash resistivity was reduced

54

Flue gas treatment

from 2 x 1012 ohm cm to 4 x 107 ohm cm. The low resistivity after treatment was due to the high carbon content of the ash. TIle injection of S03 allowed the plant to operate at full load but, although the opacity levels were acceptable, they were not ideal because of emission spikes caused by dust re-entrainment during rapping (Amott and others, 1990).

The simultaneous injection of S03 and ammonia has been advocated as a solution to a number of problems encountered using S03 alone. Dual flue gas conditioning is said to counteract collection efficiency losses due the following three causes:

high resistivity ashes which require excessive quantities of S03 to obtain acceptable resistivity at the operating temperature. A few US coals and some Gondwanaland coals are difficult in this respect. Coals with this characteristic are recognisable by their high silica and low alkali contents: excessive rapping and re-entrainment losses resulting from high gas velocity and low aspect ratio ESPs, as well as some of the effects of inadequate rapping systems; reduced collecting efficiencies arising from the presence of unburnt carbon in the ash (Ferrigan and others. 1992).

For some coals, an excessively high concentration of S03 is needed to give the required collection efficiency. TIlis effect was exacerbated at high flue gas temperatures because the equilibrium, between water vapour and S03 on one side of the equation and H2S04 vapour on the other, is strongly affected by flue gas temperatures. Figure 30 shows this dependence.

Since free S03 does not react with ash as quickly as H2S04, higher temperatures will cause increasing amounts of S03 to pass through the precipitator (Wright and Woracek, 1992). The emission of an excessive amount of S03 in the flue gas

~

:5 0 Q. C1l >

0" (f)

N I en C1l

U C ::J 0 .0

0(')

(f)

25

20

15

10

5

0 50 100 150 200 250 300 350

Temperature, °C

Figure 30 Equilibrium between S03 and H2S04 versus temperature (Wright and Woracek, 1992)

is undesirable and causes a visible blue plume to form on the stack.

The temperature of the flue gas after the air heater and before the precipitator can be reduced by spraying water into the flue. The addition of sufficient water to increase the water vapour content of the gas from 4.8% to 9.2% would result in evaporative cooling of the flue gas from 150°C to 90°C. The opposing effects on flue gas volume of the additional water vapour and reduced temperature would give a net decrease of around 8%. The major hazard attending water injection is the formation of hard accretions of ash through inadequate water atomisation. However, the development of reliable systems for flue gas humidification has been advocated as an option for improving particulate control (Bush, 1995).

Krigmont and others (1992) reported that the performance of ESPs could be optimised by the injection of an equimolar mixture of S03 and ammonia. Tests with Texas lignite showed that while S03 injection was effective at 121°C, excessive quantities would be required at 1630C. A combination of ammonia and S03 created a conditioning agent that was not subject to a temperature limit and effectively reduced ash resistivity while increasing ash cohesivity. Ammonia addition equal in ppmv to the S03 addition was most effective for reducing resistivity. Adding ammonia at twice the S03 rate was less effective. These results were said to lend some credibility to the speculation that the conditioning medium was ammonium hydrogen sulphate.

Computer programs can predict the resistivity of a given fly ash, as a function of SO.., feed rate, at selected gas temperatures. This allows a programmable logic controller to automatically select optimum SO.., feed rates for maximum precipitator efficiency. Figure 31 illustrates a control logic combining precipitator and opacity signals for automatic S03 trim control.

Precipitator power consumption is sensitive to fly ash resistivity. Before there is any indication on the stack opacity meter, declining power consumption and more sparking indicate increasing fly ash resistivity and the need to increase the SO.., injection rate. However, successful trim control relies on slow response to avoid over controlling in response to opacity spikes or small variations in precipitator power consumption (Wright and Woracek, 1992).

Sodium conditioning has also been used to improve the perfOimance of ESPs when low sulphur, low alkali, high silica coals are used. Dry sodium sulphate or sodium carbonate is distributed on the coal before the pulverising mills. The sodium compound decomposes in the furnace and Na20 deposits on the fly ash particles. It was found that:

sodium conditioning of low sulphur eastern USA coals such as Coal Inc, Minnehaha, and Shand, can produce low resistivity ash at temperatures of 180°C or higher; problems with ash fouling and cleanliness in the boilers, which might be expected to arise from sodium conditioning, were avoided by maintaining the ash Na20 concentration at 3% or less;

55

Flue gas treatment

Under Overconditioned conditioned

B c

A

A Resistivity level Precipitator power consumption

Opacity meter Autofeed response

Optimum Optimum Optimum Maintain feedrate

B Resistivity level Precipitator power consumption

Opacity meter

High Below optimum Increased emissions

Autofeed response Increase 803 feedrate

c Resistivity level Low Precipitator power consumption

Opacity meter Above optimum Increased emissions

Autofeed response Decrease 803 feedrate

Figure 31 Automatic 503 trim control (Wright and Woracek, 1992)

sodium addition did not appear to cause any increase in fouling or ash buildup in the ESPs.

The technique is said to offer relatively inexpensive capital costs and 'reasonable' operating costs (McDonald and others, 1992).

Energisation modifications The addition of ash conditioning agents is designed to overcome the problems of back corona and ash re-entrainment by modifying the properties of 'difficult' ash. The alternative approach, of modifying the energisation waveform has also been used successfully. Conventionally, precipitators are energised by monophase, full wave rectification of ac current to produce a dc voltage with double frequency ripple superimposed. Figure 32 is a simplified representation of a typical energisation circuit.

The amount of power supplied to the ESP in any half cycle is controlled by feedback signals of primary voltage and current and secondary voltage and current. The primary circuit includes the control rectifiers (CR) and a current limiting reactor (CLR). The automatic voltage control system controls the power through the primary circuit by 'firing' or 'gating' the CR at the proper time during each half cycle (Weaver and others, 1992). The function of the control circuit is maximise the mean voltage across the ESP without causing excessive sparking. The earliest precipitators used analogue controllers. Generally, power is increased until a spark occurs, power is then turned off to extinguish the spark and re-energisation of the precipitator is controlled through a variety of spark recovery adjustments. The primary adjustment parameter is spark rate. Typically a rate is set that is thought to be optimum for the particular ESP. The CLR has two main functions; to limit the potentially damaging increase in current when sparking occurs and to modify the shape of the voltage and current waveforms in the precipitator field. The

former function essentially protects the CR stack and the transformer/rectifier (TR) set. The latter function affects the efficiency of the ESP. The ESP acts as a capacitor and hence the varying voltage from the TR set appears as a dc voltage across the ESP with a superimposed ripple. The more nearly sinusoidal the waveform from the TR set the smaller the ripple voltage in relation to the dc voltage and hence the higher the mean voltage that can be maintained without excessive sparking.

Improvements have been made on the analogue control system just described by the use of microprocessors. In addition to monitoring voltage and current values, such systems can accumulate data and modify their reactions by analysing trends. The system is able to predict when sparks are likely to occur and prevent a significant proportion from occurring. Back corona can also be detected and power levels reduced until it no longer exists (Weaver and others, 1992). Daub (1996) described the principles of an improved algorithm for detecting and overcoming back corona. The method traditionally used relies on analysis of the relationship between average precipitator voltage and average precipitator current. The presence of back corona is indicated when the relationship between these parameters, which is normally proportionate, becomes inverse. Daub's algorithm is based on the increase in the electrical resistance/capacitance behaviour of the ESP. When spark over occurs under back corona conditions the trough value of the ESP voltage, compared with its voltage before the spark, is higher during several periods of the mains frequency. The back corona detector is activated at selected time intervals, typically every 15 minutes, and pelforms the comparison described. If back corona is indicated the controller changes from dc energising to intermittent energising. This is accomplished by using the CR to suppress, two out of three half waves. If back corona is still present after the next time interval the off time is increased by two half periods. If back corona is absent the unit returns to dc operation.

The Aghios Dimitros power station in Greece comprises four units with a total capacity of 1220 MWe. The precipitators were retrofitted with microprocessor based controllers to replace the existing analogue control system. The primary reason for fitting the new equipment was to reduce the dust emissions which were exacerbated by the high resistivity of the fly ash. Following the modifications the dust emissions were reduced by 25% and, through intermittent energising, the power consumption of the precipitators was reduced by 90%: from 2435 kW for the four units to 245 kW (Daub, 1996).

Ente Nazionale per I 'Energia Elettrica (ENEL) of Italy is currently engaged in upgrading the performance of their ESPs to ensure that, by the end of the 1990s, the particulate emissions from all their power stations will be below 50 mg/m3. The ESPs in operation on their large (320 and 360 MWe) units belong to three generations:

first generation plants, at rated throughput, have designed SCAs of around 50 m-Is, a gas velocity in the range 1.5-2.3 mis, a plate spacing of 228 or 254 mm. The plates are 7~ 10m high;

56

I

Flue gas treatment

Current limitingSCR stack reactor----------,

(CLR) Transformer rectifier (TR) setI r-----------------I I I II

L - 1 -------'I-+-Ie e+-...l..-------'ry"V"'V'~..__r___o

I

I

L - 2 --------t--+-------pt..-:>J.'-"t-----'I-----<t-----!--------J

Automatic voltagecontrol

Figure 32 ESP power supply system (Johnston, 1992)

second generation plants have designed SCAs of around 90m- 1s, four electric fields, a gas velocity of 1.2 mis, spacing of 300 mm and plate height of 14 m; third generation plants have a SCA of 135 m- Isand seven electric fields in series.

Efficient dust collection requires the highest possible charge on the particles coupled with the highest sustainable electrostatic field. In order to induce the largest possible charge on the ash particles it is necessary to apply as high a voltage as is possible. In normal ESP operation this is achieved by accepting an incidence of sparking. Another mode of energisation, that is reported to be effective for high resistance ash, uses high voltage short duration, pulses imposed on a steady dc voltage. However, with pulse energising, providing that the duration of the voltage pulse is sufficiently short, the particles can be charged and the voltage reduced before a spark discharge has time to be generated. Hence the periodic collapses of collecting voltage and mechanical re-dispersion of collected dust are avoided. The steady dc voltage, provided by three phase rectification. is set at a level below the onset of sparking and close to the onset corona value. The tunable pulse frequency rate should be below 20 Hz, depending on the type of fly ash. The pulse voltage should be 'left free to evolve to obtain a voltage close to the spark value' (Dinelli, 1990). Rea and Bogani (1992) quoted a pulse duration between 50 and 300 ).lS but, after further development, a pulse duration of around 10 ).lS has apparently been selected (Trebbi and Padera, 1995). The pulse energisation technique was pilot tested at ENEL's

Primary A current meter

(AG)

Automatic voltagecontrol

I

I I L _

Secondary current meter

(DC)

Signal resistor

Marghera power station using a side stream ESP and on a 35 MWt industrial boiler. The encouraging results led to full scale tests at ENEL's Sulcis Unit in Sardinia, Italy. Table 19 shows the results from the industrial ESP.

The results showed that it was possible to reduce emissions by around 85-90% when high ash resistivity South African coals were used. With the lower ash resistivity, low sulphur American blend emissions were reduced by more than 50%. The subsequent full scale tests on the 240 MWe Sardinian unit confirmed the previous results with a decrease in outlet emissions from 120-'190 mg/m3 to 38-50 mg/m3. The other significant result of the testing was a decrease in energy consumption to values that are three to five times lower than those required for conventional energisation alone and around 10% of those needed when S03 conditioning was applied (Trebbi and Padera, 1995).

Independent work on pulse energisation has been performed at The Commonwealth Scientific and Industrial Research Organisation (CSIRO) in Australia. Paulson and others (1993) assessed the efficiency of a laboratory scale ESP under conventional, intermittent and pulsed energisation. They found that, for an ESP efficiency of 99.4%, the SCAs required were in the ratios 1 : 0.55 : 0.41 respectively. For much shorter pulses than those used by ENEL (200 ns with a rise time of 100 ns) the minimum pulse frequency for optimum efficiency was 50 Hz. The experiments were performed using an Australian bituminous coal. The fly ash resistivity is not quoted but an SCA of 80 m2kg- 1s was

I I

I

I

Voltagedivider

Secondary current meter(-)

(DC)V

(+ )

Precipitatorfield

Signalresistor

57

Flue gas treatment

Table 19 Experimental results of narrow pulse energisation tests: industrial ESP (Trebbi and Padera, 1995)

Conventional energisation Narrow pulse energisation Coal Flue gas, DC SCA m-Is

Efficiency, Emission, Power, Efficiency, Emission, Power, % mg/m3 kW % mg/m3 kW

South Africa AMCOAL* -175 140 97.36 -330 55 99.61 2 10 AMCOAL* -140 150 97.90 -285 99.80 10 GEN.MIN* -170 140 98.13 -170 52 99.77 -20 10 TCOA* -170 140 98.81 -160 42 99.82

US low S blendt -170 90 99.25 -50 22 99.68 -20 7

Fly ash electrical resistivity: * 1-6 x 1012 ohm cm t 4-7 x 1011 ohm cm

quoted to achieve a collection efficiency of 99.4%. Given a flue gas temperature of 120°C this would approximately convert to an SCA of 80 m-Is for an efficiency of 99.4% indicating that the ash resistivity was in the optimum range.

Extreme examples of high resistivity fly ash are encountered with fluidised bed furnaces and so it is conventional to use bag filters in such applications. Actually particles are present with a range of resistivities but the high carbon content, low resistivity particles are preferentially collected in the first fields of the ESP. The high resistivity of the remaining material adversely affects the pe!i'ormance of subsequent fields. Noguchi and Sakai (1993) found that, for Chinese, Australian and Japanese coals, the ash in the outlet hoppers of their ESPs normally has resistivities in the range 1012 to 1013 ohm cm. Experimenting with the ESP at the Wakamatsu 50 MWe atmospheric fluidised bed combustor (AFBC) demonstration facility they found that a pulse energised ESP was effective with these difficult ashes. On the basis of the encouraging results, a pulse energised ESP was specified for the Takehara 350 MWe AFBC. Noguchi and Saki (1993) used a pulse duration of 100 /ls. The pulse frequency was not stated.

ESP efficiency may also be increased by using a variable inductance CLR (VI-CLR). A fixed value CLR can be sized to provide optimum performance at one operating point of a power supply. However, if the power delivery is required to vary, the optimally sinusoidal waveform to the precipitator can only be maintained if the CLR has a different inductance at each operating point of the power supply. As the power level of the precipitator supply is reduced the amount of inductance required to maintain optimum performance increases. Advantages claimed for a VI-CLR in comparison with a fixed CLR out of its optimum range are:

increased efficiency of the precipitator power supply producing an increased power output; reduced total harmonic distortion; increased average voltage before spark-over occurs with consequently increased particulates collection; minimisation of the destructive effects of sparking, especially when operating below rated limits when the impedance of the VI-CLR is highest (Johnston, 1992).

5.4.3 Wet ESPs

Although the concentration of particulates in the flue gas may be greatly reduced by passage through a wet scrubber, the remaining concentration may still be considered excessive at sensitive locations. Near large cities in Japan for example, particulates emissions from coal-fired power stations are required to be below 10 mg/m3 to match the performance of oil-fired power stations. The gas stream from the FGD contains sulphate mist and submicron sized dust. Wet ESPs have been used as the final measure to control particulate emissions for both oil- and coal-fired power plants.

In the dry ESP, a layer of dust forms on the collecting plates and is periodically detached by mechanical agitation of the plates. In the wet ESP, no layer is allowed to form, the collecting plates are washed by a continuous stream of water and the dust is removed as a slurry. As a result of the different principle of dust collection and removal wet ESPs are said to have the following advantages and disadvantages.

Advantages: the collecting performance is independent of dust resistivity; there is no dust re-entrainment even at high gas velocities; higher gas velocity, and lower hopper angles facilitate the design of more compact installations; reliability is enhanced because there are no moving parts; the device is effective for collecting sub-micron particles and S03 mist.

Disadvantages: It is necessary to reduce the gas temperature below the dewpoint; high SOx concentrations cause problems; high dust concentrations cause problems; a waste water stream is produced; effective corrosion protection is required (Fujishima and Tsuchiya, 1993).

Wet ESPs have been used mainly in the Japanese metals industries. The first utility boiler plant wet ESP was installed in 1975 for an oil-fired unit. Figure 33 shows the layout of

58

FGD

Flue gas treatment

Fl GGHeatW ~ '''hooge' Boiler Air GG Heat Dry ESP

heater exchanger

Figure 33 Coal-fired boiler with wet ESP: process units (Fujishima and Tsuchiya, 1993)

flue gas treatment units for a coal-fired installation with wet ESP.

The first wet ESP installation for a coal-fired utility power station in Japan was at the 265 MWe Yokosuka unit of Tokyo Electric Power Co in 1985. The wet ESPs were also installed, in 1991, 1992 and 1993 for units 1,2 & 3 (3 x 700 MWe) of Chubu Electric Power's Hekinan power station. All units are reported to be operating according to specification and controlling emissions at 10 mg/m3 or less (Fujishima and Tsuchiya, 1993).

5.4.4 Fabric filters: baghouses

As described in Section 5.4.2, the particulates produced by some US and Gondwanaland coals present problems for ESP operation. In Australia, particularly in New South Wales, it was often found that conventional ESPs were unable to perform adequately when new and their performance generally deteriorated with age. This deterioration was accelerated by the need for frequent water washing (Robertson and Strangert, 1992). Hence, a series of trials were made to assess the effectiveness of bag filters for controlling particulate emissions.

The specific cleaning capacity of bag filters is usually expressed in telms of air/cloth (A/C) ratio; the number of m3

Operating cycle

Damper closed

-Gas outCollected cake

-

1-+--+-1_---+---- Anti-collapse -----+----.(...,,-~ ring Released cake

Gas in 'Air' out

Thimble

\ 1"'1-,-...

n4o-l.----- Damper open •

of gas per second that can be filtered through each m2 of fabric. Two main types of fabric filter are generally in use; low ratio reverse air and high ratio or pulse-jet filters. Figure 34 shows the arrangement of a reverse-air, low ratio

filter.

During the operating cycle gas flows through the fabric and a layer of dust builds up on the bags and the pressure drop across the bag increases. The flow is briefly reversed for the cleaning cycle. The reverse flow collapses the bag and discharges the dust deposits into the collecting hopper. For utility applications the term reverse-air is a misnomer. The 'air' is actually flue gas. The first fabric filters suitable for use at boiler flue gas temperatures used relatively delicate fibreglass cloth and a correspondingly gentle cleaning cycle was necessary to give adequate bag life. Reverse-air units are characterised by low ratios of the order of 0.01 m/s. With the development of more robust bags, made from felted synthetic fabrics, it was possible to achieve higher ratios through the use of more aggressive bag cleaning methods. Reverse air with mechanical shaking (shake/deflate) gave more effective cleaning but this type of system has generally not demonstrated the bag life expectancy of pure reverse air units (Singer, 1991). Pulse-jet filters, which use brief blasts of compressed air to clean the bags are amongst the most compact particulate control devices per unit of flue gas flow. They are specified with ratios of around 0.02 mls. By 1992,

Cleaning cycle

Reverse 'air' in

__ Damper closed

Figure 34 Schematic arrangement of a reverse-air filter (Singer, 1991)

59

Flue gas treatment

300 pulse-jet fabric filters had been installed on utility and industrial boilers throughout the world (Soud, 1995).

Following the successful retrofitting of a baghouse to a small PC-fired boiler in 1972, the Electricity Commission of New South Wales, Australia, converted a series of progressively larger boilers. In 1978 they undertook the construction of a new power station of 4 x 660 MWe units. Six further units, at two other sites, gave a total capacity of 6,600 MWe base load units with low ratio baghouses. The Commission also has a total of 2700 MWe of capacity fitted with pulse jet baghouses. The case of Munmorah power station exemplifies the high ratio refits.

As a result of high maintenance requirements and particularly poor performance from the ESPs of the 350 MWe units at Munmorah plant it was decided to replace the internals of the precipitators by fitting fabric filters into the casings of the existing ESPs. The ESPs were somewhat undersize for their 'difficult' coals, with a SCA of 77 nr's which is near the lower end of the range conventionally used. Hence, relatively little space was available to accommodate the new bag filters. This dictated the choice of high ratio pulse jet filters which typically require 40% less plan area than the low ratio filters (Miller and others, I992a) and the plan area was further reduced by using 7.2 m long bags. The specification for the work called for a maximum filtration velocity of 0.02 m/s at the maximum expected gas flow of 480 m3/s at 140°C and an overall pressure drop of 2.5 kPa at maximum flow. New ID fans, with inlet and outlet silencers were included in the scope of the contract. The tender that was accepted guaranteed a bag life of 27,000 hours and a maximum emissions guarantee of 50 mg/m3. The inlet dust burden for all cells is in the range 12-21 g/m3 with an average in the range 16-19 g/m3. After the retrofit the plant appears to have performed well and met its guarantees. Although some problems occurred they did not result in load restrictions. When bag life reached 20,000 h, tests indicated a remaining life of a further 20,000 h (Robertson and Strangert, 1992).

5.4.5 Flue gas conditioning for fabric filters

Flue gas conditioning using S03 and ammonia has been reported to increase the efficiency of bag filters. Advantages claimed are:

particulate emissions are substantially reduced; a more porous dust cake is produced leading to reduced pressure drop; the dust cake remains on the surface of the fabric and is prevented from seeping and packing into the fabric structure causing blinding; the dust is discharged from the bags in larger agglomerates which more readily fall into the hopper instead of being recollected on the bags (Miller and others, 1992b).

Trials to assess the effectiveness of flue gas conditioning were conducted at Texas Utilities' Monticello power station. The station operates with a number of ESPs and baghouses that operate in parallel. Low ratio shake/deflate baghouses were designed to take 80% of the boiler exhaust but, because

of higher than expected pressure drops and after-cleaning opacity spikes, they were only taking about half of the boiler exhaust. A pilot injection system was installed into No 1 baghouse. The injection of S03 and ammonia began on the ninth of December 1990. The pressure drop across the baghouse immediately started to decline and the flow through the baghouse increased indicating an increase in dust cake permeability. At the same time there was a fall in baseline opacity from the baghouse and opacity spikes gradually began to decline in amplitude, a decline that continued for a couple of days. Conditioning continued until June 1991. Throughout the test period the baghouse responded immediately to the loss of ammonia or S03 with an increase in opacity and pressure drop. In every case performance was restored to the level before the interruption when the injection of conditioning agents resumed. The results of the trials led Texas Utilities Electric to solicit bids for the installation of conditioning systems for units 1 and 2 of the Monticello Station (vann Bush and others, 1992).

Flue gas may also be conditioned by electrostatically charging the dust. Figure 35 shows two orthogonal sections through a particle charging, pulse jet baghouse. Flue gas enters the lower section of the baghouse and passes through a corona discharge before meeting the bags. As with chemical conditioning, the process is said to reduce both pressure drop and fines emissions by hindering penetration of the fabric. In consequence, the baghouse can be operated at a higher air to cloth ratio, fewer bags are needed and the size of the housing is reduced. Helfricht (1992) compared the costs for a conventional baghouse having an A/C ratio of 0.02 m/s with

On stream flow

Row cleaning

r-t---.,>"'I-_ On stream

Ba~ housmg

Inlet

Hopper

High voltage to grid

Figure 35 Example of a particle charging baghouse (Helfricht, 1992)

60

Flue gas treatment

those for a baghouse with an electrical conditioning unit and an AlC ratio in the range 0.03 to 0.05 m/s. For estimating purposes it was assumed that the capital and operating costs of the conditioning unit would be similar to those for an ESP with a SCA of 10 m-1s. Figures 36 and 37 show that, in comparison with the conventional baghouse with an AlC ratio of 0.02 mis, both capital and operating costs are reduced for the electrically enhanced cases.

EPRI have developed a system which exploits this principle. The compact hybrid filter (COHPAC) is claimed to offer savings of up to 60% in capital costs when upgrading existing ESPs. Two versions are offered: COHPAC I is a pulse-jet baghouse (PlB) downstream of an existing ESP. COHPAC II is a PlB retrofitted into the final field of an ESP. As well as imparting an electric charge to the particles the ESP, or the remaining fields of the partly cannibalised ESP, wi]] remove a significant amount of the fly ash from the flue gas. The combination of low ash loading and charged

2.4

2.2

2

1.8 (/)

~ 1.6 (5 D c 1.4 '2

1.2E ti 0 0 0.8 EJ '6. 0.6 co

0 0.4

0.2

0

- Housing. Charger EI2l Bags

Figure 36 Capital costs of conventional and electrically enhanced baghouses (Helfricht, 1992)

600-,-------------------------, [10 ~ (5 D 500 D c co (/)

is 400 -5

ca ~ 300

~ ~ 200 o OJ c .~ 100

~ o o

4 6 8 10 Air to cloth ratio

4 6 8 10 Air to cloth ratio

mil Fan power • Charging [£] Comp air • Bag replace

D Maintenance & operating D Capital recovery

Figure 37 Yearly operating costs of conventional and electrically enhanced baghouses (Helfricht, 1992)

particles will allow the PlB to operate at higher than normal AlC ratios with moderate pressure drop.

The COHPAC I concept has been tested at fu]] scale in the form of a demonstration baghouse designed to accept 25% of the flue gas from a 575 MWe boiler firing lignite coal. The PlB has eight compartments and is sized to filter a total flue gas flow of 350 m3/s at 196 ± 17°C at an A/C ratio of 0.08 m/s with one compartment off-line for maintenance and one off-line for bag cleaning. The mass concentrations at the inlet of the baghouse ranged from 0.1-0.3 g/m3. The mmd of the particles was 5.8 !J.m. The outlet emissions were 12 mg/m3 with a mmd of 4.5 !J.m. Outlet opacity (six minute and 1 h averages) was normally below 2%. In the first 1000 h the pressure drop across the bags increased as they 'seasoned' and developed an equilibrium layer of fly ash. After 1000 h, the pressure drop stabilised. At an A/C ratio of 0.08 m/s the pressure drop was 1.4 to 1.5 kPa. The COHPAC I was tested for a total of 3762 hours over a six month period. The failure of a few filter bags near the end of the test contributed to an increase in the outlet opacity to 3.5% (Chang, 1995).

5.4.6 FGD wet scrubbers and the fortuitous removal of particulates and trace elements

The wet FGD scrubbers described in Section 5.2 also remove particulates. It has been suggested that a limestone/gypsum scrubber could be sufficient as the only particulates control measure. However, the large volume of solids entering the scrubber might compromise its original function and where merchantable gypsum is produced it would be heavily contaminated by ash. A power station in Finland was equipped with open tower FGD scrubbers downstream of inefficient ESPs. With inlet dust loadings to the scrubbers around 324 mg/m3 the process was adversely affected by the combined effect of ash particulates and HF acid gas. The resulting problems were resolved by upgrading the ESPs to reduce the scrubber inlet particulates concentration to approximately 200 mg/m3 (Siikavirta and Kouvo, 1995).

Where there is already an efficient ESP in operation, a wet scrubber can further reduce the fly ash loading of flue gas (McIlvane, 1992). Various accounts have been given of the efficiency of wet scrubbers as particulate control devices. References to the particulate collecting properties in literature from the USA are usually oblique. McIlvane (J 992) suggests, that since US regulations stipUlate that opacity is measured directly after the ESPs, the subsequent collection of particulates by a scrubber is usually considered irrelevant. A number of authors refer to the dust removing properties of scrubbers as a problem in contro]]ing the quality of the gypsum by-product. The removal by the scrubber of 'up to 70% of the fly ash that escapes the electrostatic precipitator' was anticipated in a report on the wet scrubber for the B L England generating station NJ, USA (Wiggins and others, 1995). The 1000 MWe No I unit of Sinichi Power station has the largest coal-fired boiler in Japan. TIle advanced wet scrubber fitted to this unit includes a pre-scrubber after the ESPs to remove 'dust and soluble gases such as HCl and HF'

61

Flue gas treatment

(Hirao and others, 1995). In common with the previous paper, the main preoccupation was with the quality of the gypsum. However, the designed flue gas dust emission of the plant was quoted as <20 mg/m3 and the actual emissions were said to be less than 10 mg/m3.

Chemical analysis shows that the particulates emitted from a wet scrubber are different from those entering the scrubber. A series of tests were performed over three days and nights at Gelderland power plant in the Netherlands. The collection efficiency for particulates was 99.9% in the ESP, 90% in the limestone/gypsum scrubber and 99.99% for the whole combination. The analysis of the particulate matter sampled after the scrubber was -40% ash, -10% gypsum and 50% droplets of water saturated with gypsum. As was found at the Sinichi power station, the concentration of particulates downstream of the wet scrubber was less than 10 mg/m3

(Mcij, 1994).

The Chiyoda CT-121 Clean Coal Technology project at Georgia Power's Yates plant in the USA, features a 100 MWe S02 absorption module called the jet bubbling reactor (JBR). The $36 million project is co-funded by the US DOE, EPRI and Southern Company Services. The process was effective in its primary purpose consistently giving S02 removal efficiencies greater than 90% with 98% removal achieved under certain conditions. However, another objective of the demonstration was to assess the performance of the JBR as a combined particulate collector and S02

removal device. With the upstream ESP de-energised, problems were encountered with ash agglomeration in the JBR. With partial energisation of the ESP to provide 90% particulates removal the agglomeration problem was solved. Under these conditions analysis of the inlet and outlet streams from the JBR indicated that nearly 100% of the particulate >10 /lm and 90% of the material in the 1-10 /lm range were removed. There was no significant net removal of material <1 /lm but analyses and materials balances suggested that the majority of the outlet particulates could be sulphuric acid aerosol produced through cooling of gaseous S03 in the scrubber. As a result the net low particulate removal in the submicron range might result from a combination of ash removal and acid mist generation within

the JBR.

As discussed in Section 2.1.7, trace elements are associated mainly with the ash but some are also partitioned between the solid and the vapour phase. The reported removal of 99.99% of fly ash particulates, would greatly reduce emissions of the non volatile and condensing trace elements. The emission of class III elements (see Table 3) are not removed by ESPs but in a wet FGD plant, B, Br, CI and I are largely removed and more than half of the F, Hg and Se. The limestone input to FGD plants contains substantially more heavy metals than are contained in the gas stream input but they leave in the gypsum, sludge and waste water (Meij, 1994).

62

6 Residue considerations

Processes for optimising the abatement of atmospheric pollution may result in an increased production of solid by-products. In optimising abatement technologies due regard has to be paid to possible effects on the quantity ancIJor marketability of the by-products. Hence, the selection of abatement technologies needs to be co-ordinated with market research and development programmes and operating parameters may be restricted by considerations of by-product quality control.

6.1 FGD by-products The imposition of tighter S02 emission standards has led to a considerable increase in the production of CCBs. The need to dispose of these products is a major consideration in the selection of FGD processes.

The limestone/gypsum process is the most widely used technology. However, a few countries in Europe have equipped a significant proportion of their capacity with the spray dry scrubbers (see Table 20).

6.1.1 FGD gypsum Although the product of many limestone gypsum scrubbers is sent to landfill, the popularity of the lime/limestone gypsum process is in part due to the potential marketability of the product. However, the realisation of this potential involves a considerable marketing and development effort. In the 1970s the rapid installation of FGD plant in Japan resulted in a large surplus of FGD gypsum. By 1980 this stockpile amounted to more than 11 million tonnes, more than a full years demand for gypsum. Combined Government and private initiatives reversed this supply/demand pattern and now the emphasis is on developing more valuable products. An interesting consequence of the success in using gypsum in Japan is the emergence of a recyling problem as the amount of gypsum from demolished buildings increases. In 1995 gypsum board was being removed from demolished buildings at the rate of 400,000 tonnes per year and it is anticipated that this will have increased to an annual rate 1.44 million tonnes by the year 2000 (Nagata, 1995).

Table 20 Breakdown by method of power station desulphurisation capacity (post-combustion measures) (Kolar, 1995)

Austria, 1993

Denmark,

1993 Germany, 1993

Central* Local-I-Sweden USA,

1990

OECD,

1987

Proportion of power station capacity with FGD, % 60 32 100 94 26

Breakdown of FGD capacity, %: Lime/limestone scrubbers SDA process

Dry processes (non-regenerative) Regenerative processes Others

54.9 41.7

3.5

52.7

37.3

10.0

90.2 7.0

2.5 0.3

68.2

28.2 0.6

3.0

100

77.8

9.6

3.1

9.5

84.6

9.0 0.9 2.4 3.1

* Central stations -j- Local coal-fired CHP stations

63

7

Residue considerations

6.3

(ij (IJ >

6

5 4.9

I

I

Qi0 4 m (IJ 3.2 c c .9

3

c ,g 2 ~

0 1992 1996 2000

Year

Figure 38 FGD gypsum production in Germany (Kirchen and Morgenroth, 1996)

Figure 38 shows the growth in FGD gypsum production in Germany since 1983. By 2000 German production of FGD gypsum will have nearly doubled in comparison with 1992 due to new FGD installations in the eastern part of Germany.

In the Czech Republic power production is coal intensive and depends predominantly on the use of high ash, low calorific value brown coal. It is estimated that by 1999 annual ash production will be 9.1 million tonnes which is equivalent to almost one tonne per capita. All of their power stations will have been equipped with FGD and consequently, in addition to their tonne of coal ash, each inhabitant of the Republic will have available approximately 170 kg of gypsum (Peleska, 1996).

With the current German market for gypsum already fully supplied, and increasing quantities being produced by neighbouring states, new markets for this material will have to be developed (Kirchen and Morgenroth, 1996). The need to dispose of such large tonnages dictates the exploitation of bulk markets. Unfortunately prices per tonne in such markets tend to be low and the low value limits the potential for exploiting distant markets. In consequence CCBs may be virtually unsaleable from some locations because of local competition from readily available minerals. For example the north east part of Spain has been said to be one gigantic limestone and gypsum quarry and hence there is no commercial outlet for FGD gypsum in that area (Lacarta, 1996).

The Netherlands Agency for Energy and the Environment (Novem) conducted a survey to identify potential European markets for FGD gypsum. Applications considered were:

plaster board; plaster impregnated fibre board; plaster blocks; cement setting retarder; self-levelling floor screeds.

In a method of floor construction used in the Netherlands and elsewhere, a smooth surface is provided by a screed of sand, cement and water 30-50 mm thick. The levelling of this screed is labour intensive and arduous. A self levelling floor

screed can be made using a mixture of calcium sulphate anhydrite, sand and water. In addition to its self levelling properties, the new screed suffers less shrinkage when setting and the resultant membrane has superior dimensional stability and greater resistance to bending. Novem estimated that self levelling floor screeds represented a potential market for 7 million tly of FGD gypsum (Moonen, 1991). In Germany, self-levelling floor screeds are being produced using the a-hemihydrate of gypsum. The [3-hemihydrate is used in the manufacture of plasterboard and other building applications but the use of the hemihydrate was formerly limited to specialist applications by high cost. It is claimed that, using the ProMineral process, large scale production of high quality a-hemihydrate is economic. A full scale a-hemihydrate production plant has been running since 1993. A second plant is being erected in eastern Germany and one or two additional plants are planned (Kirchen and Morgenroth, 1996). Hence, the marketing of increasing quantities of FGD gypsum presents considerable difficulties but utilities appear to be meeting the challenge.

6.1.2 Sorbent injection and spray dry scrubber by-products

Processes that involve injecting a sorbent before the main ESPs or fabric filters inevitably result in the sorbent becoming mixed with the fly ash. Hence the problem is the disposal of an augmented quantity of fly ash contaminated with sorbent. In the case of sorbent injection into the furnace, with only 20-30% utilisation of the sorbent, the partly spent sorbent might easily outweigh the ash. spray dry processes, where partly spent sorbent and ash is recycled, give much better sorbent utilisation particularly if the ash is naturally alkaline. However, a mixture of sorbent and ash is unsuitable for most of the markets that have been found for PC ash. If the ash is separated from the gas stream before the scrubber, the ash is suitable for the usual markets and the spent sorbent is virtually free of ash. In that case, the product is a white, fine grained, dry powder consisting mainly of calcium sulphate, calcium sulphite and unreacted lime. ELSAM, the association of western Danish utilities, conducted a comprehensive research and development programme aimed at finding beneficial uses for spray dry scrubber product. Relevant properties are:

sulphur content; chloride content; slaked lime content; physical form (fine, white granules); moisture absorption (hygroscopic); disinfectant (sulphite and lime content); low heavy metals content.

The investigation ruled out applications for cement and concrete because of the deleterious effects of the sulphur and chloride content. In view of the sulphur content and the low heavy metals content, the product showed some promise as an additive to liquid manure. It also appears to be potentially disposable by feeding it into wet scrubber systems where it acts as a supplementary source of lime and augments gypsum production. However, transport costs reduce the attractiveness

64


of this option and there are reservations concerning possible effects on gypsum quality. In practice, the bulk of the spray dry scrubber production has been mixed with fly ash, as a stabiliser, and deposited in landfill above ground water levels. Tests on the deposition of 1,500 m3 the mixture below ground water level indicated that this procedure was not advisable. The material becomes unstable (Ripka, 1995).

6.2 Fly ash quality

Fly ash is used in the production of cement, light weight aggregates, asphalt and concrete (see Sloss and others, 1996). Utilisation varies with location. For example, because their legislation virtually precludes other alternatives, beneficial utilisation in the Netherlands is almost 100% (cement 62%, lightweight aggregates 20%, concrete asphalt and other applications 18%). In eastern Europe under the previous regimes the use of fly ash in building materials was forbidden and almost 100% was dumped. Although the situation is changing, dumping is still the predominant means of disposal in eastern Europe and the USA (Kalyoncu and others, 1995). The need for tighter control of NOx emissions from power stations is leading to the general deployment of low NOx burners and also to the use of SCR as the final emission control step.

6.2.1 Effects of low NOx burners

The fly ash from boilers fitted with low NOx burners is identifiably different from that obtained from boilers fitted with conventional burners. The general differences appear to be:

size, low NOx combustion appears to produce coarser ash than uncontrolled combustion; shape, the particles are more angular and ilTegular than the predominantly spherical particles produced from uncontrolled combustion; carbon content of the ash tends to increase when combustion conditions are modified to reduce the rate of NOx emissions.

Robl and others (1995) found that the fly ash from a boiler that had been retrofitted with low NOx burners was coarser after the retrofit. The amount of material <25 ~m decreased from 66.1 % to 58.9%. The change in particle size distribution was primarily due to an increased proportion of +74 ~m

material. King (1993), describing experience in retrofitting low NOx burners to more than 5000 MWe of pulverised fuel fired utility boiler plant, reported that in general the proportion of fly ash to bottom ash increases and the fly ash is more porous and more friable. Dutch utilities also found that the fly ash from boilers equipped with low NOx burners tended to be different from 'normal' fly ash. The particles tend to be coarser and more angular than the typically spherical particles of the normal product and the carbon content tends to be increased. The major cement and concrete markets prefer fine, spherical ash but the ash can be beneficiated by classification and milling. Cornelissen and Vissers (1996), describing the beneficiation of 'low NOx' fly ash found that separation and milling of the coarser particles increased the yield of product suitable as a concrete filler. In

spite of the irregular shape of the micronised particles, the fluidity of the concrete mix was improved and a high

strength value was achieved.

The tendency for the ash from low NOx installations to have a higher carbon content is well documented (see Sloss and others, 1996; Sorge and others, 1993; Baimbridge and others, 1993). Construction industry specifications for ash to be used in the production of cement and concrete usually require carbon in ash contents of less than 5%. As the amount of excess air is reduced carbon in ash concentrations tend to increase and NOx emissions tend to reduce. However, the lower limit for excess air may be determined by factors other than carbon in ash. Reducing conditions adjacent to the furnace wall can promote rapid corrosion and CO emissions increase as the stoichiometric ratio is approached. Measures for the reduction of carbon in ash, by finer grinding of the coal and increased attention to coal and air distribution were discussed in Section 4.4. General experience with second generation low NOx burners indicates that where carbon in ash was not a problem before the retrofit it can be expected to be manageable after the modifications.

6.2.2 Effects of SCR and SNCR

Fly ash normally contains around 10 mg/kg of ammonia produced by combustion of the PC. Control of NOx by SCR involves the addition of ammonia into the flue gas. In the presence of a suitable catalyst, the ammonia reduces NO x to nitrogen. The addition of ammonia leads to an increase in the ammonia content of the fly ash. For a newly installed SCR system with fresh catalyst the ammonia content of the ash is around 20-50 mg/kg and the ammonia slip is around 2-5 ppm. The efficiency of the SCR catalyst declines with time and the NOx emission rate tends to increase. Over a limited range it is possible to compensate for declining catalyst activity by increasing the ammonia addition but this results in an increasing proportion of the ammonia 'slipping' through the catalyst. Some of the slip is discharged to atmosphere but most of it is adsorbed by the fly ash. Hence the ammonia content of the fly ash can be used to monitor the condition of the SCR catalyst and indicate when maintenance is required

(see Section 5.3. \).

van der Brugghen and others (1995) investigated the problems caused when samples of fly ash with abnonnally high ammonia content were used in a range of processes and applications. This material was produced in the course of tests at Maas power station with the air preheater being used as an SCR reactor (van del' Kooij, 1997). Analyses with an X-ray photoelectron spectrometer showed that ammonia was present as (NH4hS04 on the surface of the fly ash particles. The only adverse effects encountered in using these materials related to the emission of ammonia into poorly ventilated environments. Ammonia is released when the ash is moistened. Vigorous mixing operations increase the rate of release. Tests were performed using experimental mixes of concrete. The composition of the mixes was: 78% sand and gravel, 10% Portland cement, 3.5% fly ash and 8.5% water. Ash samples with ammonia contents of 100, 200 and 300 mg/kg were used. The air within the closed mixer became highly contaminated with ammonia during mixing

65


E 35 Q. Q.

E 30 0 e "0 25 Ql

.~ 'E 0 20 0

.£ c: 15 0

~ "E 10 Ql 0 c: 00 5

::c'"z 0

0 2 4 6 8 10 12

Time after pouring of mortar, hours

Figure 39 Ammonia concentration in the air inside a confined room after pouring a concrete floor (van der Brugghen and others, 1995)

but the concentration declined rapidly when mixing ceased. Concrete mixtures using fly ash with ammonia contents of 100 mg/kg and 200 mg/kg were used to pour a concrete floor in a confined room. While the floor was being poured, the odour of ammonia was clearly present. Figure 39 shows the variation of ammonia content in the air with time.

Some of the main conclusions from the work on ammonia contamination were:

there was no appreciable effect on product quality;

a nuisance can be produced by the release of ammonia to the immediate environment. This is process specific; minimal or zero smell nuisance should be expected during disposal or use of fly ash containing up to 100 mg/m3 of ammonia; some nuisance can be expected at 200 mg/m3;

using ash with an ammonia concentration of 300 mg/m3,

it is possible that the concentration of ammonia in an enclosed environment (eg. a poorly ventilated room) could exceed the maximum allowable concentration of 25 ppm.

6.2.3 SeR catalyst

The installation of SCR will eventually result in a solid waste stream of exhausted catalyst material. Germany was a leading country in the extensive deployment of SCR technology, but in spite of the deployment of more than 30,000 m3 of catalyst material, only a few catalysts have been replaced to date. The main constituents of the catalysts are Ti02 (>75%), W002 (-7%), BaO (-3%), V205 content should be less than 1%, Na20 and K20 content should be less than 0.1 %. The disposal of used catalyst material must be arranged with regard to the possibility that it may be toxic due to plugging with heavy metals (see Section 5.3.1). In Germany the approved method for the disposal of SCR catalyst involves shredding and conversion to a glass in a slag tap furnace (Fuchs and others, 1996).

66

7 Conclusions

Concern about a perceived deterioration of the environment has increased the emphasis on pollution control. The introduction in the USA of a market-based system to secure a reduction in S02 emissions provoked an unexpected response, coal switching, but was followed by a greater than expected reduction at a fraction of the predicted cost. The EU is also resolved to use market means, where appropriate, to secure emissions reductions. The use of fiscal instruments such as pollution taxes may offer governments opportunities to encourage abatement while increasing their revenue receipts. Since taxes may be reviewed annually, or at even shorter intervals, the imposition of pollution taxes could increase the difficulties for utilities in electing for a given degree of abatement.

The achievement of national reductions in aggregate emissions does not necessarily address the problem of achieving local air quality standards. At many locations there is episodic exceedance of national air quality standards for ozone and/or PM 10 and/or S02. In this respect, power station emission plumes brought to earth by unfavourable meteorological conditions can make a substantial contribution to local episodes of poor air quality. Continuous emission monitoring will make such events more readily attributable to individual sources. In consequence, provisions for more stringent local emissions standards may apply. Where practicable it may be prudent for utilities to select upgrade options that provide a route to further upgrading.

The Phase I requirements of the US CAAA 1990 for the control of total national S02 emissions were relatively undemanding in comparison with Phase II and with possible further requirements. Phase II requires a further reduction in national emissions to an average of around 1500 mg/m3

(1.2 lb/million Btu). National standards for new boilers in Europe, and for existing boilers at some locations, require S02 emission rates of 400 mg/m3 or less. Similarly, European legislation limits the NOx emission rate for new large combustion plant to 650 mg/m3 but some European

countries have set the limit, for new and existing plants, at 200 mg/m3. Recently published case studies by the US EPA suggest that the USA may be moving towards similarly stringent emission standards. In the USA, the use of low sulphur coals has proved a cost effective means for complying with the requirements of Phase I of the US CAAA 1990. However, this route will become increasingly problematic as emissions standards continue to tighten. Wet scrubbing is currently the state of the art technology for flue gas desulphurisation. Development of wet scrubber technology is reducing costs while improving reliability and efficiency. The first generation of wet scrubber plants were capable of reducing S02 emission rates by around 90%. A reduction of 95% is now normal and fully commercial installations, using dibasic acid buffering, report reductions in excess of 98%. Where market mechanisms reward marginal increases in S02 removal, the upgrading of an existing wet scrubber has been shown to be a highly cost effective means for gaining additional credits. Pilot scale trials indicate that removal rates up 99.5% are feasible before marginal costs begin to escalate exponentially.

A range of technologies is available for reducing NOx emissions from existing boilers. Optimisation of combustion conditions can be an effective, low cost option and may provide a basis for further improvement. The applicability of combustion control measures is dependent on boiler, site and fuel specific factors. Fuel ratio has been identified as an important parameter particularly when volatile matter content is determined by rapid heating. For generously sized boilers firing brown coal NOx emission rates as low as 160 mglm3

have been achieved using combustion measures alone. The capacity for combustion modifications is more limited for older boilers that have a compact design for firing hard coal. The potential for flue gas treatment may also be limited by a lack of available space near the unit. However, a clear upgrade path exists for many boilers. Starting with the relatively inexpensive process of optimising existing equipment, it progresses through the fitting of low NOx

67

Conclusions

burners and other combustion modifications to the retrofitting of SCR. SCR is currently the state of the art technology for NOx control. It is the only technology that has been demonstrated to be capable of consistently achieving NOx emission rates of less than 200 mg/m3 for hard coal fired PC boilers. This is recognised in US CAAA 1990 by the stipulation that from 1998, for extreme ozone non-attainment areas, NOx emissions from utility coal-fired boilers should be controlled either by the use of SCR, or other comparably effective control technologies, or by switching to natural gas.

Emissions of fine particulate matter (PMIO and, more recently, PMz.5) appear to be subjects of increasing concern. The major sources of fine particulates in the human environment are diesel exhaust emissions and secondary particles generated from sulphur and nitrogen oxides in the atmosphere. The abatement of SOz and NOx emissions reduces the contribution to secondary PMZ.5 from power stations.

The control of primary particulate emissions is related to the efficiency of the control systems: ESPs, fabric filters and SOz scrubbers. Generally, national standards require emission rates that do not exceed 50-65 mg/m3 but coal-fired power stations at some locations in Japan are required to comply with a limit of 10 mg/m3. The performance of existing ESPs may become unsatisfactory because properties of the ash have changed or because standards have become more stringent. Sulphur trioxide is an important 'natural' conditioning agent for PC fly ash and a switch to low sulphur coals may adversely affect the performance of ESPs. 'Natural' S03 may be replaced by injecting S03 before the ESP and this process can be optimised by using automatically controlled dosing equipment. The conditioning effect of S03 may be enhanced by humidifying and cooling the gas stream before the ESP. For some applications the effectiveness of the simultaneous injection of S03 and ammonia has been demonstrated. The efficiency of ESPs in processing 'difficult' ash has also been improved by modifying the control equipment and changing the energisation waveform. Microprocessor-based control systems can minimise electrical breakdown in the ESP by using trend analysis to predict when a spark is about to occur. Through pulse energising it is possible to charge the particles and reduce the voltage before a spark discharge has time to be generated. Using this technology, the emission rate of a 240 MWe Sardinian power station was reduced from 120-190 mg/m3 to 30-50 mg/m3.

Bag filters are the most effective option for some difficult dusts. The advent of stronger filter fabrics and the use of more aggressive filter cleaning methods have facilitated the development of compact, high air to cloth ratio bag filters. This has allowed under performing ESPs to be reconditioned by removing the internals and fitting bag filters within the existing ESP casing. As with ESPs, the performance of bag filters is affected by the properties of the dust and in some cases baghouse performance is improved by flue gas conditioning. Particulate removal efficiency can also be improved by electrically charging the dust particles. The combination of an ESP and a baghouse in series is said to be

highly effective. The ESP reduces the loading on the baghouse and the charged dust from the ESP allows the baghouse to operate at lower air to cloth ratios with a reduced pressure drop.

The rate of emission of Class I and Class II trace elements from boiler stacks depend on their original concentration in the coal and on the collection efficiency of the particulates control devices. FGD wet scrubbers are not usually considered to be particulates control devices but they can be highly effective. Their effectiveness in removing dust may not be apparent because of new material entrained by the scrubbing process. In consequence the concentration of particulates in the gas leaving the scrubber may be similar to that entering the scrubber but the composition of the particulates may be quite different. An analysis of particulates sampled from the gas before and after a wet scrubber system revealed that the ESP was 99.7% efficient and the scrubber approximately 90% efficient in removing particulates giving an overall efficiency of over 99.9% and a particulates emission rate of less than 10 mg/m3 (accurate determination of concentrations less than 10 mg/m3 is problematic). The composition was approximately 40% ash, 10% gypsum and 40% droplets of water saturated with gypsum. Wet scrubbers also reduce emissions of Class III trace elements by scrubbing out more than half of the F, Hg and Se from the flue gas.

A range of options is available to the operators who need to optimise their power stations to meet emerging environmental standards. Where the cost was justified by necessity, utility scale PC-fired power stations have demonstrated compliance with the most stringent current emission standards: more than 98% SOz removal to give SOz emissions below 200 mg/m3, NOx emissions less than 200 mg/m3 and particulates emissions of less than 10 mg/m3. The attainment of national air quality standards is highly desirable but, ideally, the abatement of air pollution should not be at the expense of increased disposal of waste to landfill. The need to ensure the merchantability of CCBs has implications for the selection and operation of pollution control technologies. The installation of low NOx burners appears to have deleterious effects on the properties of fly ash for use in cement but techniques exist for upgrading the product. SNCR and SCR may also affect the merchantability of fly ash if an excessive ammonia slip is pemlitted. The marketability of gypsum is one of the factors that has led to the predominance of the lime/limestone/gypsum process for flue gas desulphurisation. With existing markets for gypsum already almost saturated in some countries, the more widespread deployment of wet scrubber systems will substantially increase the rate of production. The development and marketing of new gypsum products are being actively pursued. At some locations the disposal of coal combustion by-products from PC boilers enjoys favourable treatment because they are classified as non-hazardous waste. However, at other locations disposal to landfill is already proscribed or deterred by fiscal penalties that may become increasingly onerous.

68

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Dec 1991. Pleasant Hill, CA, USA, EPRI Distribution Center, pp 2.107-2.125 (1992) Weilert C V, Stous D H, Dyer P N (1992) Techniques for evaluating alternative reagent supplies. In: 199J S02 control symposium, Washington, DC, USA, 3-6 Dec 1991. Pleasant Hill, CA, USA, EPRI Distribution Center, pp 3A.l05-3A.116 (1992) Wieringa K (ed) (1995) Environment in the European Union 1995: Report for the review of the fifth environmental action programme. Luxembourg, Office for Official Publications of the European Communities, 151 pp (1996) Wiggins D S, Lukens K A, Pettinelli T C, Lahr T S (1995) The FGD system at Atlantic Electric's B L England station design features and project update. In: Proceedings: J995 S02 control symposium. Miami, FL, USA, 28-31 Mar 1995. EPRI-TR-105258-v 2, Palo Alto, CA. USA, EPRI Distribution Center, vol 2, pp 27.1-27.15 (1995) Wildman D J, Smouse S M (1995) Estimation of NO x

emissions from pulverized coal-fired utility boilers. Paper presented at: EPRlIEPA 1995 joint symposium on stationary combustion NOx control, Kansas City, MO, USA, 16-19 May 1995. 20 pp (1995) Withum J A, Maskew J T, Rosenhoover W A, Stouffer M R, Wu M M (1995) Development of the advanced Coolside sorbent injection process for SOz control. In: Proceedings: 1995 S02 control symposium, Miami, FL, USA, 28-31 Mar 1995. EPRI-TR-I 05258-v 2, Palo Alto, CA, USA, EPRI Distribution Center, vol 2, pp 33.1-33.16 (1995) Wolniak D E (1992) An AE's perspective on the relationship of power production and regulatory trends on particulate control technology. In: Ninth particulate control symposium: vol 1 electrostatic precipitators, Williamsburg, VA, USA, 15-18 Oct 1991. EPRI-TR-100471-voll, Pleasant Hill, CA, USA, EPRI Distribution Center, vol I, pp K I-K7 (1992) Woolf M (1996) Industry links taint green tax. The Observer: Business, 1 (29 Sep 1996) Wright R A, Woracek D L (1992) Advances in S03 gas plant design and control. In: Ninth particulate control symposium: vol 1 electrostatic precipitators, Williamsburg, VA, USA, 15-18 Oct 1991. EPRI-TR-I00471-vol 1, Pleasant Hill, CA, USA, EPRI Distribution Center, vol I, pp 1.1-1.15 (1992) Zawacki T, Bengtsson S (1996) Novel design for Konin wet FGD. In: Power-Gen' 96. Budapest, Hungary, 26-28 Jun 1996. Utrecht, The Netherlands, PennWell Conferences and Exhibitions, vol 1, pp 517-528 (1996)

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CoalPower 2 on CD-ROM

CoalPower on CD-ROM, already the most comprehensive collection of data on coal-fired power stations currently available, has now been redesigned and updated and its coverage extended for 1997.

• Coal Power 2 contains information on over 1600 coal-fired power stations and over 4500 individual units in 60 countries

• Most of the data entries have been revised and verified during 1996

• More than 800 addresses for utilities and equipment suppliers make this a valuable marketing tool

• In addition to searches such as finding all units firing coal with specified sulphur or ash content or for all power plants using a particular environmental control technology, it is now possible to locate items of plant from a specific manufacturer or equipment supplier

For futher details please contact:

Mary Barrett IEA Coal Research Gemini House 10-18 Putney Hill London SW15 6AA United Kingdom

Tel: +44 (0)181-7890111 Fax: +44 (0)181-780 1746 e-mail: [email protected] Internet: http://www.iea-coal.org.uk

• For each unit information is provided (where available) on:

• utility/owner/operator • plant location • capacity • current status, and where available • coal burn • coal quality (heating value, sulphur and

ash content) • boiler type and manufacturer

In addition, data on flue gas desulphurisation (FGD) for S02 control, primary measures and flue gas treatment for NOx emissions reduction are incorporated where available.

• Environmental control technologies data include:

• system • process name • supplier • flowsheet or image of system • pollutant emission concentration • efficiency

Coal Power 2 is available within member countries of lEA Coal Research for: £750/US$1200 (+ VAT in the UK): £375/2600 to educational establishments; £500/US$800 to purchasers of CoalPower 1. The price to non-member countries is £7500/US$12,000.

Member countries of lEA Coal Research are:

Australia, Austria, Canada, Denmark, Finland, Italy, Japan, the Netherlands, Poland, Spain, Sweden, the UK and the USA.

lEA COAL RESEARCH

Printed in England

£300 (non-member countries)

£100 (member countries)

£50 (educational establishments within member countries) ISBN 92-9029-284-9

Documents

Improving existing power stations to comply with emerging