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EMISSION C'::JNTL"I.OL,

TECHNOLOGY IN EUi\OPE

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TECHNICAL REPORT DATA \

{l'fe=t: retUi J_r:riOM on the rt!PUU ~fon compleritt6J t 1. REPORT NO. 1

2

•

13. RECIPIENT'S ACCESSIOrotNO. I

EPA-600/2-88-013

4. TITLE AND SUBTITLE iii. REPORT OATE .

Assessment of S02 and NOx Emission Control February 1988

Technology in Europe 6. PERFORMING ORGANIZATION CODE

1. AUTHORISI II. PERFORMING ORGANIZATION REPORT NC.

William Ellison

ll. PERFORMING OFlOANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO.

Ellison Consultants

4966 Tall Oaks Drive 11. CONTRACT/GRAN' NO, 0

Monrovia. Maryland 21'7'70- 9816 EPA Purchase Order

6Dl772NASA

12. SPONSORING AGENCY NAME AND ADDRESS 13. TVPE OF REPORT AND PERIOD COVE PlED

E,PA, Office of Research and Development Final; 4/86-8/87 14. SPONSORING AGENCV COOE

Air and EnerD Eniineering Research Labora~ory

EPA/600/13 r Research Triangle P~k, NC 27711

111.aUPPLEMENTARY NOTES AEERL project officer is Charles B. Sedman. ~ail-Drop 4, 919/

541-7700. - ~,

1- '

1e.ABSTRACT The report is a compilation of information on the current status of abatement technology used to control major air pollutants. including S02 and NOx, in -,

Europe. It focuses on flue gas sulfurization (FGD). combustion modification (CM),

and selective catalytic reduction (SCR) of NOx. Information presented was gathered

from utility company representatives and FGD, CM, and SCR process developers. "

as well as from the author's research. Current air pollution regulations in Europe,--'" ->i

relat ed problems. operational parameters of commercial FGD and SCR plants,

FGD and SCR economics. and the author's evaluation of the processes are also described.

,

,

-

7. KEY WORDS AND DOCUMENT ANALYSIS

la, OESC"II"TO"S b.'DENTIFIERS/OPEN ENDED TERMS c. CDSATI FiddfGroup .,

Pollution Combustion Pollution Control l8B

Emission Catalysis Stationary Sources 14G "

Sulfur Dioxide Economics Europe 07B 05C

Nitrogen Oxides Boilers' West Germany l3A ..

Flue Gases Waste Water 2lB

Desulfurization Fossil Fuels 07A.07D 2lD

18. DISTRJBUTION STATEMENT 111. SECURITY CLASS (11tU Report) 21. NO. OF PAGES

Unclassified 96

Release to Public 20. SECURITY CLASS (1'hU pqc) 22. PRICE

Unclassified

OETE0006810
EPA-600/2-88-013

February 19BB

ASSESSMENT OF S02 AND Nax EMISSION

CONTROL TECHNOLOGY IN EUROPE

by

William Ellison

Ellison Consultants

Monrovia, MD 21770-9316

EPA Purchase Order No. 6D1772NASA

EPA Project Officer:

Charles B. Sedman

Air and Energy Engineering Research Laboratory

U.S. Environmental Protection Agency

Research Triangle Park. NC 27711

Prepared for:

Office of Research and Development

U.S. Environmental Protection Agency

Washington. DC 20460

OETE0006811
TABLE OF CONTENTS

Item

Foreword

Abstract

Table of Contents

Figures

Tables

Abbreviations and Symbols

Acknowledgements

Executive Summary

SECTION 1

STATUS OF S02 AND NOx EMISSION REGULATIONS

1 • 1 WEST GERMAN S02 REGULATIONS

1.1.1 Key Provisions of Landmark

1983 Legislation

1.1.2 Other Stipulations of 1983 GFAVO

1.1.3 1986 Legislation for Industrial Plants

1.2 WEST GERMAN HOx REGULATIONS

1.2.1 1983 and Superseding 1984 Legislation

1.2.2 Comparison with U.S.A. and Japan

1.2.3 Technological Implications of Stringent

, Control Requirements

1.2.4 Other Legislation in Europe

1.2.5 1986 Legislation for Industrial Plants

SECTION 2

STATIONARY SOURCE FLUE GAS DESULFURIZATION

DEVELOPMENT AND APPLICATION

2.1 BOILERS AFFECTED BY 198311984 WEST GERMAN

LEGISLATION AND ACCORDS

2.1.1 Size of FGD Market

2.1.2 Principal Boiler Fuels in Use

2.2 OVERVIEW OF PRINCIPAL FGD TECHNOLOGY APPLICATION

2.2.1 Impact of 1983 Qest German FGD Legislation

2.2.2 Source of FGD Technology Used

2.2.3 Current Generic Design of Lime/Limestone

FGD Systems

2.2.4 Contrast with U.S. FGD Practice

2.3 DETAILS OF FGD TECHNOLOGY USED

2.3.1 System Characteristics of Lime/Limestone

FGD Suppliers

2.3.2 Operating Experience

2.3.3 Minor Processes

iii

ii

ii

iii

vi

vii

ix

xii

xiii

1-1

I-I

I-I

1-2

1-2

1-2

1-3

1-4

1-5

1-5

1-6

2-1

2-1

2-1

2-1

2-1

2-1

2-2

2-3

2-5

2-5

2-5

2-8

2-10

OETE0006812
TABLE OF CONTENTS (Continued)

Item

2.4 TYPICAL DESIGN PRACTICES

2.4.1 Materials of Construction

2.4.2 Flue Gas Reheat

2.4.3 Wastewater Management

2.4.4 FGD By-Product Gypsum Management

SECTION 3

STATIONARY SOURCE DE-NOx DEVELOPMENT AND APPLICATION

3.1 BOILERS AFFECTED BY 1984 LEGISLATION/ACCORDS

3.2 OVERVIEW OF PRINCIPAL DE-NOx TECHNOLOGY APPLICATION

3.3 APPLICABILITY OF SCR TECHNOLOGY

3.4 OTHER POST-cOMBUSTION CONTROL TECHNIQUES

3.5 COMBUSTION MODIFICATIONS

SECTION 4

SELECTIVE CATALYTIC REDUCTION (SCR)

4. 1 OVERVIEW

4.1.1 Process Description

4.1.2 Commercial Applications in West Germany

4.1.3 Earlier Japanese Activity

4.1.4 Stringent Removal-Efficiency Requirements

4.2 COMMERCIAL IMPLEMENTATION OF SCR TECHNOLOGY

4.2.1 Air Preheater Fouling

4.2.2 Difficulties in Retrofit Installation of SCR

4.2.3 Cold-Side SCR

4.2.4 Integrated Air-Preheater/SCR-Reactor Design

2-13

2-13

2-15

2-17

2-17

3-1

3-1

3-1

3-1

3-2

3-4

4-1

4-1

4-1

4-1

4-2

4-3

4-3

4-3

4-4

4-7

4-9

SECTION 5

OTHER POST-COMBUSTION DE-NOx AND SOx/NOx REMOVAL PROCESSES 5-1

5.1 ACTIVATED CARBON (COKE) SOx!NOx PROCESS 5-1

5.2 ABSQRPTION-REDUCTION SCRUBBING 5-1

5.3 ELECTRON BEAM PROCESS 5-3

5.4 SOLINOX PROCESS 5-3

S~5 CAUSTIC SCRUBBING

5.6 WET GAS SULFURIC ACID PROCESS

iv

5-4

5-4

OETE0006813
.'

TABLE OF CONTENTS (Continued)

Item

SECTION 6 . ESTIMATED COSTS FOR 502 AND NOx CONTROL

6.1 FLUE GAS DESULFURlZATION

6.2 NOx REMOVAL

SECTION 7

OTHER EUROPEAN COUNTRIES

7.1 tHE NEtHERLANDS

7.1.1 S02 Emissions

7.1.2 NOx Emissions

7.2 AUStRIA

7.2.1 S02 Emissions

7.2.2 NOx Emissions

7.3 SWEDEN

7.3.1 S02 Emissions

7.3.2 NOx Emissions

7.3.3 Fuel Oil Users Fee

7.4 DENMARK

7.5 NORWAY

7.6 FINLAND

7.7 FRANCE

7.8 BELGIUM

7.9 SWITZERLAND

7.10 ITALY

7.11 SPAIN

7.12 UNITED KINGDOM

7.13 TURKEY

7.14 OtHER COUNTRIES

REFERENCES

v

6-1

6-1

6-2

7-1

7-1

7-1

7-3

7-3

7-4

7-5

7-5

7-5

7-6

7-8

7-8

7-8

7-8

7-9

7-9

7-10

7-10

7-11

7-11

7-12

7-12

R-l

OETE0006814
EXECUTIVE SUMMARY

The very strong reaction of the government of the Federal Republic

of Germany (West Germany) in 1983 to mounting indications of accelerated

forest diebaCk attributable to air contaminants has led to massive expenditures in that and other European countries for retrofit installation of

flue gas desulfurization (FGD), i.e. scrubbers, on coal-burning steam

boilers. In most instances coal sulfur content is low to medium. and

substantially lower than coal sulfur levels in bituminous coal used for

boiler fuel in eastern and midwestern U.S.A. 1983 West German legislation

(GFAVO) calls for retrofitting by 1988 of FGD facilities of a minimum of

85% sulfur dioxide (502) removal efficiency, with stack emission no

greater than 400 milligrams (mg) per normal cubic meter (NII!.3) of flue gas.

for new and existing boilers greater than approximately 110 megawatts.

i.e. HW(e), size. As of 1986. more than 100 FGD systems with greater

than 40,000 HW(e) aggregate capacity have been purchased in West Germany

alone, more than 93% of it of the form of usable-gypsum-producing wet

lime/limestone scrubbing eomparable to many such facilities in Japan and

to a number of such flue gas cleaning systems installed in the U.S.A.

beginning in the late 19708. Other important FGD technologies are also

being utilized in West Germany, some of them of potential value in any

future retrofit bigh-sulfur FGD applications in the U.S.A.

1983 West German legislation requires by 1993 the retrofit addition

of approximately 400 more FGD installations aggregating approximately

25,000 Mi(e) of capacity on boilers in the slze range 35 to 110 MW(e).

Land availability in mainland European countries is such that it is

generally necessary to apply usable-byproduct-forming FGD systems to

avoid need for throwaway disposal of FGD solid waste. In view of the

many millions of annual metric tons of synthetic gypsum supply that could

ultimately be created. and some uncertainty as to the magnitude of available

markets for this material. FGD technologies other than lime/limestone-gypsum

scrubbing are expected to be given serious consideration in achieving

compliance with the 1993 S02 control deadline.

Stringent West German S02 legislation in 1983 was followed in 1984

by enactment of very stringent new nitrogen oxides (NOx) limits calling

for emisSio~s of no more than 200 mg NOx ' measured as nitrogen dioxide.

N02, per NIl!. • approximately 0.16 lb N02 per million Btu heat input. for

existing and new boilers greater than 110 MW(e), size. As of 1986 approximately 50 high-effic1ency commercial systems aggregating more than

10,000 MW(e) capacity. most for retrofit addition, have been purchased in

West Germany alone. and approximately 30,000 MW(e) of additional NOX

removal capacity will be required to be retrofitted by deadlines during

the period 1988 to 1990. Systems applied to date primarily use selective

catalytic reduction (SCR) technology, which employs ammonia reagent to

chemically convert NOx to normal atmospheric nitrogen. A number of

adaptations of typical SCR technology previously utilized in Japan for

base-loaded coal-fired boilers are being applied and evaluated in West

Germany for use in peaking-boiler service. Such new process designs.

xiii

OETE0006815
some of which offer potential for significantly reducing the cost of

retrofit SCi technology, may prove to be of significant value for

possible application in low or h1gh-sulfur de-HOx service in the U.S.A.

West German influence and its projected capital expenditures for

stationary source S02 and HOX control aggregating well in excess of 40

billion West German marks bf the early 19908 is bringing about a new and

extraordinary, eontinent-wide effort to accomplish substantial abatement

of acid precipitation effects through major and Widespread reductions in

502 and HOx emission inventories.

xiv

OETE0006816
·.

SECTION 1

STATUS OF S02 AND

NOX EMISSION REGULATIONS

1.1 WEST GERMAN SO, REGULATIONS

Recent acceleration of European activities for reduction of sulfur

oxide (502) and nitrogen oxide (NOx) emissions is centered in the Federal

Republic of Germany, (West Germany). Great emphasis has been placed on

extensive forest damage, considered to be tied to air pollution, which

has occurred in some regions of the country. Effects on trees have been

particularly severe in the area of North Rhine-Westphalia in the central

portion of the country, as well as Baden Wuerttemberg in the southwest.

At the same time the West German coal industry (1) feels that the causes

for forest decline in that country have not yet been found.

1.1.1 Key Provisions of Landmark 1983 Legislation

In 1983 West Germany enacted a major national acid rain control

directive (GFAVO) (2), (see Table I-I), that has led to a major program

of flue gas desulfurization (FGD) installation at both new and existing

boilers, primarily on large coal-fired units. Note that boilers larger

than 110 MW{e) have been required to add stack gas cleaning by 1988.

Reduction of emissions from smaller boilers. 18 to 110 HW(e), is tied to

a 1993 deadline. Requirements are the same for existing oil-fired boilers.

TABLE 1-1

FEDERAL 502 CONTROL REQUIREMENTS FOR WEST GERMAN COAL-FIRED BOILERS

SO, Emission Limit

Size. mg/Nm3 Compliance Approx. No.

MW{e) (App. Lb/MMBtu) Removal Deadline Boilers Existing

Over 110 400 (0.3, Avg.) 85 7/1/88 160

35 to 110 2,000 (1.6, Avg.) 60 4/1/93 370

18 to 35 2,000 (1.6, Avg.) 4/1/93 300

Note also that in addition to an absolute limit on the rate of S02

emission a minimum %-removal is specified for boilers 35 KW(e) and larger.

thus preventing the use of fuel switching to achieve control compliance.

The provisions of the directive for flUidized bed boilers in the range of

35 to 110 MW(e) requires that S02 emission reduction be 75% (rather than

60%). Informed opinion in West Germany believes that the 400 mg S02/Nm3

(144 ppm) requirement for boilers above 110 MW(e) may well be lowered to

approximately 200 ag (72 ppm) or less by 1990 or before. Similarly. the

6.0%-relllOval requirement level for 35 to 110 KW(e) boilers may be expected

to be increased in the next several years.

1-1

OETE0006817
1.1.2 Other Stipulations of 1983 GFAVO

After declaration of individual boiler owners by July I, 1984, any

existing boiler larger than 110 MW(e) , if committed to being decommissioned

by April 1, 1993, is permitted to operate for no more than 30,000 additional

hours at an 502 emission rate not to exceed 2,500 mg/Nm3, (900 ppm.)

Additionally, the 1983 law requires that flue gases in the stack

folloWing desulfurization must typically have a minimum temperature of

72°C (162Of) as they exit the stack.

Surveillance of 502 emission by continuous monitoring and recording

of stack 502 is required for coal- and oil-fired boilers larger than -18

MW(e). Compliance requires that (3) all daily mean values are equal to

or smaller than the emission limit value: 97% of half-hour mean values

are equal to or 8maller than 1.2 times the emission limit value; and all

half-hour mean values are equal to or smaller than tWice the emission

limit value.

Individual local (provincial) governments have the authority to

impose more stringent requirements than those specified by the national

legislation. For example, (4) in North Khine~estphalia, (With nearly

50% of the electric power generation of the entire country, a large

portion being fired with lignite), -special requirements were placed on

approximately 3,000 MW(e) of existing lignite-fired boiler capacity in

1984 calling for an interim 502 emission reduction of 110,000 metric tons

per year by 1987 (through temporary low-capital-cost dry-alkali injection

means. )

1.1.3 1986 Legislation for Industrial Plants

Emission limits for small existing industrial boilers, e.g. 1% sulfur

fuel-fired units larger than approximately 6,500 lb/hour steam generation,

the equivalent of approximately 0.5 MW(e) , are addressed in new national

legislation (TA Luft) of February 27, 1986 (5). With many exceptions, it

is specified that boilers emitting more than 5 kilogram 502 per hour must

limit emissions to- 500 mg/HlD3, (180 ppm).

1.2 WEST GERMAN NOx REGULATIONS

After enactment of the major 1983 S02 legislation, which imposed

modest NOx requirements, concern about NOx as a contributor to forest

damage substantially increased. Following from a "technology forcing"

provision of the 1983 law tied to state-of-the-art technical developments,

a 1984 accord among federal and provincial environmental ministers in

effect substantially reduced the 1983 limits for NOx. At the same time

it called for setting of deadlines by the individual provincial jurisdic- tions.

1-2

OETE0006818
Category

1.2.1 1983 and Superseding 1984 Legislation

The limit values legislated in 1983 and those later substituted by

sanction of national government in 1984 for coal-fired boilers are as in

Table 1-2 (6). Note that existing coal-fired boilers (with future operation of unrestricted duration) as well as new boilers must limit NOx

emission to 200 mg per standard cubic meter, a level equivalent to approximately 100 ppm (volUllle). An approximate equivalence between the four

most common emission concentration measures is: 1 mg/Nm3 - 0.487 ppm •

0.35 g/GJ c 0.000814 lb/MM Btu (7). This stringent requirement is

predicated on commercial experience in Japan indicating that selective

catalytic reduction (SCR) technology is effective, and the judgement that

it is demonstrated to be capable of reducing emissions to this310w level.

[NOx limits, 1984 basis, for new oil-fired units are L50 mg/Nm above 110

MW(e) and 300 mg/Nm3 from 18 to 110 MW(e~. For'existing units of unspecified

future lifetime the limits are 150 mg/Nm above 110 MW(e) and 450 mg/Nm3

from 18 to 110 MW(e).}

TABLE 1-2

NOx CONTROL REQUIREMENTS FOR WEST GEIlHAN COAL-FlRED BOILERS

NOx Emission-'Limit, mg N02/NIa3 (ppm),

(6% 0, Basis, Dry Bottom: 5% 02 Basis, Wet Bottom)

Size, MW(e)

New Units., Dry Bottom:

1983

1984

New Units, Wet Bottom

(Slag-Tap) :

1983

1984

Existing Units,

Dry Bottom:

1983

1984

Existing Units,

Wet Bottom

(Slag-Tap) :

1983

1984

18 to 110

800 (400)

400 (200)

1,800 (900)

400 (200)

1,300 (650)

650 (325)

2,000 (l,OOO)

1,300 (650)

Over 110

800 (400)

200 (100)

1,800 (900)

200 (100)

1,300 (650)

200 (100)

2,000 (l,000)

200 (laO)

Note: 200 mg/Nm3 equals approximately 0.16 lb/MM Btu.

1-3

OETE0006819
"

Note, however, that at the option of boiler owners, as decided and

declared by them in 1984, old boilers aggregating approximately 12,000

KW(e) capacity will be phased out, 1.e. retired, no later than 1993

after no more than 30,000 additional hours 3of operation, during which

they will be allowed to emit 650 mg N02/Nm , Le. approximately 325 ppm,

(1,300 mg/Nm3 for wet bottom), above 18 HW(e), (450 mg/Nm3 for o11-f1red

units.)

As in the case of 502' surveillance of HOX emissions by continuous

monitoring and recording of stack NO is required for coal- and oil-fired

boilers larger than 18 KW(e). Compliance requires that all daily mean

values are equal to or smaller than the emission l1Jl1t value: 97% of

half-hour mean values are equal to or smaller than 1.2 times the emission

limit values and all half-hour mean values are equal to or smaller than

twice the emission limit value.

The state government of Baden~uerttemberg, the area of greatest

forest-damage severity was tbe first to impose prompt deadlines for the

stringent 1984 NOx emission limits (8). Dry bottom boilerst both new and

existing, IIlUst comply by 1988, wet (molten-ash) bottom. boilers by 1990.

Similar deadlines have also been established by other state jurisdictions

including North Rhine-Westphal1a. It is expected that the retrofitting

of NO~ removal systems on existing West German boilers larger than 110

HW(e} will be cOlllPleted by 1990 resulting in an average of 70% reduction

in NOx emissions.

1.2.2 Comparison with U.S.A. and Japan

The extremely stringent 200 mg/Nm3 requirement for both new and

existing coal-fired boilers above 110 MW(e) size surpasses NOx control

requirements 1n all other nations including Japan. See Table 1-3 (9).

The West German HOx stringency for boilers above 110 HW(e) is all the

more remarkable, taking into account that most HOX emissions are from

mobile sources. (Hate that additional regulations are being considered

in West Germany that will require lead-free fuel and catalytic converters

for gasoline-fueled automobiles.)

TABLE 1-3

COMPARISON OF NOx EMISSION STANDARDS FOR COAL-FIRED UTILITY BOILERS

Country

West Germany, Hew and Existing

over 110 MW(e), (1{2 hr. avg.)

U.S.A., New Sources

Japan, after 1987

1-4

NOX Emission Standard,

mg as N02/Nm3 (6% O2)

200

600-750

410

OETE0006820
1.2.3 Technological Implications of Stringent Control Requirements

Commercially developed combustion modifications for HOx control are

expected to be routinely applied, primarily on dry-bottom boilers.

However, the very substantial reduction that will be required from the

uncontrolled NOx emission levels illustrated by Table 1-4 (6) is resulting

in Widespread application of SCi to essentially all German boilers larger

than 110 HW(e). ~reover. since it is necessary to sustain ample boiler

temperatures in wet bottom boilers sufficient to maintain bottom ash in a

molten state, only 1I1nor reduction in HOx emission can be achieved by

combustion modification; and wet bottom boilers will require SCI. removal

effieiencies as high as 90%.

TABLE 1-4

TYPICAL PRE-CONTROL BOILER NOx EMISSIONS

Type Boiler

Mean

- BitWll1nous.

Wet Bottom (Slag-Tap)

Bituminous,

Dry Bottom

Lignite,

~augentially-Fired

1.2.4 Other Legislation in Europe

800-2.800

800-1.500

400-700

1.700

1,200

500

By influence of West Germany significant NOx control legislation has also

passed or is pending in Austria, Switzerland, The Netherlands, Denmark. Sweden

and the European Eeonomic C01lllllUllity. See Table 1-5 (7) displaying the HOx

emission management objectives of governing officials of EEC. (10) revised in

1985 to eall for emission rates throughout Europe after 1995 comparable to

current requireJlE!Dts in West Geruany. New standards in Austria for coal-fired

boilers above 110 }{W(e) call for 150 1llg/Nm3 for new boilers and 300 mg/Nm3 for

existing boilers (11).

1-5

OETE0006821
TABLE 1-5

EFFECT OF AMENDED EUROPEAN COOIUNITY DIRECTIVE

Emission Limits (mg N02/Hm3)

1983 Proposed Directive Coal Oil

All Plants over 50 Wet)*

to 1995 800** 450

after 1995 400*** 220

1985 Amended Directive

to 1995: over 50 Wet) 450

50-100 MW(t) 800**

100-300 MW(t) 800

over 300 !!W(t) 650

after 1995: over 50 !!W(t) 150

50-100 MW(t) 400***

over 100 MW(t) 200

Gas

350

180

350

100

*Note that 100 MW(t) equals approximately 37 MW(e).

**1300 mg/Nm3 for slag tap furnaces

***800 IIg/Nm3 for slag tap furnaces

1.2.5 1986 Legislation for Industrial Plants

The new federal regulations (TA Luft) issued on February 27, 1986,

limit NOx emissions from industrial plants nth an output of m~re than

5 kilograms as N02 per hour, generally to a limit of 500 mg/Nm. (As

noted earlier, the SOz emission limit for industrial plants with an S02

output of more than 5 kilograms per hour has been set a a nominal level

of 500 mg/Nm3).

Other new NOX limits imposed by the February 1986 legislation are

as follows:

o Solids incineration, less than 50 !!W(t), i.e. 18 MW(e)

- Fluidized bed, more than 20 MW(t) 300 mg/Nm3

- Other 500 mg/Nm3

o Oil incineration, less than 50 MW(t)

o Gas incineration, less than 100 MW(t)

o Gas Engines

- Diesel

More than 3 MW(t)

Less than 3 HW(t)

1-6

250 IIg/Nm3

200 mg/Nm3

2,000 mg/Nm3

4,000 mg/Nm3

OETE0006822
- Otto

Four-stroke

Two-stroke

o Gas turbines

- More than 60,000 Nm3!h exhaust

- Less than 60,000 Nm3/h

1-7

500 mg!Nm3

800 mg!Nm3

300 mg!Nm3

350 mg/Nm3

OETE0006823
SECTION 3

STATIONARY SOURCE DE-N0x

DEVELOPMENT AND APPLICATION

3. 1 BOILERS AFFECTED BY 1984 LEGISLATION/ACCORDS

Referring to the earlier Table 2-1, it can be seen that more than

150 West German boilers are impacted the 1984 federal/provincial NOx

control accords requiring reduction of HOx e~ssions from units larger

than 110 MW(e) to the level of 200 mg N02!Nm , equivalent to 100 ppm

(vol.) and to 0.16 Ib/MM Btu heat input. Also affected are 7,400 MW(e)

of new, coal-burning units under construction or expected to start up by

approximately 1990.

3.2 OVERVIEW OF PRINCIPAL DE-No,. TECHNOLOGY APPLICATION

The emission limit, (200 mg/Nm3), set in 1984 for boilers above

110 MW(e) is well beyond the capabilities of combustion modification

techniques and requires the use of flue gas cleaning processes for ROx

removal such as sea and wet or dry sorption. With the resulting requirement ~or reductions in existing NOX emissions in the amount of 50-70% or

more, post combustion flue gas treatment techniques can be expected to be

broadly applied in Europe. especially processes that are capable of

removing both S02 and NOx, (and possibly particulates). and that can

function adequately in such power plant service. However, because of the

early (late-1980s) deadlines for compliance by large boilers in West

Germany, and despite the fact that it serves only to remove HOx. the high

developed SCR process is being DOSt broadly assessed. adapted and applied.

3.3 APPLICABILITY OF SCR TECHNOLOGY

Due to concerns about applicability at existing electric utility

plants in West Germany of extensive commercial SCR experience in comparatively new. base-loaded boilers in Japan. approximately 50 SCR pilot

plant trains have been installed and tested (22) to aSsess catalyst

performance and characteristics. The installations include 24 systems

based on conventional SCR application upstream of the air preheater

(high-dust), and 19 systems based on use of SCR downstream of FGD

(cold-side), including 11 with activated carbon. Extensive high-dust sea

field p11ot-scale investigation is taking place because German boilers to

be retrofitted with SCR are considered to have a more variable load

pattern (more frequent load swings) than those in Japan that have been

equipped and operated with SCR. and could cause thermal shock of the

catalyst structure. In addition. possible unique effects of fly ash from

German coal Is of concern. Also, although avoided in Japanese practice

and of concern because of ammonia-slippage problems, design HOx removal

efficiency substantially above 80% i8 specified for a number of the German

retrofit SCR applications.

3-1

OETE0006824
."

Nonetheless, in the face of all these SCR uncertainties, catalystlife guarantees have since 1984, increased from 1 year to two years or

more (24). Of 10 competing SCR system suppliers in Germany, 6 are licensees

of Japanese process licensors while 3 offer German developments including

use of activated carbon, ceramic IIIOlec:ular sieve, and iron oxide. For

cold-side sea service (downstream of FGD) activated carbon (coke) is of

considerable interest since its catalysis is effective at a comparatively

low temperature, i.e. as low as 90oe, (194°F) and requires less reheating

of the water-saturated gas prior to the SCR step. An American licensor,

Norton, uses a zeolite type catalyst.

As early as 1984 26 specific initial commercial installations were

anticipated. several to be applied downstream of FGD because of inadequate

plot space to permit normal tie in of the SCR reactor upstream of the air

preheater. (See Fig. 3-1) (16). As noted earlier. in some provinces

such as Baden-Wuerttemberg, the most heavily forest-damaged area, and

North Rhine-Westphalia. the greatest emitting area, the state-administered

NOx control planning is more advanced than in others, and accounts for

lIlOst NOx control installations under way to date. The first 1II8jor SCR

facility has been installed on a 460 MW(e) bituminous-coal-fired. dry

bottom boiler and commenced operation in early 1986. Another early

installation of 160 HW(e) capacity on a bituzinous-coal-fired, wet bottom

boiler. will achieve close to 90% NOx removal.

3.4 OtHER POST-COMBUSTION CONTROL-TECHNIQUES

Other potentially important developments for NOx removal include

sustained pilot and field test programs seeking to adapt existing rotary

regenerative air preheaters to incorporate catalyst-coated plates,

permitting these facilities to also serve as SeR reactors. Catalyst

temperature in this integrated arrangement for high-dust service ranges

within the heat exchanger from 1500C to less than 3500e (302 DF to less

than 662°F), whereas an SCR reactor typically positioned upstream of the

air preheater operates at approximately 350°C (662 D F).

Full-scale power plant testing (41) indicates feasibility of selective

non-catalytic reduction (SNCR) at lOOO°C (1832°F) with approximately 50%

NOx removal (without undesirable, partial conversion of S02 to S03 that

accompanies SCR operation). As per Table 4-1, 940 MW(e) of SNCR capability

is being installed in West Germany.

A number of pilot plants have been installed in West Germany to

investigate use of wet simultaneous S02!NOx removal systems, both of the

absorption-reduction and oxidation/absorption types. Wet NOx removal

techniques include a usable-gypsum producing process that is reported to

use a ferrous complex ion (FeEDTA) in conjunction with sulfite (and

thiosulfite) ions to fix and chemically reduce flue gas NO. This process.

now being installed on a full-scale basis, appears to be very similar to

the Japanese-proposed technology of the 19708 (42). Although the wet

simultaneous S02!NOx processes are seen to have possible economic advantages

the tight deadlines (compliance as early as 1988 in many instances) are

leading to a preferred use of the more commercially established technology

based on SCR.

3-2

OETE0006825
Figure 3-1. Configuration of alternative Sel De-NOX plants

in combination with FGD.

3-3

OETE0006826
3.5 COMBUSTION MODIFICATIONS

Combustion modifications have been the most common, commercially

available means of controlling NOx emissions at coal-fired utility boilers.

For reasons of cost-effectiveness and reliability, combustion controls

offering significant NOx reductions are likely to continue to be the

preferred NOx control approach for both new and retrofit applications in

smaller boilers. In general, the most practical and cost-effective

retrofit combustion control options are low excess air firing, overfire

air, and low-NOx burners. Note, however, that wet bottOll, i.e. slag-tap,

type boilers are limited in their ability to apply combustion modifications

for NOx control since generally lower gas temperatures brought about in

at least a portion of the furnace would be expected to alter the wet slag

properties and possibly hinder its drainage from the bottom of the boiler.

Brown coal (lignite) fired power plants (9), constituting another substantial

portion of electric power production in West Germany, also present unique

problems for NOX emission control because of special firing arrangements

required and because of high water vapor content of flue gas.

Among available options, low-NOx burners promise the greatest

potential for significant (50 to 60%) NOx reductions and are thus receiving

substantial attention in field development activities. Specifically,

these burners are designed to control the mi'ldng and stoichiometry of fuel

and air in the near-burner region of the furnace to retard conversion of

fuel-bound nitrogen to HOz: while still maintaining high combustion efficiency.

This is accomplished by controlling the momentum, direction, and quantity

of fuel and air streams at the burner throat as they are injected into

the furnace chamber.

Few existing coal-fired utility boilers have yet been retrofitted

with low-NOx combustion systems. Retrofitting combustion controls to

existing units appears to be technically feasible however, provided

sufficient attention is given to site-specific design and engineering.

These advanced systems pose new eombustion conditions, furnace flow and

mixing requirements, and boiler control issues significantly different

from conventional burners. Their ultimate success hinges on the ability

to integrate these processes with the fixed physical and thermodynamic

constraints of the existing boiler. In order to expand the retrofit

applicability of these low-N0x systems, several demonstrations on a

variety of boilers are being carried out.

Independently, advanced Nex combustion control concepts are being

developed to more closely control the fuel-air mixing, temperature, and

combustion chemistry in the furnace. Reburning technology originated in

Japan is under development to destroy NOX already formed in the initial

combustion step. It has been reported to produce a 50% further reduction

beyond that of low-Hex burners.

New boilers in West Germany equipped with recently-developed low-Hex

b~rnejs emit 800 mg N02/m3 in the case of dry bottom design and 1,300 mg

N02/m in the case of wet bottom design (6). In one of the most recent

3-4

OETE0006827
applications in dry-bottom service low-NOx burners are being used in

conjunction with application of over-fire air to try to achieve an emission

rate of 650 mg N02/m3• For new (but not existing) boilers in bituminous

dry-bottom service, the Japanesedevised. advanced low-NOx techique,

called MIn Furnace NOx Reduction" (IFNR) or "Fuel Staging" or also "Reburning

Technology" holds great long-term promise. It is believed to have the

potential to decrease the HOx level below that achieved with other burner

technologies by 30 to 50%. A secondary fuel is injected into the furnace

above the main burners and the remaining air for burnout is supplied

through ports located above the secondary fuel injection. The secondary

fuel will considerably reduce the HO produced in the main combustion zone

to yield H2. The fuel staging technique is not commercially demonstrated

in coal service and faced with a number of problems connected with burn-out,

corrosion and slagging (43). The injection of secondary fuel leads to a

high concentration of hydrocarbon radicals in a zone of high temperature

and air deficiency. To a great extent these radicals reduce the NO

molecules produced in the main combustion zone to N2 (direct NO reduction)

or nitrogen compounds, such as HCN and mit. This complex process includes

both gaseous phase reactions and heterogeneous gas/solid reactions.

Combustion in the furnace is completed in the final burnout zone using

the balance of combustion-air supply. In this Zone the nitrogen compounds

formed as intermediate products in the reduction zone are further converted,

partly to N2 (indirect HO reduction) and also back to NO. Tests have

shown that by this overall process a net reduction of nitrogen oxides by

about 50% can be achieved. The development of firing systems using the

IFNi principle by staging the fuel supply in the furnace chamber is

actively pursued by a number of companies and institutions in Japan,

Germany, and U.S.A. Full-scale experience has been gained with oil-firing

systems. As to its application to coal firing systems, first test results

have up to now only been obtained in pilot-scale plants. Development has

been started on injecting the secondary fuel into a burner-related arrangement, i.e. achievement of staged fuel supply to the individual coal

flame. It is expected that in-furnace NOx reduction (reburning) will

soon be applied to some pulverized coal-fired boilers after further

current operation of this furnace-staging method on a 40 MW(e) gas-fired

boiler. In conjunction with flue gas recirculation NOx emission rates

comparable to these from gas firing can be ultimately foreseen through this

combustion-modification method for coal and heavy oil fuels.

There are some fluid bed boilers under construction but the experience

with existing ones has not been free from problems, particularly in the

case of circulating-bed types (22).

3-5

OETE0006828
SECTION 4

SELECTIVE CATALYTIC

REDUCTION (SCR)

4.1 OVERVIEW

4.1.1 Process Description

The SCR process is based upon treating the flue gas with ammonia

(NR3) to chemically reduce NOx in accordance with the following chemical

reactions:

4NO + 4NR3 + 02 -

2NOZ + 4NR3 + OZ

4N2 + 6H20

3N2 + 6HZO

The reactions proceed when the gas temperature is from aoooe to 10000 e

(1470°F to 1830°F), which is the basis for the selective noncatalytic

reduction method. However, in the presence of a suitable catalyst, the

reaction proceeds with a gas temperature of 3000e to 400°C (570°F to

750°F), which is close to the temperature of the flue gas as it exits the

boiler economizer section upstream of the air preheater. This is the

basis for the utility SCR process', which is theoretically capable of

achieving 85 to 95% NOx removal for ammonia injections of .85 to 1 mole

NR3 per mole of NO present. Note also that when the SCR operation is

carried out downstream of FGD (cold-end) the limited presence of S02 and

S03 in the flue gas makes it possible to utilize catalyst with higher NOx activity permitting efficient SCR operation at as low as lOO°C (392°F).

Typical catalysts (44) are of honeycomb design. Flue gas still

containing the fly ash enters square channels in the catalystic elements

of 6 x 6 to 10 x 10 1ID1 size and flows parallel to the solid channel walls

which have a thickness of about 1.5 mm. Basic material for the catalyst

is Ti02 to which vanadium and/or tungsten as active material and a binding

agent have been added. Catalysts are installed in layers in the reactor

leaving a free space of 1-2 m between layers. Honeycomb elements are

combined to form modules. This method allow for easy replacement of

catalyst layers by means of a hoist or other lifting device.

4.1.2 Commercial Application in West Germany

Only a limited 1IIlunt of commercial operating time has yet been

achieved in Europe but many utility installations are in initial

operation or under construction in West Germany. Colllllitlllent to SCR

systems in West Germany for initial startup during the period 1986-1990,

publicized as of July 1986 (22) are as per Table 4-1.

4-1

OETE0006829
TABLE 4-1

PRINCIPAL SCR TECHNOLOGY SUPPLIERS

Approx. Number of

Aggregate Installations

Catalyst Licensor MW(e) High Dust Cold End

Kawasaki 1,250 3 2

Mitsubishi 2,000 5 2

IHI 1,850 8 1

Babcock Hitachi 1,300 5

Norton 105 3

Other 810 3

Not announced/selected 1,860 8

Total SCI. committed 9,175 32 8

SNeR committed 940 3 x

Approximately 30,000 MW(e) of large boiler capacity in North

Rhine-Westphalia will be equipped with SCI. by 1989 or 1990. By 1990

3700 MW(e) of HOx removal systems, primarily SCR, will be installed in

Baden-Wuerttemberg. In all, the boiler HOX emission inventory throughout

West Germany will ultimately be reduced by 0.7 million metric tons,

principally by SCI. (44).

4.1.3 Earlier Japanese Activity

In the work 1n Japan leading up to present applications in Germany

the process manufacturers have routinely designed the SCI. reactor for 80%

NOx removal and have often designed for 90% removal with a guarantee of

80%. The catalysts are also warranted for 1 to 2 years of lifetime. The

predominant catalyst type that has been applied in Japan (8), and that is

nOW being most extensively used in Germany is ceramic based type containing

Ti02., V20S, and traces of heavy metals. Each of a multitude of catalyst

layers that the flue gas contacts consists of single blocks of either

honeycomb shaped ceramics or catalyst covered plates. Operational problems

that have previously been encountered and addressed in commercialization

of the technology in Japan are:

o Plant efficiency reduction due to economizer tube removal

o Catalyst erosion (and poisoning in the early installations)

4-2

OETE0006830
o SCR reactor plugging with ash

o Plugging of the air preheater and induced draft fans with dust

and ammonium bisulfate

o Ammonia bypass leakage with a resulting contamination of the

fly ash and the FGD wastewater

o Difficulties with maintenance and accuracy of the NOX and NB3

instrumentation

4.1.4 Stringent Removal-Efficiency Requirements

While Japanese practice has established 80% NOx removal in SCR as a

generally practical maximum level to avoid significant ammonia leakage to

the downstream air preheater and FGD system, permitting by BOlIle German

provincial authorities in some applications calls for close to 90% seR

efficiency, which 1s of concern in view of the Japanese design philosophy.

This includes a small installation of VEBA Kraftwerke at Knepper, 1986

initial startup, on a wet bottom boiler to reduce NOX emissions to 200

mg/m3• An SCR. system starting up in 1986 on a dry-bottom. boUer at

Neckarwerke in Altbach, approximately 370 MW(e) SCR capacity. will alBO

achieve a 200 mg/m3 NOx emission from the stack but treat only 80% of the

total flue gas flow.

4.2 COMMERCIAL IMPLEMENTATION OF SCR TECHNOLOGY

4.2.1 Air Preheater Fouling

Through prior field study in Japan and more recent work in Germany

(45), major efforts have been made to establish design criteria for the

air preheater to make it compatible with common high-dust SCR. operation

upstream. (A similar concern would apply in connection with operation of

rotary heat exchangers downstream of cold-side SCR..) In reducing flue-gas

stream temperatures as low as 150°C to 230°C (300°F to 450°F) the air

preheater causes excess NH3 vapor from the SCR operation to react with

water vapor and !lOst of the 503 gas present to form the compounds 8l!Il1Onium

bisulfate and ammoniUIII sulfate. (The SCR reactor further enhances this

formation due to the fact that the SeR catalyst converts approximately 1%

of the flue gas SOz to S03, thereby essentially doubling flue-gas 503

concentration.) AmmoniUIII sulfate vapor solidifies below 250°C (482 DF) and

ammonium bisulfate forms a liquid at a somewhat lower temperature. The

latter solidifies at approximately 150DC (300°F). These compounds stick

to fly ash and to the internal surfaces of the air preheater. It has

also been found that the air preheater heating surfaces. so wetted and

fouled. act like -fly paper- in collecting fly ash particles from the

flue gas. further contributing to internal deposits and causing increased

gas pressure drop. Fouling can be expected to be encountered when NB3

concentration in flue gas downstream of SeR is as high as approximately

5 ppm. This can be expected when SCR is operated at BOx removal efficiency

substantially higher than 80% or, even at lower efficiencies when, toward

4-3

OETE0006831
the end of the usable life of the catalyst charge, increased ammonia feed

is used to maintain required NOx removal efficiency. Nonetheless, the

Germans emphasize that flue-gas 503 content is a more critical factor;

at a specified NH3 leakage rate it is the 503 content which determines

whether there will be a serious rate of buildup of dry 8IIIIIlonium sulfate

with liquid ammonium bisulfate on the air preheater heating surfaces.

Based on field test experience in both Japan and Germany important criteria

as follows have been established for design of deNOx-compatible air

preheaters (and gas-gas heaters for cold-side sca as applicable):

o The heating surfaces must have a configuration that is easily

cleaned by means of soot blowing.

o The cross-over of heating-element layers must be avoided in the

area most likely to be affected by ammonium bisulfate deposition.

o Enameled heating elements should be used, particularly when 503

concentration is greater than 2 ppm.

o Highly efficient sootblow1ng devices must be used in order to

limit outages.

a-When 503 concentration is greater than 2 ppm need of provision for

frequent off-the-line water washing of the air preheater must be

anticipated; unlike rotary regenerative heat exchangers used to

achieve flue gas reheat downstream of wet FGD. air preheaters

downstream of sca cannot be water washed on-line.

4.2.2 Difficulties in Retrofit Installation of sea

Because of the large size of the sca reactor, 'system retrofitting is

a major engineering challenge, particularly in the case of high-dust

applications. which require tie-ins to ductwork upstream of the air

preheater. This is illustrated by a published report of the details of

the 370 MW(e) sca retrofit at Heckarwerke (Block 5) in Altbach recently

put into operation. Although this unit is newly constructed, the SCR

installation was in every sense a retrofit since it was not anticipated

in the original plant design. Construction of the 460 HW(e) coal-fired

unit began in 1982. In the spring of 1984 the boiler, air preheater and

flue-gas ductwork were completed. The bollerhouse facade was already

closed. Sections of the induced-draft fan were being manufactured.

Initial operation of the plant was planned for mid-1985.

In the Spring of 1984, initial studies began for the installation of

an SCR catalytic converter whereby the planned unit start-up date would

be maintained and an emission value of 200 mg NOx/m3 would be achieved.

The results of this study showed that it was possible to install an sca

system between boiler end and air preheater, with a flue gas volume of

1.1 million m3/h (i.e. approxi1ll8.tely 80% of the flue gas volume), and

w~th two reactor bypass ducts, each for approxi1ll8.tely 10% of the total

flue gas volume. By arranging the converter between the boiler supports

4-4

OETE0006832
and the load-bearing structure of the bo11erhouse facade, it was possible

to retain the exterior design of the boilerhouse. The reactor was designed

for four converter levels and with one level for flow straightening

blades. In the initial stage, only three converter levels were fitted.

The design of the flue gas ducts, the mixing section for economizer

bypass flow/residual flue-gas flow, the NH3 feed section, the reactor are

at the inlet side of the converter and the addition of tbe reactor bypass

flow were carefully investigated by wind-tunnel tests. The configuration

of the air preheater registers was altered, and the package lengtb increased.

While maintaining the induced-draft fan housing, the differential pressure

developed could be increased by 20 mbar (8 in.W.G.) by alterations to the

impeller. Figure 4-1 is a schematic illustration of the installation

plan devised.

Subsequently the following retrofit alterations were carried out:

o Partial dismantling of the boilerhouse up to an elevation of

over 40 meters

o Reinforcement of load bearing members in the boilerhouse area

o Dismantling of the flue gas ducts between boiler end and air

-preheater, and installation of the SCR reactor housing

o Installation of the reactor "bypass ducts

o Installation of the economizer bypass, including opening of

the boiler wall and installation of the ducts

o Installation of additional dust removal systems for the

economizer bypass area and downstream of the reactor

o Installation of the ammonia supply system (support,

distribution, injection)

o Alterations to the air preheater internals

o Alterations to the induced--draft system

With the benefit of careful planning and expedited shop work, and

With construction activity planned to the last detail, installation of

the major components (reactor, bypass ducts, economizer bypass) was

completed in November 1984, after which the boilerhouse facade was closed

again. Other work could thereby be performed so that trial operation of

the unit was able to begin as scheduled in September 1985. Ammonia

storage was completed by the end of October 1985. The catalyst was installed

in November during a one-week shutdown. the first tests of NOx emissions

were performed in late November 1985.

4-5

OETE0006833
Reactor

bypass

Economizer De~NOx

bypass reactor

Figure 4-1. Cross-section of SCR system retrofit.

side views/plan view.

4-6

OETE0006834
4.2.3 Cold-Side SCR

In Japanese and European programs to retrofit SCR systems for fluegas NOx removal. phySical plot-space limitations have in some instances

prevented the tying in of the SCR reactor at the no~l location, upstream

of the air preheater i.e. in high-dust service at the Khat side" of flue

gas desulfurization (FGD.) In such instances it may be necessary to use

a "cold side", i.e. tail end. installation, adding SeR downstream of feD.

but connected 80 as to receive the FGD outlet gas after it has been

heated to a suitable temperature. i.e. typically 320°C (608°F), for the

catalyzed reduction of flue gas HOx. The largest existing FGI>-c:old-sidesea operation (downstream of wet FGD) is a 1.320.000 Nm3/hr (820.000 scfm)

1979 installation. the equivalent of 330 MW(e) , at an iron are sinter

furnace of Hippan Kokan KK at its Keihin Works in Japan. It utilizes a

rotary regenerative heater followed by ammonia injection and an iron ore

catalyst reactor operating at 3900 e (734°F), to reduce a 200 ppm flue-gas

HOx concentration to 30 ppm. 1979 capital cost of the system installation

is understood to be 6.7 billion yen, approximately 15 million DM. which

is equivalent to approximately 20 million DM (1985), or roughly 60 DM per

kW, somewhat higher than for a typical hot-side application.

Many cold side installations in West Germany announced to date (38)

are small capacity With generally poor economics of scale. A municipal

power plant, which is installing three 35 KW(e) cold-side SCR systems

utilizing a cyclical operation of twin ~anular heatexchange beds in

conjunction with feed of ammonia to a single catalys~ chamber operating

at 350°C (662°F) to reduce HOx emission to 200 mg/Nm , is projected to

have capital cost of 250 UK per kW (and a unit cost of 2.5 Pfg per kWh)

(47). In a new boiler application of SCR, the greater apparent Simplicity

and economy of a hot-side installation may rule out use of a cold-side

design.

However, the very substantial difference in total cost between

hot-side and cold-side retrofit installations. typically, has largely to

do with energy costs of the cold side technique that lead to substantial

reheating of the flue gas above the water saturated temperature at which

it exits the upstream FGD system. Cold-side SCR yields approximately

500 e (90°F) of flue gas reheat, and thus eliminates need for reheat

facilities that would normally be included in the FGD installation. When

an appropriate credit for this non-regenerative reheat is/can be given.

the margin of cost difference between hot and cold side design 16 significantly reduced.

In addition, catalyst life and system reliability is expected to be

better with cold-side operation. In an extensive field pilot test program

(45) that began in early 1985 favorable reliability for tail-end system

installations has been verified even with NR3 leakage of approximately

5-10 ppm. No gas pressure drop increase has been experienced; S03 content

of the flue gas is below 2 ppm and the flue-gas dust content is less than

50 mg/Nm3, (0.04 lb/HM Btu.) Note, in conjunction with the discussion in

Section 4.2.1., above, related to rotary heat exchanger fouling tendencies

4-7

OETE0006835
by upstream SCR reactor operation. that this generally low flue-gas 503

concentration downstream of FGD is of major Significance. Fullest consideration of this and other factors may lead to a broad new preference

for cold--side SCR over high-dust SCR since (48):

o A comparison of the tolerable operating regimes for cold-side and

for high-dust SCR indicates that low flue-gas 502 content in

cold--side operation makes it possible to use catalysts of considerably higher activity since the resulting higher rate of 503

formation in the SeR reactor can be tolerated without any dramatic

increase in formation of the undesirable ammonia-sulfur compounds.

(Ammonia emission or slip in high-dust configurations must be kept

at a low level. Ac~ording to Japanese experience less than 5 ppm

is required in order to achieve a 6000 hour cleaning interval for

the removal of ammonium bisulfate from the air preheater.)

o Cold--side SCR design technology development may be expected to

lead to very low SCR operating temperature. perhaps no more than

lOCoe. in an economical system arrangement that would use a simple

steam coil heater in lieu of a rotary regenerative heat exchanger.

and handles only approximately half the actual flue gas flow

volume of a high-dust SCR system.

o Low flue-gas 503 concentrat~on in a cold-side system makes it

possible to tolerate substantially higher ammonia leakage. In

addition a low flue-gas. particulate concentration permits use of

catalysts of a small geometric pitch having a higher specific

surface. These factors work together to make possible a more

compact reactor design.

o In cold-side installations the SCR reactor temperature is maintained

at an optimum level for the NOx reduction independently of boiler

load and without need for provisions such as economizer bypassing.

o As determined in West German pilot plant tests. catalyst activity!

life in high-dust 5CR operation is substantially shortened in wet

bottom (slag-tap) boiler service due to a characteristically high

alkali metals content of the fly ash.

o In use of high-dust SCR operation in typical dry bottom boiler

service the high concentration of dust reaching the catalyst

erodes it and. at the same time. the flow channels in the catalyst

must be large enough to prevent the catalyst from becoming plugged

up. Erosion will continuously form new surfaces and this calls .

for highly efficient gas flow distribution. Catalyst life is less

than half that of a cold-side SCR installation.

4-8

OETE0006836
4.2.4 Integrated Air-Preheater/SCR-Reactor Design

To minimize the cost penalties for installing and operating cold-side

SCR at large coal-fired electric utility plants when plot-space limitations

make it necessary to do so. or other reasons call for it. more economical

system designs are anticipated that combine the regenerative heat exchanger

and the SCR reactor into a single integrated assembly. Engineering and

operation of such future integrated system designs is expected to include

use of economical coal-based high-pressure steam (in lieu of fired clean

fuel) for the augmenting of flue-gas feed preheat upstream of SCR. and

the advantageous use of a plate type (rather than honeycomb-grid type)

catalyst configuration compatible with the heat exchanger internals.

Air preheater manufacturing interests in Germany have extensive

field programs underway to develop an attractive SCR system design. (45)

the De-NOx Air Preheater. (or a De-NOx Gas-Gas-Heater). for moderate NOx

removal efficiencies in either hot or cold side service. See Figures 4-3

and 4-6 illustrating integrated system designs as contrasted with conventional high-dust and cold-side SCR installations depicted by Figures 4-2.

4-4. and 4-5.

Since the regenerative heat exchangers have a surface area comparable

in size to that of a typical SCR reactor. the basic idea of the development

is to· integrate the catalyst into the heating surface of the already

available Lungstrom-type air preheater and thereby avoid need for cost

and space of a separate SCR reactor. The supplier is concentrating on

the optimum utilization of the element height despite the axial temperature

variation in the basket. and expects efficient. operation of the systems

after the initial "teething" problems have been solved. Despite NOx

removal efficiencies of 60% and higher in early small-scale field tests

an initial large scale. 150 MW{e), test in late 1985 demonstrated far

less. Further new small scale testing is underway in this major developmental program seeking to overcome present obstacles.

4-9

OETE0006837
Figure 4-2. Conventional high-dust SCR application.

4-10

OETE0006838
, f

Figure 4-3. Integrated air preheater/SCR-reactor (high dust).

4-11

OETE0006839
AlP

Figure 4-4. Cold-side SCR (new boiler application).

4-12

, r

OETE0006840
AlP

, r

Figure 4-5. Cold-side SCR (existing boiler/FGD application).

4-13

OETE0006841
.....--N-i3

Figure 4-6. Integrated heat exchanger/SCR-reactor (cold-side).

4-14

OETE0006842
REFERENCES

(In English unless otherwise noted)

1. Seeliger, J. (Association of German Hard Coal Mining Industry,

Essen, West Germany). A Coal Industry's View on Forest Damages

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71. Thompson, J.S., British Gypsum Limited. Personal communication,

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