,a,.. ",'**"~ ~-**  '

...**~,.** 

### ......

. -:-

## -.:.'..,

•• ol"o •

.,' . ....... -" }r' ' •

. :.u.;.; 

### Office of

### AirQ'.lality

### Plamllilgand·Strilld.irds ,fa,_ •**~.1** I

, 

## \'EPA-600/2':88-013



### ,February'I9B8



## -.'

. " , , ,**~~SESS~NT** 

### OF802 ANDNO

### x EMISSION C'::JNTL"I.OL, 

### TECHNOLOGYINEUi\OPE

-;.:.

,- " \

# ... UnitedStales· Environmentalf'rotection Agencv

.,.-."!

. 

# Re'searchand**Qey~lopment**

".-:! •. ::.



# .**'P'r~pared ~f6t\:·**  '. ", I ' ' . 

## _'.-1':-

. i. .:

.' . -. (....
'. ',. 

### (**·~./J**.... '- w 

### •

... - " , (i**,~**..

# ·.~~~'f:**e',rel=Pare~** 

# b:y

. 

# -.

# ..,'
..**~.** 

### Air'and'Energy

### EngincaiingResearch ., LabQratory'". :. Reseafch7Tri!9ng1e**Park,_~C** 

### 27711

..;. "



### ,..... .' 

## ._.


# - 'f"':J. I ,:..,

'.' 

# ..... "-'::..

,..\n. 

# . .. 

# - .... ;-1; 

# ...

,t. r



# --**~~** ::; \i- '.

;. ,. 

# ... .. "



# .. . ,,=,, -'-,r t:",:"",.•'**~)** ;.... , 

## . .:":-,'

.'

., .l ""1 -0 '\,.. 

### ""

.( 

### .." ,".:

r:

r,**(~.**



# ....



### OETE0006809\ '



# f

. R-7 EPAForm22211-1 ._·73) \
' TECHNICALREPORTDATA 

### \ {l'fe=t:retUiJ_r:riOMonthert!PUU**~fon** compleritt6J 

## t 1.REPORTNO. 1 2
• 13.RECIPIENT'SACCESSIOrotNO. I 

### EPA-600/2-88-013 4.TITLEANDSUBTITLE iii.REPORTOATE . 

### AssessmentofS02 andNOxEmissionControl February1988

Technologyin

### Europe 6.PERFORMINGORGANIZATIONCODE

1.AUTHORISI II.PERFORMINGORGANIZATIONREPORTNC. 

### WilliamEllison
ll.PERFORMINGOFlOANIZATIONNAMEANDADDRESS 10.PROGRAMELEMENTNO. 

### EllisonConsultants 4966TallOaksDrive 11.CONTRACT/GRAN' NO, 0 

### Monrovia. Maryland 21'7'70-9816 EPA 

### PurchaseOrder 6Dl772NASA 12.SPONSORINGAGENCYNAMEANDADDRESS 13.TVPEOFREPORTANDPERIODCOVEPlED 

### E,PA, OfficeofResearch

### andDevelopment Final; 4/86-8/87 14.SPONSORINGAGENCVCOOE 

### AirandEnerDEniineeringResearch**Labora~ory** 

### EPA/600

### /13 

# r ResearchTriangle**P~k,** 

### NC 27711
111.aUPPLEMENTARYNOTES 

### AEERLprojectofficeris Charles B. 

### Sedman.**~ail-Drop** 4, 919/ 

### 541-7700. 

### -**~,** 1- ' 1e.ABSTRACT 

### Thereportis acompilationofinformationonthecurrentstatus ofabatementtechnologyusedtocontrolmajor air

### pollutants. includingS02 andNOx, in 

# -, 

### Europe. It

### focuses onfluegas sulfurization(FGD). combustionmodification (CM), andselectivecatalyticreduction(SCR) ofNOx. Informationpresentedwas gathered fromutilitycompanyrepresentatives andFGD, CM, andSCRprocessdevelopers.

" 

### as wellasfromthe author's research. Currentair

### pollutionregulations in 

### Europe,--'" ->i 

### relatedproblems. operationalparameters ofcommercialFGDandSCRplants, FGDandSCReconomics. andtheauthor's evaluationoftheprocesses are alsodescribed.

,

,

- 7. KEYWORDSANDDOCUMENTANALYSIS 

### la, OESC"II"TO"S b.'DENTIFIERS/OPENENDEDTERMS c. CDSATIFiddfGroup 

## .,

Pollution Combustion PollutionControl l8B Emission Catalysis StationarySources 14G " 

### SulfurDioxide Economics Europe 07B 05C NitrogenOxides Boilers' WestGermany l3A 

## .. FlueGases WasteWater 2lB Desulfurization FossilFuels 07A.07D 

### 2lD
18.DISTRJBUTIONSTATEMENT 111.SECURITYCLASS(11tUReport) 21.NO.OFPAGES 

### Unclassified 96 Release

### toPublic 20.SECURITYCLASS(1'hUpqc) 22.PRICE 

### Unclassified



### OETE0006810

### EPA-600/2-88-013 February19BB



### 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 ProtectionAgency

Research Triangle Park. NC 27711

Prepared for: Office of 

### Research and Development U.S. Environmental Protection Agency 

### Washington. DC 20460



### OETE0006811TABLE OF CONTENTS Item Foreword Abstract Table ofContents Figures Tables Abbreviations and Symbols Acknowledgements Executive Summary SECTION 1 STATUS OF S02 

### AND NOx EMISSIONREGULATIONS 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 HO

### xREGULATIONS 1.2.1 1983 and Superseding 1984Legislation 1.2.2 Comparisonwith 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

### ANDACCORDS 2.1.1 Size ofFGDMarket 2.1.2 Principal Boiler Fuels in Use 2.2 OVERVIEW OF PRINCIPAL FGD TECHNOLOGYAPPLICATION 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 FGDTECHNOLOGY 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 

### WastewaterManagement 2.4.4 

### FGD By-Product GypsumManagement SECTION 3 STATIONARY SOURCE DE-NOx DEVELOPMENT AND 

### APPLICATION 3.1 BOILERS AFFECTED BY 1984 LEGISLATION/ACCORDS 3.2 

### OVERVIEW OF PRINCIPALDE-NO

### xTECHNOLOGY APPLICATION 3.3 

### APPLICABILITY OF SCRTECHNOLOGY 3.4 

### OTHER POST-cOMBUSTION CONTROL TECHNIQUES 3.5 COMBUSTIONMODIFICATIONS 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 SCRTECHNOLOGY 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 OTHERPOST-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 NO

### xREMOVAL 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 S02Emissions 7.2.2 NOx Emissions 7.3 SWEDEN 7.3.1 S02Emissions 7.3.2 NOx Emissions 7.3.3 Fuel OilUsers 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



### OETE0006814EXECUTIVE 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 otherEuropean 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 midwesternU.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 400milligrams (mg) per normal cubic meter (NII!.3) of flue gas. for newand existing boilers greater than approximately 110megawatts. i.e. HW(e), size. As of 1986. more than 100

### FGD systems with greater than 40,000HW(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 beingutilized 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 400more FGD installations aggregating approximately 25,000Mi(e) of capacity on boilers in the slze range 35 to 110MW(e). Land availability inmainland European countries is such that it is generallynecessary 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 compliancewith the 1993 S02 control deadline. StringentWest German S02 legislation in 1983 was followed in 1984 by enactment ofvery stringent new nitrogen oxides (NOx) limits calling for**emisSio~s** of no more than 200mg 

### 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 110MW(e), size. As of 1986 approximately 50 high-effic1ency commercial systems aggregating more than 10,000MW(e) capacity. most for retrofit addition, have been purchased in West Germany alone. and approximately 30,000MW(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. Anumber of adaptations of typical SCRtechnology 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



### OETE0006815some 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 billionWest Germanmarks 

### bf the early 19908 is bringing about a new and extraordinary, eontinent-wide effort to accomplish substantial abatement of acid precipitation effects throughmajor andWidespread reductions in 502and HOx emission inventories.

xiv



## OETE0006816

## ·

# .

SECTION 1
STATUS OF S02 AND NOXEMISSION 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 portionof the country, as well as BadenWuerttemberg 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 110MW{e) have been required to add stack gas cleaning by 1988. Reduction of emissions from smaller boilers. 18 to 110HW(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 110MW(e) requires that S02 emission reduction be 75% (rather than 60%). Informed opinion inWest Germany believes that the 400 mg S02/Nm3 (144 ppm) requirement for boilers above 110MW(e) may well be lowered to approximately 200ag (72ppm) or less by 1990 or before. Similarly. the 6.0%-relllOval requirement level for 35 to 110KW(e) boilers may be expected to be increased in the next severalyears. 1-1



### OETE00068171.1.2 Other Stipulations of 1983 GFAVO After declaration of individual boiler owners by July I, 1984, any existing boiler larger than 110MW(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 2,500mg/Nm3, (900 ppm.) Additionally, the 1983 lawrequires that flue gases in the stack folloWing desulfurizationmust 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) inNorth**Khine~estphalia,** (With nearly 50% of the electric power generation of the entire country, a large portionbeing fired withlignite), -special requirements were placed on approximately 3,000MW(e) of existing lignite-fired boiler capacity in 1984 calling for an interim 502 emission reduction of 110,000metric tons peryear by 1987 (through temporary low-capital-cost dry-alkali injection means.) 1.1.3 1986Legislation for Industrial Plants Emission limits for small existing industrial boilers, e.g. 1% sulfur fuel-firedunits larger than approximately 6,500 lb/hour steam generation, the equivalent of approximately 0.5 MW(e), are addressed in new national legislation (TALuft) ofFebruary 27, 1986 (5). Withmany exceptions, it is specified that boilers emitting more than 5kilogram 502 per hour must limit emissions to- 500mg/HlD3, (180ppm). 1.2 WEST GERMAN NOxREGULATIONS After enactment of the major 1983 S02 legislation, which imposed modest NOxrequirements, 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 ofdeadlines by the individual provincial jurisdic- tions.

1-2



### OETE0006818Category 1.2.1 1983 and Superseding 1984Legislation 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 200mg per standard cubic meter, 

### a level equivalent to approximately 100 ppm (volUllle). An approximate equivalence between the four most common emission concentrationmeasures is: 

### 1mg/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 thejudgement that it is demonstrated to be capable of reducing emissions to this310w level. [NO x limits, 1984 basis, for new oil-fired units are L50mg/Nm above 110 MW(e) and 300mg/Nm3 from 18 to 110**MW(e~.** For'existingunits ofunspecified future lifetime the limits are 150 mg/Nm above 110MW(e) and 450 mg/Nm3 from 18 to 110MW(e).} TABLE 1-2 NOx CONTROL REQUIREMENTS FORWEST GEIlHAN COAL-FlRED BOILERS NO



### x 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: 200mg/Nm3 equals approximately 0.16 lb/MMBtu.

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 hours3of operation, during which they will be allowed to emit 650mg N02/Nm , Le. approximately 325 ppm, (1,300mg/Nm3 for wet bottom), above 18HW(e), (450mg/Nm3 for o11-f1red units.) As in the case of 502' surveillance ofHOX 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 limitvalues 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 ofgreatest forest-damage severity was tbe first to impose prompt deadlines for the stringent 1984NOx emission limits 

### (8). Dry bottomboilerst both new and existing, IIlUst comply by 1988, wet (molten-ash) bottom. boilers by 1990. Similar deadlines have also been established by other statejurisdictions including NorthRhine-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 1990resulting in an average of 70% reduction in NOx emissions. 1.2.2 Comparisonwith

### U.S.A. and Japan The extremely stringent 200mg/Nm3 requirement for both new and existing coal-fired boilers above 110MW(e) size surpasses NOx control requirements 1n all other nations including Japan. See Table 1-3 (9). The West GermanHOx stringency for boilers above 110HW(e) is all the more remarkable, taking into account thatmost HOX emissions are from mobile sources. (Hate that additional regulations are being considered inWest Germany thatwill require lead-free fuel and catalytic converters for gasoline-fueled automobiles.) TABLE 1-3 COMPARISON OF NOxEMISSION STANDARDS FOR COAL-FIRED UTILITYBOILERS Country West Germany, Hew and Existing over 110MW(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-bottomboilers. However, the very substantial reduction that will be required from the uncontrolled NOx emission levels illustrated by Table 

### 1-4 (6) is resulting inWidespread application of SCi to essentially all German boilers larger than 110HW(e).**~reover.** since it is necessary to sustain ample boiler temperatures inwet bottom boilers sufficient to maintain bottomash in a molten state, only 1I1nor reduction in HO

### x 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 ofWest Germany significant NOx control legislation has also passed or is pending in Austria, Switzerland, The Netherlands, Denmark. Sweden and the EuropeanEeonomic 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 300mg/Nm3 for existing boilers (11).



### 1-5



### OETE0006821TABLE 1-5 EFFECT OF AMENDED EUROPEAN COOIUNITY DIRECTIVE Emission Limits (mg N02/Hm3) 1983 Proposed Directive Coal Oil All Plants over 50Wet)* to 1995 800** 450 after 1995 400*** 220 1985 Amended Directive

to 1995: over 50Wet) 450 50-100MW(t) 800** 100-300MW(t) 800 over 300 !!W(t) 650 after 1995: over 50!!W(t) 150 50-100MW(t) 400*** over 100 MW(t) 200 Gas
350 180
350

100

*Note that 100MW(t) equals approximately 37 MW(e). **1300mg/Nm3 for slag tap furnaces ***800IIg/Nm3 for slag tap furnaces 1.2.5 1986Legislation for Industrial Plants The new federal regulations 

### (TA Luft) issued on February 

### 27, 1986, limit

## NOx emissions fromindustrialplants nth 

### an output of**m~re** than 5kilograms as N02 per hour, generally to a limit of 500mg/Nm. (As noted earlier, the

## SOz emission limit for industrial plants with an S02 output ofmore than 5kilograms per hour has been set a a nominal level of 500mg/Nm3). Othernew NOX limits imposed by the February 1986 legislation are as follows:
o Solids incineration, less than 50 !!W(t), i.e. 18MW(e)

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

- Other 500mg/Nm3
o Oil incineration, less than 50MW(t)
o Gas incineration, less than 100MW(t)
o Gas Engines

- Diesel More than 3MW(t) Less than 3HW(t)



### 1-6 250IIg/Nm3 200mg/Nm3

2,000mg/Nm3 4,000mg/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 350mg/Nm3



### OETE0006823SECTION 3 STATIONARY SOURCE DE-N0x DEVELOPMENT AND APPLICATION


### 3.1 BOILERS 

### AFFECTEDBY 1984 LEGISLATION/ACCORDS 

### Referring to the earlier Table 2-1, it 

### can be 

### seen thatmore than 150West German boilers are impacted the 1984 federal/provincial NOx control accords requiring reductionofHOx**e~ssions** 

### from units larger than 110MW(e) to the level of 200mg N02

### !Nm , equivalent to 100ppm (vol.) and to 0.16 Ib/MM Btuheat input. Also affected are 7,400MW(e) of new, coal-burning units under construction or expected to start up by approximately 1990. 3.2 OVERVIEW OF PRINCIPAL DE-No,. TECHNOLOGYAPPLICATION 

### The emission limit, (200 mg/Nm3), 

### set in 1984for boilers above 110MW(e) is well beyond the capabilities ofcombustionmodification techniques and requires the use offlue gas cleaningprocesses 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 canbe expected to be 

### broadly applied inEurope. 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 inWest 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 electricutility plants inWest Germany of extensive commercial SCR

### experience in comparatively new. base-loaded boilers in Japan. approximately 50 SCR

### pilot plant trains have beeninstalled 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 onuse of SCR

### downstreamof FGD (cold-side), including 11 with activated carbon. Extensive high-dust

## sea field p11ot-scale investigation is taking place because Germanboilers 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 ofconcern. 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 SCRuncertainties, catalystlife guarantees have since 1984, increased from 1 year to two years or more (24). Of 10competing SCRsystem suppliers in Germany, 6 are licensees of Japanese process licensors while 

### 3offer 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 90o

## e, (194°F) and requires less reheating of the water-saturated gas prior to the SCRstep. An American licensor, Norton, uses a zeolite type catalyst. As early as 1984 26 specific initial commercial installations were anticipated. several to be applied downstreamof

### FGD because of inadequate plot space to permit normal tie in of the SCRreactor upstream of the air preheater. (See Fig. 3-1) (16). As noted earlier. in some provinces such as Baden-Wuerttemberg, themost 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 underway to date. The first 1II8jor SCR facility has been installed on a 460MW(e) bituminous-coal-fired. dry bottomboiler and commenced operation in early 1986. Another early installation of 160HW(e) capacity on a bituzinous-coal-fired, wet bottom boiler.will achieve close to 90% NO

### xremoval. 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 3500 

## e (302D

### Fto less than 662°F), whereas an SCRreactor typically positionedupstream of the air preheater operates at approximately 350°C (662DF). Full-scale power plant testing (41) indicates feasibility of selective non-catalytic reduction (SNCR) at lOOO°C (1832°F) with approximately 50% NOx removal (withoutundesirable, partial conversion of S02 to S03 that accompanies SCR operation). As per Table 4-1, 940 MW(e) of SNCR capability is being installed inWest Germany. Anumber of pilot plants have been installed inWest 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-gypsumproducing process that is reported to use a ferrous complex ion (FeEDTA) in conjunctionwith 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!NOxprocesses are seen to have possible economic advantages the tight deadlines (compliance as early as 1988 inmany instances) are leading to a preferred use of the more commercially established technology based on SCR. 3-2



### OETE0006825Figure 3-1. Configuration of alternative Sel

### De-NOX plants in combination with FGD.



### 3-3



### OETE00068263.5 COMBUSTIONMODIFICATIONS 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 NOxreductions 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 thewet slag properties and possibly hinder its drainage from the bottom of the boiler. Brown coal (lignite) fired power plants (9), constituting another substantial portion ofelectric power production inWest Germany, also present unique problems for NOX emission control because of special firing arrangements required and because ofhigh 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 maintaininghigh 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-firedutility 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. Theirultimate 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 ofboilers 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. Newboilers inWest Germany equipped with recently-developed low-Hex

### b~rnejs emit 800mg N02/m3 in the case of dry bottom design and 1,300mg N02/m in the case ofwet bottomdesign (6). In one of the most recent 

### 3-4



### OETE0006827applications in dry-bottom service low-NOx burners are beingused in conjunction with application of over-fire air to try to achieve an emission rate of 650mg 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-termpromise. It is believed to have the potential to decrease the HOxlevel below that achieved with other burner technologies by 30 to 50%. Asecondary 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, corrosionand slagging (43). The injection of secondary fuel leads to a high concentration of hydrocarbon radicals in a zone ofhigh 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) ornitrogen 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 (indirectHO 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 IFNiprinciple 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 40MW(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-modificationmethod 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



### OETE0006828SECTION 4 SELECTIVE CATALYTIC

REDUCTION (SCR)
4.1 OVERVIEW 4.1.1 Process Description The SCRprocess 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 proceedwhen the gas temperature is from

## aoooe to 10000

## e (1470°F to 1830°F), which is the basis for the selective noncatalytic reductionmethod. However, in the presence ofa suitable catalyst, the reaction proceeds with a gas temperature of 3000

### e 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 upstreamof the air preheater. This is the basis for the utility SCRprocess', which is theoretically capable of achieving 85 to 95% NOxremoval for ammoniainjections of .85 to 1 mole NR3 permole of NOpresent. Note also thatwhen the SCRoperation is carried out downstream ofFGD (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 SCRoperation 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 6to 10x 10 1ID1 size and flows parallel to the solid channelwalls which have a thickness of about 1.5 mm. Basic material for the catalyst is Ti02 to whichvanadiumand/or tungsten as active material and a binding agent have been added. Catalysts are installed in layers in the reactor leavinga free space of 1-2mbetween layers. Honeycomb elements are combined to formmodules. 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 orunder construction inWest 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



### OETE0006829TABLE 4-1 PRINCIPAL SCRTECHNOLOGY 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 SNeRcommitted 940 3 x Approximately 30,000MW(e) of large boiler capacity in North Rhine-Westphaliawill be equippedwith SCI.by 1989 or 1990. By 1990 3700MW(e) ofHOx removal systems, primarily SCR, will be installedin Baden-Wuerttemberg. In all, the boiler

### HOX emission inventory throughout West Germany will ultimately bereduced by 0.7 millionmetric tons, principally by SCI. (44). 4.1.3 Earlier Japanese Activity In the work 

### 1nJapan leadingup to present applications in Germany the process manufacturers have routinely designed the SCI. reactor for 80% NOx removal andhave often designed for 90% removal with a guarantee of 80%. The catalysts are alsowarranted for 1 to 2years 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 ofheavy 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



### OETE0006830o SCR reactor plugging with ash
o Plugging of the air preheater and induced draft fans with dust and ammoniumbisulfate
o Ammonia bypass leakage with a resulting contamination of the

fly ash and the FGDwastewater
o Difficulties withmaintenance and accuracy of the

### NOX and NB3 instrumentation 4.1.4 Stringent Removal-Efficiency Requirements While Japanese practice has established 80% NOx removal in SCRas a generally practical maximum level to avoid significant ammonia leakage to the downstream air preheater and FGD system, permittingby 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 ofVEBA Kraftwerke at Knepper, 1986 initial startup, on awet bottomboiler 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 370MW(e) SCR capacity. will alBO achieve a 200 mg/m3 NO x 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 beenmade to establish design criteria for the air preheater to make it compatible with common high-dust SCR. operation upstream. (A similar concernwould apply in connectionwith operation of rotary heat exchangers downstream of cold-side SCR..) In reducing flue-gas streamtemperatures as low as 150°C to 230°C (300°F to 450°F) the air preheater causes excess NH3 vapor from the SCRoperation to react with water vapor and !lOst of the 503 gas present to form the compounds 8l!Il1Onium bisulfate and ammoniUIII sulfate. (The SCRreactor 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 (482DF) and ammoniumbisulfate 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 5ppm. This can be expectedwhen SCR is operated at BOx removal efficiency substantially higher than 80% or, even at lower efficiencies when, toward 4-3



### OETE0006831the end of the usable life of the catalyst charge, increased ammonia feed is used to maintain required NOxremoval 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 ammoniumbisulfate 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 ofdeNOx-compatible air preheaters (and gas-gas heaters for cold-side

## scaas applicable):
o The heating surfaces must have a configuration that is easily cleaned bymeans of soot blowing.
o The cross-over of heating-element layers must be avoided in the areamost 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-linewaterwashing of the air preheatermust be anticipated; unlike rotary regenerative heat exchangers used to achieve flue gas reheat downstream ofwet FGD. air preheaters downstreamof

## sca cannot be water washed on-line. 4.2.2 Difficulties inRetrofit Installation of 

### sea Because of the large size of the

## scareactor,'systemretrofitting 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 370MW(e) 

## scaretrofit 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 converterwhereby the planned unit start-up date would be maintained and an emission value of 200

### mg NO x/m3would be achieved. The results of this study showed that it was possible to install an

## sca systembetween boiler end and air preheater, with a flue gas volume of 1.1 millionm 3

### /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



### OETE0006832and the load-bearing structure of the bo11erhouse facade, itwas possible to retain the exterior design of the boilerhouse. The reactor was designed for four converter levels andwithone 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 20mbar (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 40meters
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 SCRreactorhousing
o Installation of the reactor "bypass ducts
o Installation of the economizer bypass, including opening of

the boilerwall 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. Otherwork 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



## OETE0006833Reactor bypass Economizer**De~NOx** bypass reactor

Figure 4-1. Cross-section of SCR system retrofit. side views/plan view.



### 4-6



### OETE00068344.2.3 Cold-Side SCR In Japanese and European programs to retrofit SCR systems for fluegas 

### NOxremoval. 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 itmay be necessary to use a "cold side", i.e. tail end. installation, adding SeRdownstreamof 

### 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-side

### seaoperation (downstream of wet 

### FGD) is a 1.320.000Nm3/hr (820.000 scfm) 1979 installation. the equivalent of 330

### MW(e), at an iron are sinter furnace of Hippan Kokan KKat its KeihinWorks 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 ppmflue-gas HO

### xconcentration to 30ppm. 1979 capital cost of the system installation is understood to be 6.7 billionyen, 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 inWest Germany announced to date (38) are small capacity Withgenerally poor economics of scale. 

### Amunicipal power plant, which is installing three 35KW(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 HO 

### x emission to 200

### mg/Nm , is projected to have capital cost of 250 UKperkW (and a unit cost of 2.5 Pfg perkWh) (47). In a new boiler application of SCR, the greater apparent Simplicity and economy of a hot-side installationmay 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 SCRyields approximately 500

## e (90°F) of flue gas reheat, and thus eliminates need for reheat facilities thatwould 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 systemreliability is expected to be betterwith 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 

### 2ppm and the flue-gas dust content is less than 50mg/Nm3, (0.04 lb/HM Btu.) Note, in conjunctionwith the discussion in Section 

### 4.2.1., above, related to rotary heat exchanger fouling tendencies 4-7



### OETE0006835by upstream SCR reactor operation. that this generally low flue-gas 503 concentration downstream of FGD is ofmajor 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 Acomparison 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 SeRreactor 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 SCRdesign 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 inWest 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 SCRoperation 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. Erosionwill 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



## OETE00068364.2.4 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 systemdesigns 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 contrastedwith conventional high-dust and cold-side SCRinstallations 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 SCRreactor. 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 optimumutilization 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. 150MW{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



### OETE0006837Figure 4-2. Conventional high-dust SCRapplication.



### 4-10



### OETE0006838

# , f

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

4-11



### OETE0006839AlP

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

4-12 

# , r

OETE0006840AlP 

# , 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 CoalMining Industry, Essen, West Germany). ACoal Industry's View on Forest Damages and Air Pollution in the Federal Republic of Germany. Symposium on Acid Rain. Washington, DC. June 10, 1986. 2. Federal Republic of

.Germany, Thirteenth order implementing the Federal Emission Control Act (large furnaces order)

- 13th BImSchV. cabinet decision of June 14. 1983. (German language) 3. Leutzke. K. and Stahl, R. Continuous Em1ssionMonitoring for S02 and NOx in the Federal RepUblic of Ger1lll1ny. Seminar, Graz, Austria. May 1986. 4. Peutz, H. and Bartholot, R.D. Reduction of

### SOz and NOx Emissions from Stationary Sources in North Rhine-Westphalia

- Strategy and Results. Fourth Seminaron the Control of Sulfur and Nitrogen Oxides from Stationary Sources, Graz, Austria. 

### Hay 1986. S. Leimkuehler, 

### J., GEl. Personal communication, 

### Kay 31. 1986. 6. Keinhorst, R. Legal Instruments and the State ofTechnology for

.Reducing HOx**~ssions** 

### in theFederal Republic of Germany. In:

Proceedings: 1985 Symposium onStationary CombustionNOx Control, Volume 1. EPA-600/9-86-021a (NTIS PB 86-225042), July 1986. 7. Dacey. P.W. An 

### Overviewof International NOx Control Regulations. In: Proceedings: 1985 Symposiumon Stationary Combustion NOx Control. Volume 1. EPA-600/9-86-021a (NTIS PB 86-225042), July 1986. 8. 

### Rentz. O. and Beer, W. Application of de-NOx Technologies Federal Republic of Germany and Europe. In: Proceedings: Symposiumon Stationary CombustionNOx Control, Volume 1, EPA-600/9-86-02la (NTIS PB 86-225042), July 1986. in the 1985

9. Hein. K.lt.G., Ronig, J., 

### and Roppe, V. Reduction ofNOx-emissions for Brown Coal Combustion Systems in the Federal Republic of Germany. In: Proceedings: 1985 SymposiUlll on Stationary Combustion NOx Control, Volume 1, EPA-600/9-86-021a (NTIS PB 86-225042), July 1986. 10. Amended proposal for a council directive on limitation of pollutants from large combustion plants. COM(85) 47 final. Brussels: European Commission. Februarr 1985. 11. Hackl, A., Technische UniversitatWien. Personal communication, November 6, 1985.

R-l



### OETE000684312. Ellison, W. Survey Report and Assessment of Utility Flue Gas Desulfurization System Installations in Europe. In: Ninth Symposium on Flue Gas Desulfurization, Cincinnati, Ohio. June 1985, Volume 1, EPA-600/9-85-033a (NTIS PB 86-138641), December 1985. 13. REA fur 33,000 HW (FGD for 33,000HW), Energie, Volume #6, Number 12, December 1984. (German language) 14. Der stand der nachruestung bei der rauchgasentschwefelung, elektrizitaetswirtschaft, Jg 85 (1986), Heft,S, pp 171-174. (German language) 15. Davids, P., Baug, N., Lange, H., Cels. B. -J., and Schmidt. B., (UBA/Berlin). Luftreinhaltung bei kraftwerks und 1ndustriefeuerungen. BWK, Volume 37, Number 4. April 1985. (German language) 16. Qu1ttek, C. Flue Gas Desulfurization and NOx Removal Processes and Latest Developments, Deutsche Babcock Anlagen A.G. 1986. 17. 'Kondo, K., Pure Air. Personal cOIIIDlnication, October 23. 1985. 18. Olson. D•• GEESI. Personal communication. December 13. 1985. 19. Byrne, R.E. Gypsum Producing Wet FGD Systems Emerge As the Dominant Process in the World Wet FGD Market. Joint Power Generating Conference. 1983. 20. Escbe, M., Saarberg-BoelterUmwelt Tecbnik. Personal communication, May 21. 1985. 21. Le1mkuehler, J., GEA. Personal communication. January 6. 1986. 22. Forck, B., VGB. Personal communication. August 25, 1986. 23. Pietrzeniuk, H. Utilization of Residues of Desulfurization and Denitrification Technologies. Seminar, Graz, Austria. May 1986. 24. Forck, B. Flue Gas Desulfurization and NOx Reduction. Technical Conference, Malmo, Sweden. November 6, 1985. 25. Giovanetti. A•• Davy McKee. Personal communication, August 26, 1986. 26. Florack, F. Walther. Personal communication, October 17, 1986. 27. Erga. O. S02 Recovery by Means of Adipic Acid Buffers. Seminar, Graz. Austria. May 1986. 28. LaDgenkamp. H•• and Van Velzen. D. The Community's IspraHark 13A Process for Flue Gas Desulfurlzation. Energy in Europe. 1986. 29. Tokerud, A., and Naess, E. The Flakt-Hydro Process

-**S~** Removal by Se,awater. Seminar, Graz, Austria. Hay 1986. 

### R-2



### OETE0006844

### 30. Felsvang. K •• NiroAtomizer. Personal communication, October 17, 1986. 31. Schmale, C., and Dietl, R. Experience in the Operation of a Dry/ 

### Semi-Dry Flue Gas Desulfurization Plant (FGD) According to the Lurgi Circulating Fluid BedAbsorption Process (CFB) in the Schwandorf Power Station of BayernwerkAG. Third Annual Convention of the VDI-Gesellsehaft Energietechnik, Darmstadt, West Germany. February, 1986. 32. Chughtai, M.Y. 

### Results ofDirectDesulfurization from COllllllercial Power Plants. In: Proceedings: 1986 Joint Symposiumon Dry 

### 502 and SilllUltaneous S02/NOx ControlTechnologies, Volume 2, 

### EPA-600/9- 86-029b (NTIS PB 87-120457), October 1986. 33. Reese, J.L., et ale 

### Evaluation of Sorbent Injection Test at Tiefstaclc. West Germany. In: 

### Proceedings: 1986Joint Symposium on Dry 

### 502 and Simultaneous S02/Nex ControlTechnologies, Volume 

### 2. EPA-600/9-86-029b (NTIS PB 87-120457). October 1986. 34. Kenakkala, T•• et a1. 'TheTampellaLIFAC S02 Removal Process. In: Proceedings: 1986Joint Symposium on Dry 

### S02 and SiIIlUltaneous SOz/NOx ControlTechnologies, Volume 2, 

### EPA-600/9-86-029b (NTIS PB 87-120457), October 1986. 35. Leimkuehler, J., GU. Personal communications, November/December 1985. 36. Clay, D.E. andVeser, K., 

### 'KraftanlagenHeidelberg. Personal communication, October 28, 1985. 37. 

### Clay, D.E. and Veser. K., 

### K'raftanlagenHeidelberg. Personal communication, March 25. 1986. 38. Slakey, 

### P.B., DB Gas Cleaning. Personal communication. November 

### I, 1985. 39. Kappe, J., Kappe IntermediairBV, Personal communication, March 29, 1986. 40. Kappe. J•• andEllison, W. 

### Utilization ofResiduals from Flue Gas Desulfurization. Annual Meeting, American Institute of Chemical Engineers, Chicago, Illinois. November 1985. 41. Hittelbach, G., and Voje, H. Application of the SNCR Process to CycloneFiring. Special VGB Meeting,

## NOx Emissions Reduction, June 1986.

R-3



### OETE000684542. Sekiya. T•• and Ellison, W. Simultaneous Nitrogen Oxides and Sulfur Dioxide Removal by Absorption-Reduction Scrubbing. Fifth National Conference on Energy and the Environment, Cincinnati, Ohio. October 1979. 43. Leikert. K•• Reidick. R. and Sehuster, R. Low HOx-Emission Combustion of Fossil Fuels in the Federal Republic of Germany. Fourth Sellinar on the Control of Sulfur and Nitrogen Oxides from Stationary Sources, Graz, Austria. May 1986. 44. Lange, M. (Director of the Office of Environment, Berlin). Regulations for and Fulfillment of Requirements for NOx Emission Restrictions in Large Furnace Systems in Europe, 1985. (German language) 45. Clay, D.E. and Veser K. Regenerative heat exchangers used in envirotUDental technology. VGB Symposium, 1986. 46. Necker. P. Reduction of BOx Emissions frOll1 Coal-Fired Power Plants Using the SCR Technology. Seminar, Graz, Austria. May 1986. 47. Minderung von stickoxidemissionen aus kohlekraftiwerken in BadenWuerttemberg. Joint Commission Report for Province of**Baden~uerttemberg,** October 1984. (German language) 48. Berrlander, B. BOx Reduction-Methods and Pilot Testing. Modern Power Systems (UK). April 1986, pp 33-37. 49. Knoblach, K. and Juentgen, H. Active Coke Processes for S02 and NOx Removal from Flue Gases. 'l'hird Symposium on Integrated Environmental Controls for Fossll-Fuel Power Plants, Pittsburgh, Pennsylvania. February 1986. 50. Mika, C., et a1. Simultaneous 502 and BOx Abatement by the Sm.. Process. VGB SpecialMeeting: Test Units for NOx Emission Abatement, Essen, West Germany. June 1986. 51. Markovic, V., IAEA. Personal cOllllDunication, September 10, 1986. 52. Attfellner, H., Lotepro Corporation. Personal communication, September 15, 1986. 53. Morsing, P. Baldor TopsoeA/s. Personal communication, October 30, 1986. 54. Schaerer, B., and**~ug,** N. The Cost of Flue Gas Desulfurization and Denitrification in the Federal Republic of Germany. Seminar, Graz, Austria. May 1986. 55. Van der Brugghen, F.W., KEMA. Personal communication, August 29, 1986.



### R-4



### OETE000684656. Bloem, P.J.C., and Sciarone, B.J.G. Application of Spray Dryer Products at the Sand-Lime Production. In: Proceedings: 1986 Joint Symposium on Dry S02 and Simultaneous S02/NOx Control Technologies. Volume 2,**EPA-600/9~86-029b** (NTIS PB 87-120457), October 1986. 57. Hackl, A.E•• Striwe, W., and ROssina. I. Status of Emission Control on Power Plants and Large Industrial Boilers in Austria. Expert Meeting on Pollution Control ofCoal Combustion. Vienna, Austria, 

### May 1986. 58. Assarson, B., SwedishMinistry ofAgriculture andEnvironment. Swedish Strategy to Reduce Emissions of Sulfur and Nitrogen Oxides. ENCLAIR '86/International Symposium onEnergy and CleanerAir: Costs of Reducing Emissions, Taormina, Italy. October 1986. 59. Rosby, S-O. Flakt Industri

### AB. Personal communication, August .28, 1986. 60. Hanell, B. The National SwedishEnvironment Protection Board. Personal communication, December 27, 1982. 61. Hanell. 

### B. Personal communication, April 23, 1985. 62. lEAFlue Gas Treatment, prepared by Denmark National Agency of Environmental Protection andElkraft. Workshop in Japan, November 11, 1986. 63. Tokerud, A. A/S NorskViftefabrikk. Personal cOIlllll1nication, September 16. 1986. 64. -Acid Rain- Abatement, Council ofMinisters. Press Conference. Centre Interprofessionnel Technique D'Etudes de la Pollution Atmospherique (CITEPA), October 23. 1985. 65. Government of Switzerland. Emissions ofAtmospheric Pollutants in Switzerland: Extent, Development, andMeasures Taken So Far. Seminar. Graz. Austria. 

### May 1986. 66. Snaddon, R., GEESI. Personal communication. August 1, 1986. 67. Italian-U.S. coal report released. Electric Light and Power, August 1986, p. 48. 68. Ricci. A., ENEL. Personal communication. October 2. 1986. 69. Irabien. A •• Universidad del Pais Vasco Euskal Herriko Unibertsitatea. Personal communication, August 29. 1986. 70. Norway Upsetwith New British Power Plant. Norway Times/Nordisk Tidende. June 26. 1986.

R-5



### OETE000684771. Thompson, J.S., British GypsumLimited. Personal communication, September 2, 1986. 72. Barckham, D., A:l.roil-Flaregas Limited. Personal communication, September 15, 1986. 73. Erstmals Rauchgasentschwefelung. Umweltmagazin, October 1986. 74. Anton, P., and Griffin, L. Environmental Protection in Europe

- Standards, Tec:hnologies, Trends. Third International Conference on Clean-COal Technologies and Acid Rain, Washington, DC, October 1986.

R-6



### OETE0006848