SOX AND NOx REMOVAL FOR COAL-FIRED BOILERS INJAPAN

by

Jumpei Ando Faculty of Science and Engineering Chuo University Tokyo, Japan

to be presented at 

### THE SEVENTH SYMPOSIUMONFLUEGAS DESULFURIZATION Hollywood, Florida

May 17-20, 1982

Although fhe research described In this paper has belllf funded whollyor in part by the Un;ted States Environmental Protection Agency. it has not been**~"'I~-'~rl** to Agency review and therefore does not neC3-:z-. "12 vieWS 01theAgencyandnooffici::1 endorsem'**'~rred..**



# IPHAB004228sax AND NOx REMOVAL FOR COAL-FIRED BOILERS INJAPAN Jumpei Ando Faculty of Science and Engineering Chuo University, Tokyo

ABSTRACT Combined sax and**~Ox** removal from flue gas from coal combustion has become more and more**im~ortant** with the increase of coal-fired boilers. Stringent Legulations in Japan necessitate the combined removal even for flue gas containing about ZOO ppm each of SOx and NOx derived from controlled combustion of low-sulfur coal. Flue gas cleaning, including selective catalytic reduction (SCR) of NOx' electrostatic precipitation, and the wet limestone-gypsum flue gas desulfurization (FGD) process, has been applied successfully to three coal-fired boilers, removing 50-85iof NOx' 99.9-99.95% of particulates, and 90-957. of SOZ' Thirteen similar cleaning plants are under construction for coal-fired boilers. Ammonia at the SeR reactor outlet is maintained below 5 ppm so as to give no adverse effect on FGD and the quality of fly ash, although wastewater treatment to remove ammonia may be required in certain regions. Cost of SCR is about one-third that of FGD by the limestone-gypsum process in both investment and operation. The power generation cost, including the flue gas cleaning and wastewater treatment, is less than that with low-sulfur oil without flue gas cleaning. The development of the combined cleaning system for coal has contributed significantly to save oil and to solve the energy problem in Japan. Simultaneous SOx and NOx removal by the electron beam and activated carbon processes has been tested.



# IPHAB0042291. INTRODUCTION Ambient SOZ concentrations in Japan have been lowered remarkably to meet the stringent air quality standard of 0.04 ppm daily average (equivalent to 0.02 ppm yearly average) in nearly all regions due to the strenuous efforts of SOx abatement including the construction of more than 1400 commercial FGD units. For NOx abatement. combustion modification has been applied to more than 100,000 gas sources which provide about 95% of total flue gas. NOx concentrations in flue gases from utility boilers have been reduced by combustionmodification to 200-300 ppm for coal, 80-120 ppm for oil, and 40-80 ppm for gas. Automobile emissions have been controlled by the most stringent regulations, including 0.Z5 g NOx/km for gasoline-engined passenger cars. The fact that ambient N02 concentrations exceed the strict standard (Table 1) in several regions indicates that flue gas treatment (FGT) for NOx removal is needed.

TABLE 1. AMBIENT AIR QUALITY STANDARDS, ppm
S02 NOZ Daily Yearly Daily Yearly Country average average average average Japan 0.04 0.02 0.04- 0.02- 0.06 0.03 U.S.A. f).03 0.05 West Germany 0.05 0.05

Arecent Environment Agency (Japan) report(1) claims that, to use coal, the combustion gas should be cleaned to a level equal to that of the gas from low-sulfur oil. Many simultaneous SOx and NOx removal processes have been studied for several years. Some of the processes have been applied commercially to relatively small oil-fired industrial boilers (10-40 MW equivalent); they have not yet been applied to larger gas sources because of problems with the processes. On the other hand, selective catalytic reduction (SCR) of NOx' using ammonia and a catalyst at 300-400°C to convert NOx to N Zand H20, has beendeveloped and applied to more than 130 gas sources, including coal-fired utility boilers. Table 2 shows major coal-fired utility boilers in operation and the SOx and NOx concentrations in their flue gases. This paper mainly describes FGD and combined SCR/FGD for coal-fired boilers; it briefly describes simultaneous SOx and NOx removal processes.
Z



# IPHAB004230TABLE 2. EXAMPLES OF NOx AND SOx EMISSIONS FROM COAL-FIRED UTILITY BOILERS
NOx, ppm SOx, ppm Power New (N) or Capacity, Boiler SCR FGD FGD Reheater company Station retrofit (R) MW out out in out out EPDCa Isogob R 265 200c 450 20 30 EPDC Takasago R 250 350 1500 100 140 EPDC Takasago R 250 350 1500 100 140 EPDC Takehara R 250 400 80 1700 100 140 EPDC Matsushimab N 500 300d 1000 60 100 Chugoku Shimonoseki R 175 400 190e 750 45 80 Electric Hokkaido Tomato-Atsumaf N 350 200g 30 230 10 20 Electric
aElectric Power Development Company. bSubjecting 75% of the gas to FGD. CWithDF-CN burner, two-stage combustion (TSC), and domestic low nitrogen coal

(1% or less). dUsing imported coal with SGR burner, TSC, and flue gas recirculation (FGR). eCan be lowered to 80 ppm when needed. fSubjecting 25% of the gas to SCR and 507. of the gas to FGD. gUsing domestic coal with dual-register burner, TSC, and FGR.
2. FGD UNITS FOR COAL-FIRED BOILERS 2.1 Types of Lime/Limestone FGD Processes All FGD units for coal-fired boilers in Japan use lime/limestone scrubbing, which may be classified in four types as shown in Figure 1 and Table 3. Type I is the throwaway sludge process, typical in the U.S.A. There is only one Type I unit: it is at Omuta and was constructed by Mitsui Miike Machinery Co. Other units use limestone and oxidize calcium sulfite to gypsum. To completely oxidize calcium sulfite to gypsum, it is usually necessary to lower the pH of the sulfite slurry to about 4. With a catalyst, complete oxidation is attained at a pH of about 5. Type II units lower the pH to about 5 using three scrubbers and a catalyst for oxidation. There are three Type II units: one owned byMitsui Aluminum (Omuta unit No.2) and two by EPDC at Takasago.

3



# IPHAB004231Type (I)**-~** CG 

# - --, 

### i

v Pond 

# t ' 

# I//'**7/~'/ 17/(7~/<////d** 

(II) ----r FG I I I I 

## ,

s 

## r---, ,............'-,.

--

### -**--~**

# ,

...**~------** Gypsum**-~** CG (III) CaC03 

# LtJ--lI**~.1** I p,'

## f-----------~~:5fJ

# )

-- --4' Air
- - --_1 Gypsum

CaC03

- ----' Air H?O

- ,-- --,. CG

# ',-------L~ ---I t 

# ---[fJ

- -

# -.L
- .-,ww Gypsum (IV)

FG: Flue Gas CG: Cleaned gas 

## s: Scrubber ps: Prescrubber OX: Oxidizer C: Centrifuge**w~:** Wastewater

--- Gas**----~Liquor -----~)Slurry**  or Solids Figure 1 Types of Commercial Wet Lime/limestone FGD Process for Coalfired Boilers in Japan

4



# IPHAB004232TABLE 3. FGD AND SCR UNITS FOR COAL-FIllED BOILERS Boller FGD SCR owner Plant 51te No. HW N!Ra Constructor Complet10n Type Constructor Co.ple.tion
Hitsu1 AlumJnum Omura 156 R MHHCb 1972 175 N IlMHC 1975 II EPDC Takasago 250 R MHHC 1975 II 250 R MHHC 1976 II 1sogo 265 R Itile 1976 III 265 R IHI 1976 III Takehara 250 R BHKd 1977 III BHK. KHI 1980 700 N IHI 1983 IV BHK 1983 Matsush1ma 500e N IHI 1981 IV 2 500e N BHK 1981 IV Chugoku MIllf Electric ShillOno.eki 175 R 1979 IV !illI 1980 5hln-Ube 75 R MIll 1982 IV /illI 1982 75 R /illI 1982 IV !'!HI 1982 156 R MIll 1982 IV /illI 1982 Hizushima 125 R BHK 1983 IV IlHK 1983 2 156 R BIlK 1983 IV BKK 1983 P.akkalca Electric: Tom.ato-AtsI.JDla 350g N BHK 1980 IV BHK 1980 600 N MIll 1984 IV kYUSnu neeteie Omura 156 R :1111 1982 IV !'lIII 1982 Minato 156 R If'iMC 1983 III' :1111 1983 laban**.Joi~t ~ak.oso**  8 600 N MIll 1983 IV HIlI 1983 bOG N /illI 1983 IV IHI 1983 TonoKu El'.!ctrlc Sendai 175 R BHK 1983 IV BHK 1983
j75 R BHK 1983 IV BHK Tokyo necteic YOk.OBuk.a 265 R /illI 1984 IV IlHI 1984 265 R l1HI 1984 IV HlI1 1984 5hikoku Electeic Saijo 175 R KHlh 1983 IV' 250 R KHI 1984 IV' aNe"" or retrafit. b!1itsui 'Ulke !1achinery Company. CIsh1kawajJma-Har1ma Heavy Industries. dBabeock-Hitachi K.K. eSubjecting 75:: of the gas to FGD. flUtsublshi Heavv Industries gSubjectlng 50% of the gas to FGD and 25% of the gas to SCR. hKawasakl Heavy Industrles.



# IPHAB004233Type III units have two-stage scrubbers and lower the pH of slurry at about 5 to about 4 by adding a small amount of sulfuric acid. Type III units require less investment cost than Type II units and may be preferred where sulfuric acid is available at a reasonable cost. There are three Type III units, all owned by EPDC: two at Isogo were constructed by Ishikawajima-Harima Heavy Industries (IHI) and one at Takehara was constructed by Babcock-Hitachi (BHK). Type IV units have a prescrubber with a separate liquor loop and use sulfuric acid for pH control. The prescrubber: (1) removes fly ash in the gas to reduce erosion of the scrubber system and to increase the purity of the gypsum; (2) removes chloride and fluoride from the gas to protect the scrubber system from corrosion (the fluoride removal may also increase both 502 removal efficiency and limestone utilization, possibly because fluoride reacts with limestone to form a coat of insoluble calcium fluoride on the surface of the calcium carbonate particles); and (3) cools the gas to eliminate scaling in the scrubber. Type IV units, developed by !1itsubishi Heavy Industries (!'!HI) since the 19605, have been applied to more than 30 FGD units by MHI, mainly for oil-fired boilers; it was applied to a coal-fired boiler of Chugoku Electric at 5himonoseki in 1979. All of toe limestone scrubbing units constructed since 1979 are Type IV, including those to be constructed ov IHI and BHK (Table 3). The Type IV unit prescrubber treats a hot flue gas with an acidic liquor with a pH of about 1, containing considerable amounts of chloride, fluoride, and fly ash. Therefore, the prescrubber requires highly corrosion- and erosion-resistant materials; for example, silicon carbide is often used for the spray nozzles. However, the prescrubber substantially reduces troubles in the scrubber system. All units with a prescrubber--the units at Shimonoseki, Tomato-Atsuma, and Matsushima--have been operated with 100% reliability since their startup (Table 4). The two scrubber systems for two 500 MW boilers at Matsushima are operated by only two persons per shift (one person each).

TABLE 4.**OPERATI~G** HOURS OF BOILERAND FGD (OCTOBER 1980

- SEPTEMBER 1981)
New (N) Hours FGD performance, % or Boiler FGD FGD called Oper- Reliretr0- Operation Operation to operate ability ability fit (R) (A) (B) (C) (B/A) (BiC) Shimonoseki R 7918a 7825 7825 98.8 100.0 Tomato-Atsuma 827Sb 8263 8263 99.9 100.0 Matsushima N 3968c 3968 3968 100.0 100.0 (Boiler No. 1)
aBoiler underwent annual ;naintenance in March and April 1981. bBoiler started operation in October 1980. cJanuary to June 1981. Boiler started operation**i~** January 1981.

6



# IPHAB004234The two units to be constructed by Kawasaki Heavy Industries (KHI) for Shikoku Electric (Table 3) will use the magnesiumgypsum process(3) with a prescrubberwith a separate liquor loop (Type IV'). Chiyodamay construct two FGD units for coal-fired utility boilers by thejet bubbling limestonegypsum process(3) using also a prescrubberwith a separate liquor loop. The only unit under constructionby the limestone-gypsumprocess without a prescrubber is that byMMMC for theMinato Stationof Kyushu Electric (Table 3). Asingle spray tower will be used for 90% 502 removal using a catalyst and also sulfuric acid for pH control (Type III'). Most of the U.S. systems have no prescrubber but have a stand-by scrubber which is not installed in Japan. Moreover, the S02 removal efficiency by limestone scrubbing seems lower than that with the.Type IV system in Japan by which about 95% removal is attained without any additive such as adipic acid used in the U.S.A. The prescrubbermay not be preferred for throwaway sludge systems that can be operated without scaling in the unsaturated mode. For the gypsum by-producing process, the prescrubbermay be preferred, because the overall cost of power generation (including FGD) may be lowered by the high reliability of the FGD system. 2.2 Scrubber Types and Operating Parameters Table 5 shows the capacities, types of scrubbers, and operating parameters of FGD units for utility boilers. The two EPDC units atMatsushima currently treat nearly 80% of the flue gas from the 500 MW boilers, while Hokkaido Electric's unit at Tomato-Atsuma treats 50% of the flue gas from a 350MWboiler. Otherunits treat 100% of the flue gas from the boilers they serve. EPDC's five FGD units at Isogo No.1 and No.2, Takasago No.1 and No.2, and Takehara were constructed between 1975 and 1977 and use venturi scrubbers or combined venturi and perforated plate scrubbers whichgive a high dust removal efficiency but a large pressure drop (325-615 mmH20 across two scrubbers), resulting in a high power consumption (2.2-2.6% of the power generated by the boiler). The relatively lowconsumption at Isogo (2.2%) is due to the lowinlet S02 concentration of450 ppm. Chugoku Electric's FGD unit at Shimonoseki, constructed in 1979 byMEl using a combined spray tower (semi-venturi) prescrubber and plastic-grid packed tower, gives a lower pressure drop and consumes less power (Z.1%).



### 7



# IPHAB004235IJ 

### TABLE 5. OPERATlNG PARAMETERS OF FGO UNITS FOR COAL-FIRED UTILITY BOILERS (LIMESTONE-GYPSUMPROCESS) Owner 

### EPOe EPDC EPDC EPDC Chugoku Hokkaido Station Isogo Takasago Takehara Matsushima Shimonoseki Tomato-Atsuma
Boiler No. 1 1 1 1 

### 2 1 1 Capacity, MW 256 250 250 500x3/4 500x3/4 175 350xl/2 Gas treated, 1,000 Nm3/hr 821 792 793 1,300 1,300 610 610 FGD constructor Hila 

### MMb BIIK

### c IHI BilK 

### MHId BILK 

### FGD start-up 1976 1975 1977 1981 1981 1979 1980 Inlet S02' ppm 450 1,500 1,730 1,000 1,000 730 230 Inlet dust, mg/Nm3 1,500 100 lOO 300 300 830 25 1st scrubber (prescrubber) Venturi Venturi Venturi Spray Spray Spray Venturi

L/G, ltter/Nm3 7 6 2.5 3 3 3 

### 2.2 2nd scrubber (scrubber) Venturi Venturi ppe Spray Spray Packed ppe

L/G, 

### l1ter/Nm3 7 6 7 15 15 14 5 Outlet S02, ppm 20 100 100 60 60 45 10 

### Outlet dust, mg/Nm) 50 30 50 30 30 50 5 SOx removal efficiency, % 

### 95.5f 

### 93.3f 94.2f 94.0g 94.0g 93.8g 95.7g Dust removal efficiency, % 

### 96.6 70.0 87.5 90.0 90.0 94.0 80.0 Pressure drop, mm "20 

### 36011 

### 325h 

### 615h 

### 145i 133i 240h 

### 450j Wastewater, t/hr 10 7.5 12 15 15 2.2 Power requirement, %k 2.2 2.6 

### 2.6 2.2 2.1 1.7 Gas reheating facility OFI 

### or! orI Gr.II'" 

### GC;IIIR 

### GGlim GGnm

- --'--. 

## - '--- 

### - - 

## ---- --

"'U 

### I 

# » OJ 

# o o I\J 

### W 

### 0'> alshikawaJlma-liarim8 Heavy Industries. bMltsui Milke Machinery Company. cBabcock-ll1tachi K.K. 

### dMitsubishi Heavy Industrles. eperforated plate. f

### l

-3%

### lower after reheating by oil-firing. gAbout 90% after gas reheating by gas-gas heater. hBy scrubbers and mist eliminators. iBy scrubbers. jBy scrubbers, mist eliminators, and gas-gas heater. kpercent of power generated. lOil firing. mGas-gas heater.Hokkaido Electric's Tomato-Atsuma unit, constructed by Babcock Hitachi (BHK) in 1980, uses an improved scrubber with lower pressure drop and smaller power consumption than the Takehara unit constructed by BRK in 1977 (power consumption is 1.7% vs. 2.6%). The lowpower consumption is due to the improved design and the lowinlet 502 concentration of around 230 ppm. The two EPDC units atMatsushima, completed in 1981 by IHI and BRK for 500 MW boilers, use spray towers with a low pressure drop of 133- 145 mm H20. The newEPDC unit for, the Takehara No. 3 boiler, being constructed by IHI, also uses a spray tower. The power consumption of Matsushima No.2 is 2.2%. MHI used a spray tower absorber for the first lime-gypsum process unit (20 MW equivalent) constructed in 1964 but has used a plastic-grid packed tower since 1972 as the scaling problem was solved, because the packed tower can be more efficient than the spray tower. The spray tower may have a highefficiency for a large scrubber with a height of over 30 m, such as constructed recently atMatsushima and Takehara (No.3). The operation of those large units and three 600 MWunits to be constructedbyMHI for Joban Joint Power and Hokkaido Electric (Table 3) withplastic-gridpacked tower will show a good comparison of the scrubbers. All of those units use finely ground limestone so that over 95% passes a 325 mesh screen at a stoichiometry of 1.00-1.05 to remove 94-97% of 502. Gas reheating adds a small amount of 502 so that the overall S02 removal efficiency is 90-95%. The reheating has been by oil-firing at Isogo, Takasago, and Takehara (No.1) and by gas-gas heater (Ljungstrom heat exchanger) at the newunits. The dust removal efficiency of the scrubber systems ranges from 70 to 96%. EPDC's FGD units at Isogo are designed for over 95% dust removal efficiency because the boilers use low-sulfur coal for which the conventional cold-side electrostatic precipitator (ESP) is not highly efficient. On the other hand, the EPDCboilers atXatsushima and that ofHokkaido Electric at Tomato-Atsuma use hot-side ESPs which are efficient for low-sulfur coal; therefore, the 80-90% dust removal efficiency of the FGD unit is sufficient.
3. SELECTIVE CATALYTIC REDUCTIONAND ITS COMBINATIONWITH FGD 3.1 Selective Catalytic Reduction (SCR) Ammonia selectively reacts withNOx in gases at ISO-450°C in the presence of a catalyst and oxygen. SCR can be conveniently applied to boiler economizer outlet gas at 300-400°C.



### 9



# IPHAB0042374NO

### +4NH3 

### +0z

## =4NZ

### +6HZO Early in its development, SCR had serious problems. The major ones were: (1) catalyst poisoning by SOx in the gas; (Z) plugging of the catalyst by dust; (3) deposit of ammoniumbisulfate on the catalyst at a low temperature (around 300°c or below) due to reduced boiler load; (4) ammoniumbisulfate deposit in an air preheater downstreamof the SCR r.eactor; (5) promotion of oxidation of S02 to 503 by the catalyst; and (6) erosion of the catalyst by fly ash from the coal. Solutions of those problems include: Problem (l)--using base metal catlysts based onTi02 instead ofAIZO) or FeZ03; Problem (2)--using parallel-flow catalysts or reactors such as honeycomb, plate, and tube catalysts or parallel passage reactors (soot-blowmay be applied if needed); Problem ()--maintaining the gas temperature above about 300°C by using economizer by-pass when needed; Problem (4)--keeping NH3 leakage (ammonia in the SCR reactor outlet) at a low (e.g., below 5 ppm) level; Problem (5)--developing low-oxidation catalysts (depressing oxidation also helps solve-Problems (3) and (4»; and Problem (6)--using moderate gas velocity, hard catalyst, and a device (e.g., a dummy spacer) for erosion prevention. SCR is simple, and an SCRunit is usually operated automatically (without an operator). Figure 2 shows the relationship of inlet NH)/NOx mole ratio to NOx removal efficiency and NH3 leakage. Usually NH3 leakage is kept below 5 ppmto eliminate an ammoniumbisulfate problem. For 80% NOx removal for flue fas fromcoal, a ratio of 0.85 and space velocity of nearly 3,000 hr- may be used; for 90% removal, a ratio of 0.95 and space velocity of about 2,000 hr-1may be used. Flue gas from oil combustion can be treated with 30-50% less catalyst because a much more active catalyst (porous and soft) can be used. Figure 3 shows the effect of boiler load on SCRperformance. At a reduced load-, gas temperature is lowered but NOx removal efficiency is raised because of the longer reaction time due to the reduced gas flow rate. Agas temperature above about 330°C is desirable because ammonium bisulfate tends to deposit on the catalyst at lower temperatures. 3.2 Combination of SCR and FGD Figure 4 shows combined SCR-FGD systems for coal-fired boilers. The SeR reactor of the Shimonoseki unit (A) treats flue gas with a full dust load of about 

### ZO g/Nm3 (high-dust system). Those of the Tomato-Atsuma and Takehara units (B and C) treat the gases leaving a hot ESP containing less than 0.1 g/Nm3 ofdust (low-dust system). Both systems have been operated with neither erosion nor plugging of the catalyst by fly ash.

10



# IPHAB004238NOx 

### Removal 

# [ -

# J0**5~g;** NH3 leakage

_ _ 80 90



### Figure 3 

### Boiler Load and Performance 

### of SCR 100

# ::[~J [ 502 Oxidation 

### to 503

# J1B

# :::r~~O 200[ I ! I 

# ,J
25 50 75 100 

### Boiler load(%) 100

....... N '-" 90



### ..... Ql :> 0 

### s 80 Q) CG X 0 70 z ·60

NH3/NOx

### mole ratio ....... S 0. 0. 20 Q) 00 Ql ry\)\J Ql 10 Q) u 

### ..... l-' 0 C") 0**S~··** '-" :::c z 0.6 0.7 0.8 0.9 

### 1.0 1.1
Figure 2 

### SCR for Coal-fired Boiler Flue Gas (350°C; 

### Honeycomb Catalyst)

11



# IPHAB004239A: Shimonoseki Plant, Chngoku Electt!:c

Boiler

Bypass AP

Ammonia tank FGD Stack

Baile Hot Eco ESP

Boiler Eco

Eco: Economizer APR: Air PreheaterB: Tomato-Atsuma Plant, Hokkaido Electric

Stack

C: TakeharaPlant, EPDC

Wastewater treatment (NH3 removal)

MC: Multi-cyclone ESP: Electrostatic Precipitator GGH: Gas-gas Heat Exchanger Figure 4 Combined SCR-FGD System in Operation for Coal-fired Boilers

12



# IPHAB004240The properties of fly ash, however, may be considerably different with the type of coal and the condition of combustion. The effects of various fly ashes on SCR should be further studied. Hot ESPs are more costly than cold ESPs, but are more efficient for collection of dust from low-sulfur coal. Most of the SCRunits under construction use the high-dust system because the deposit of ammonium bisulfate in the air preheater is eliminated by the cleaning effect of the fly ash, and because the dust can be sufficiently removed by the combination of the coldE5P and wet FGD. SCR units usually give less than 5 ppmNH3 leakage which is caught by wet FGD units. With Type I, II, or III FGDunits, ammonia enters the scrubber system. The ammoniamay not affect scrubber operation but may increase S02 removal efftciency.(2) With theType IV unit, ammonia is caught by the prescrubber. In any case, ammonia at the scrubber outlet is virtually nonexistent; there is not the plume problem that is usually experienced at ammonia scrubbing FGD units. With the high-dust system, a small amount of ammonia, 0.01-0.02% for 3- 7 ppm ammonia leakage, may be contained in the fly ash caught by the cold ESP. The fly ashat Shimonoseki, where ammonia leakage is kept below 1 ppm, contains very little ammonia, and therefore gives no trouble whenused as an additive to cement or for landfill. 3.3 Wastewater and Its Treatment The pH and composition of wastewater from commercial FGD units for coalfired boilers in Japan are shown inTable 6. Thewastewater (from the prescrubber and scrubber) is treated with lime to precipitate heavy metals and fluoride which are filtered off. The filtrate is usually treated by ion exchange resin to remove dithionate 52°62

- which causes chemical oxygendemand (COD). Usually the treated water contains below 10-15 mg/liter each of suspended solids and COD, below 15 ppm fluoride, and below 1 ppm oily material at pH 6.5-8.5. It thus satisfies existing regulations. As shown in Table 6, the wastewater contains a considerable amount of nitrogen compounds which may be derived mainly from NOx in the flue gas. Flue gas from a coal-fired boiler usually contains 200-500 ppmNOx' If 1-27. of the NOx is absorbed by the scrubbing liquor, the nitrogen content of the wastewater reaches 100-600 ppm as shown inTable 6, assuming that a 250 MWFGD unit purges 10 t/hrwastewater. So far, wastewaterhas not been treated to remove nitrogen compounds, because the total amount of nitrogen compounds is not much.

13



# IPHAB004241

### TABLE 6. pHAND COMPOSITION (mg/liter) OF WASTEWATERFRmtFGD UNITS 

### FOR COAL-FIRED BOILERS ("BEFORE BEINGTREATED)(l) 

### pH 5 

### Chemical oxygendemand 30 100 Suspended solids 2.,000 

### J,OOO Fluoride 500 600 Iron 100 500 Manganese 10 30 Magnesium 200 1,000 Aluminum 100 1,400 Chloride 3,000 8,000 Total Nitrogena 100 600
aDoes not include ammoniaderived from SCRofNOx' When SCRis applied upstreamofFGD, ammonia is caught by the scrubber. Ammonia at a concentration of 5 ppmin flue gas froma 250 coal-fired boiler amounts to about 3 kg/hr. If the FGD unit for the boilerpurges 10 t/hr ofwastewater, the scrubber (or prescrubber) liquor as well as the wastewatermay contain about 300mg/liter of ammonia. Adding lime causes much of the ammonia to bevolatilized. If necessary, evenmore ammoniacan be removed from the water. EPDC's demonstration plant atTakehara (combined SCRand Type II FGD) has aunit to remove ammonia fromwastewater by a conventional activated sludge process; ammonia is reduced to 10 mg/liter. The Takehara plant faces the Seto Inland Seawhich occasionallyhas a "red tide" problem. Therefore, reducing ammonia to a low level is desirable. InJapan, a small amount ofammonia has beenadded to the flue gas from oil-fired utility boilers to neutralize sulfuric acid mists and to protect ESPs from corrosion. Thus ESP outlet gas usually contains about 5 ppmNH3 which is caughtby wet-process FGD and contained in the wastewater. At Chubu Electri's Owase-Mita plant. an ammonia stripping unit has been operated to reduce ammoniain FGD wastewater.(3) When SCRis combined with a Type I FGD system, ammoniamay be caught in the calcium sulfite slurry and may accumulate in the sludge pond when the supernatant is recycled to the scrubber. Itmay be necessary to minimize the ammoniaemission from the SCRreactor.

14



# IPHAB004242It is likely that the nitrogen compounds shown in Table 6 will be reduced considerablyby applying SCR and reducing NOx in flue gas. It may be possible that the total nitrogen compounds (including ammonia) may be lowered by applying SCR and keeping ammonia leakage at a very low level; e.g., 1 ppm orbelowat the Shimonoseki plant.
4. ECONOMICS OF FGDAND SCR Investment costs of limestone-gypsumprocess FGD units for coal-fired boilers are listed in Table 7. The cost of the first units completed in 1975-1976, was 18,600 yen/kW.* The investment cost has since continued to increase mainly because of inflation. Chugoku Electric's Shimonoseki plant is fairly costly because it includes a Ljungstrom gasgas heater to reheat the gas to 110-120°C. The gas-gas heater accounts for about 10% of the investment cost but, since it does not require fuel oil for gas heating, gives an overall economic advantage. TABLE 7. INVESTMENT COST OF FGD UNITS FOR COAL-FIRED BOILERS (LIMESTONE-GYPSUMPROCESS, RETROFIT)
Plant Capacity, Investment cost Year Power company site MW 109 yen yen/kWhr completed EPDC Takasago 250 x 2 9.3 18,600 1975-1976 EPDC Isogo 265 x 2 11.0 20,750 1976 EPDC Takehara 250 

### 7.2 28,800 1977 Chugoku Electric Shimonoseki 175 

### 7.0a 40,OOOa 1979
aIncludes Ljungstrom gas-gas heat exchanger. The estimated annualized FGD cost using a gas-gas heater for a 500

### MW coal-fired boiler is about 1.9 yen/kWhr including 7 years depreciation. The fixed cost is 70% of the annualized cost. Investment costs of SCR units for coal-fired boilers are shown in Table 8. As shown in Table 9, an SCRunit for a large new, coal-fired boiler costs 6,700--8,400 yen/kW for 80% NOx removal and about 30% more for 90% removal. An SCR unit for an existing boilermay cost 10-40% more. The annualized SCRcost is 0.6-0.8 yen/kWhr for 80% removal and nearly 30% more for 90% removal. Actually it is difficult to remove 90% ofNO

### xwith NH3 leakage below5 ppmfor a large boiler because bothgas flow rate and NO

### x concentration are not uniform in a large duct. Catalyst cost is over 60% ofboth investment and annualized costs.
*1J!1

- $0.0043 15



# IPHAB004243

### TABLE 8. INVESTMENTCOSTOF SCRUNITS FORCOAL
Size New (N) or Cost Station (MW) 

### Retrofit (R) 

### Constructor Start-up (yen/kW) Shimonoseki 175 R 

### MIll 1980 9,700a Tomato-Atsuma 350x1/4 N 

### BRK 1980 10,eOOb Takehara 250x1l2 R 

### BRK 1981 7,OOOb Takehara 250x1/2 R 

### KHI 1981 S,OOOb aIncluding boilermodificationfor**econom~zer** 

### by-pass. bApproximation.

TABLE 9. 

### E:STIMATEl> SCRCOSTFORNEW700 HW

### UTILITY BOILERS (Flue gas 2,300,000 Nm3/hr. Annual powergeneration

4,292,400MWhr. 70% utilization. NR3 

### leakage less than 5ppm. Honeycomb catalyst,)

Fuel Hi2h Scoal Hi2h Scoal Low S 

### coal Inlet SOx (ppm) 2500 2500 600 InletNOx (ppm) 600 300 300
NOx removal (%) 

### 80 90 80 90 80 90 Space velocity (103 

### hr-1) 

### 2.2 1.6 2.7 -Z.O 

### 3.0 2.2**Invest~ent** 

### costa 103 

### yen/kW 8.44 10.76 7.26 9.10 6.69 8.51 U.S. S/kWb 36.7 46.8 31.6 39.6 29.1 37.0
Annualized costC 

### yen/kWhr 0.81 1.04 0.65 0.82 0.59 0.76 mill/kWhr 3.5 4.5 2.8 3.6 2.6 3.3 S/lb of

# NOxremovedd 0.48 0.56 0.79 

### 0.88 0.71 0.82 alncluding initial charge of catalyst, civil engineering, and test operation.

Catalyst: 3.5 x 106 

### yen/m3, 2years life. bSl

- 

### Y230. clncluding 10% interest and 7 years depreciation. dNOx calculatedas NOZ (1 lb

## =0.45 kg).

16



## IPHAB004244Arough estimated cost for power generation is shown in Table 10. About 20% of the total investment for a coal-fired power station is for flue gas cleaning byFGD, SCR, and ESP. The investment cost of FGD is about 70% of the cost for flue gas cleaning. The estimated annualized cost of power generation with coal is 17 yen/kWhr, including nearly 3 yen for the flue gas cleaning. The cost is less than that with low-sulfur oil without flue gas cleaning. TABLE 10. ESTIMATED POWERGENERATION COST (1981)

Investment cost, yen/kW Coal-fired power station (excluding flue gas cleaning) Flue gas desulfurization (90% efficiency) Selective catalytic reduction (80% efficiency) Electrostatic precipitator (99.5% efficiency) Total Annualized cost, yen/kWhr Flue gas desulfurization Selective catalytic reduction Electrostatic precipitator Total power cost with coal including flue gas cleaning Power cost with low-sulfur oil without flue gas cleaning



## s. SIMULTANEOUS SOx and NOx REMOVAL 5.1 Outline 200,000 32,000

7,000 4,000 243,000
1.9 0.6 0.1 17.0 20.0

Major simultaneous SOx and NOx removal processes are shown in Table 11. The copper oxide process has been applied to an oil-fired industrial boiler 

### (40MWequivalent).(4) Wet processes using Cl02 or 03 as the oxidizing agent and NaOHor CaC03 as the absorbent have been used for several gas sources (10-20 

### HW equivalent).(4) There is no plan for further application of those processes. The application of activated carbon and electronbeamprocesses to coal-fired boilers has been studied. Wet processes using alkaline solutions containing EDTA and FeS04 to absorb 502 and NO have been tested but are not commercialized yet. Pilot plant tests of fluidized-bed combustion (FaC) of coal (S 

### HW equivalent) are inprogress at EPDC's Wakamatsu Station. Preliminary tests withdomestic low-sulfur low-nitrogen coal indicated that

### NOx was lowered to about 60 ppm.(S) 

### FBC, however, may not be used widely in Japan because of the difficulty in disposing of ash containing calcium compounds. Although tests are planned to use a synthetic absorbent whichmay 

### be separated from fly ash for reuse, the method may not be practical. '
17



# IPHAB004245

### TABLE 11. MAJOR SIMULTANEOUS SOxAND NOx REMOVAL PROCESSES
Type Dry process Absorbent, reagent By-product Copper oxide. NH3 N2 and S Activated carbon, NH3 N2 and S Electronbeam, NH3 (N14)2S04 and

### NH4N 03
Wet process 

### CI02, NaOH D3' CaCD] K2S04. EDTA. FeS04 Na2SD2. NaCI. and NaN03 CaS04.2H2D. and N2 or NH3 N2 and S

5.2 Activated CarbonProcess(6) Electric PowerDevelopment Co. (EPDC) and Sumitomo Heavy Industries (SHI) have conductedjoint tests of the activated carbon process with a target ofremoving 95% of SOx and 40% of NOx in flue gas from a 

### coalfired boiler. Apilot plant witha capacityof treating 10,000 Nm

### 3/hr of flue gas from a coal-fired boiler at the EPDC's Takehara Stationwas operated from 1978 through 1980. The gas leaving an ESP at 120-150°C was added with0.7 mol NH3 to 1mol SOx and was passed through amoving bed of activated carbon. Over 90% of SOx was adsorbed by the carbon witha space velocity of 500-900 hr-1, 

### while 20-40% of NOx was removed (Figure 5). The carbonwas heated in a separatemoving bed at 35DoC by a hot inert gas to release concentrated S02' The carbon consumption was 0.5-1% perday. The concentrated 502 was mixed with a small amount of air and introduced into a shaft furnace charged with anthracite coal or coke. By partial combustion in the furnace. gas temperature reached 900°C. About 90% of the 502 was reacted: about 45% to form elemental sulfur, 30% to form H2S, and 10% to form COS. The gas, cooled to separate elemental sulfur by condensation. was led to three Claus furnaces in series to which a portion of the concentrated 502 

### was also added to react with H2S to form elemental sulfur. Thus 90% of the 502 

### recovered by the carbonwas converted to elemental sulfur. The tail gas from the Claus furnace was incineratedand returned to the FGD system. Ammonia played two roles: it reduced NOx; 

### and it reduced carbon consumption. The processmay suit a flue gas with relatively low SOx content because the consumption of bothammonia and carbon decreases with SOx content. 

### SRI claims that the process may competewith the wet limestone process for coal containing 1% or less sulfur. Ademonstration plant with a capacity of treating 300.DOO Nm3

### /hr of flue gas from a coal-fired bOilerwill be constructed at EPDC's Matsushima Station**i~** 

### 1984. 18



# IPHAB0042465.3 Electron BeamProcess Ebara Corporation and JapanAtomic EnergyResearch Institute have jointly developed a unique process to remove SOx and NOx simultaneously by electron beamradiation in the presence ofammonia. By the radiation, SOx and NOx form fine crystals of ammonium sulfate and nitrate, which are caught by an ESP orbaghouse (fabric filter). The by-product is useful for fertilizer. Apilot plant with a capacity of treating 3,000- 10,000 Nm3/hr of flue gas from an iron-ore sintering machine was operated in 1978 (Figure 6).(7) The process has been licensed to AVeO, U.S.A., which has tested the effects of coal fly ash on the process; the ashhad no adverse effect on the process.(8) Over 70% removal of fly ashmay be needed prior to the radiation to make the product useful for fertilizer. AVCO estimates that the investment cost is less than that for conventional wet lime scrubbing when a large size electronbeamgun is used. Such a gunmay be commercialized in the near future. Ebara estimates that the power consumption for treating flue gas from a coal-fired utility boiler is about 3% of the powergenerated by the boiler. The figure is a little larger than the consumptionby the combinationof SCR (0.1-0.2i.) and FGD (2.0-2.5%). Although there are many simultaneous SOx/NOx removal processes, the electron beamprocessmay be the only process whichmay be useful in large-scale to recover SOx' NOX, and NH3 as useful by-products.

6. SUMMARY Most coal-fired boilers inJapan are to use a flue gas cleaning system consistingof selective catalytic reduction (SCR) using a honeycomb or plate catalyst, electrostatic precipitators, and FGD by the limestonegypsum process using a prescrubberwith a separate liquor loop. The power generating cost by coal, including gas cleaning and wastewater treatment, is less than that by low-sulfur oil without gas cleaning. The fuel for several oil-fired boilers is to be changed to coal, using gas cleaning. However, the limestone-gypsumprocess is fairly costly. SCRis much less costly than FGD but is more costly than combustion modification (CM), and shouldbe used with CMwhen CM alone is not sufficient to meet existing regulations. Simultaneous SOx/NOxremoval processes and fluidized-bed combustion have not yet been proved to be better alternatives to combined cleaning. Furtherdevelopment of SOx and NOx removal processes is desired.

19



# IPHAB004247

### 100

"'"'

# ~2 N



## ....

.....

# ~: til 

### 90 :> 0 E OJ


## ... 

## 580 r.rJ


### ;;40

# ~: .....

:> 

### g30

# ~3 iii



### ... 20 Z 

### 130 140 150 160 Temperature(OC)
\ 

### Relative Inlet(ppm)

gas volume 

### SOx NOx 1 I 

### 100 910 230 I 2

# I 80 910 170 3 120 910 200 Figure 5 Effects ofTemperature and Gas FlowRate on removal Efficiencies 100

il-l! 

### :::80 til :> o E OJ 

### ..: 60

40 200

.-.. 

### 150 

### e Po Po



### ..... 100 M 

### Z 50 ..:.:: <lI 0 Q( 

## a l.0 2.0 3.0 Dose(Mrad) Gas Flow: 3,000 Nm3/hr Temperature 90°C Inlet Gas Composition



### SOZ ZOO ppm, NOx 200 

### ppm**~H3** 

### 600 

### ppm Figure 6 

### Test Results ofElectron Beam Process

20



# IPHAB004248LITERATOllE CITED 

### 1. The

### Panel on

### theEnviroOlental r..pactB oftheConversionto Coal. Envlroaaent Agenc:y. ADAnal.ysis of the Enviroaaental Impacts 

### of the 

### Expanded Use

### ofeoalaDd Hi

### t1g8t10nKe_urea-fortheProperIaplementationofEnviroomental ImpactAssessment (1981) (inJapanese). 2. 

### G. JODes, ll.. Glover. G. Behreos. aDdT. Shirley, Iapactof.HOx SelectiveCatalyticReductionProcesses onFlueGas Cleaning Systeas. EPA!IEll.L-RTP-1287 (inprint) (October 1981). 3. 

### J. Ando. S02

### Abatellent for StationarySources inJapan. EPA-600/7- 78-210 (NTIS 

### PB290198) (Hoveaber 1978). 4. 

### J. Ando. HOXAbatellentfor StationarySources inJapan. EPA-600/7- 79-205 (NTIS PB 80-113673) (August 1979). 5. S. 

### Ta

..nuld. H. 

### Kataya... and N. 

### Takaai. 20 ton/hPilot PlantTest 

### ofFluid1zedBedBoiler. In: Proceedings of the Third Coal 

### UtilizationTechnologySyaposiua. CoalMiningll.esearchCenter**(Septe~r** 

### 1981) (inJapanese). 6. SUII1tomo

### HeavyIndustries, Total FlueGas Treatmentbythe Dry 

### DesulfurizationProcess (1981). 7. K. 

### Itaw&Jalra. PilotPlantExperiment onthe !TeatllentofExhaustGas froma SinteringMachine by

### ElectronBeamIrradiation. Environmental Science 

### aDdTechnology, Vol. 14. Ho. 

### 3. 288-293 (March 1980). 8. V. 

### Shui aDd K. KaWlUllUra. Reaoval of SOx

### and NOx fr01ll

### FlueGases by 

### ElectronRadiation. 73rdAnnualMeetingofAPCA. 

### Montreal (July 1980).

21



# IPHAB004249