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Advanced AQCS Technology for Further Emission Control
-CONTENTS-
1. Ultra Low PM Emission Control Using Gas Cooler
2. Mercury Removal Using Special Catalyst
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Takanori Nakamoto (Babcock-Hitachi K.K.)27 Nov., 2013 @ VGB-TENPES EXPERT MEETING
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1. Ultra Low PM Emission Control Using Gas Cooler
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1.1 Typical Emission Trend in Japan (Coal-Fired)
・Severe Standards of SO2 Conc.・Severe Standards of Dust Conc.
:Improvement of the FGD System:Improvement of the Flue Gas System
→ Optimized Combination of the Flue gas System
SO2:100ppm
SO2:50ppm
SO2:25ppmDust: <20mg/m3NDust: <10mg/m3N
1980 1990 1995 2000 2005 2010 2015
Dus
t Con
c. (m
g/m
3N)
SO2
Con
c. (p
pm)
<5mg/m3N
EU Germany
SO2 (mg/m3N) 200(70 ppm)
100(35 ppm)
NOx (mg/m3N) 200(98 ppm)
80(39 ppm)
Dust (mg/m3N) 30 10
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Non-Leakage Type Rotary Regenerative Type
GGH
1.2 Conventional Flue Gas Treatment System
BoilerSCR
GGH
Stack
GGH
A/HESP
(PJFF)
WFGD
(Cooler) (Re-heater)
Fan Fan
Stack
GGH
GGH
GGH
WFGD
130 deg.C 90 deg.C 130 deg.C 90 deg.C
90 deg.C 90 deg.C50 deg.C 50 deg.C
Applicable GGH Type
WFGD
Low Temperature ESP System
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1.3 Critical Design Factor for GGH Cooler: D/S
SO3 Concentration (ppm)
DRY - WET Boundary Line
WET Condition
DRY Condition
Gas Temp. (deg.C)
Dust Conc. (mg/m3N)
SCR AH FGDESP GGH GGHIDF BUF Stack
130 90 50 90100
130100 2020
Boiler(Cooler) (Re-heater)
20,000
Operation range of Low Temp. ESP System
20 20 <10<10
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1.4 Trend of GGH Pressure Loss (Conventional)
Days (day)
0 30 60 90 120 150
EP Outlet Dust Conc. = ~ 20 mg/m3N
EP Outlet Dust Conc. = 100 mg/m3N
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1.5 Heat Recovery Tubes (Low Dust Operation)
Initial
After the operation
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1.6 Advanced Flue Gas Treatment System
Low-Low Temp. ESP System
Boiler SCR AH FGDESPGGH GGHIDF BUF Stack
Gas Temp. (deg.C)
Dust Conc. (mg/m3N) 20,00090 50 90
<10 <103090
Conventional System
(H/R) (R/H)130
20,000
Boiler SCR AH FGDESP GGH GGHIDF BUF Stack
Gas Temp. (deg.C)
Dust Conc. (mg/m3N)
90 50 9020 20100
130(H/R) (R/H)
13020,000 100
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1.7 The Features of Low-Low Temp. ESP System
Boiler SCR AH FGDESPGGH GGHIDF BUF Stack
Gas Temp. (deg.C)
Dust Conc. (mg/m3N) 20,00090 50 90
(H/R) (R/H)130
20,00090
30 <10 <10
1. Stable high dust removal performance in ESP (Low gas temperature in ESP)
2. No plugging and corrosion by high ash loading andSO3 condensation in heat recovery (cooler) side of GGH
3. Lower fan power consumption (Lower actual gas volume with low temp.)
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1.8 Stable High Dust Removal in DESP
Decrease of ESPInlet Gas Temp.
Decrease of DustElectric Resistant
Improve of ESP Performance
Conventional System
→H
igh
Low
←
Gas Temperature (deg.C)Dus
t Ele
ctric
Res
ista
nt (Ω
・cm
)
A Coal
B Coal
50 100 150 200
Low Low Temp. ESP System
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1.9 SO3 Behavior around GGH (Cooler)
GGH Heat Recovery Outlet Temp.
SO3
Con
cent
ratio
n(p
pm)
Laboratory DataPilot Data
(2) SO3 measurement data at Pilot Test
A/H GGHFGDDeNOxBoiler
Stack
GGH ESP
FAN
Temp.( C) 150 - 160 93 - 104
SO3 (ppm) 16 < 0.1 Pilot Test
SO3 (ppm) 50 < 0.1 Laboratory Test
Heat Recovery Re-heating
SO3(Vapor) SO3(humid)
Acid dew point
Removal of SO3 with DustThe fall of Temp.(By GGH)
Adsorption of SO3 into the dust Removal of SO3
・Reduction of corrosion condition
(1) The concept of SO3 Removal
ESP
Hea
t Rec
over
y Si
de O
utle
t
Adsorption&
Neutralization
SO3
Ash particle
GGH
o
o o o
0.1
1
10
100
C C C C50 100 150 200
・Prevention of the Blue Plume
o
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1.10 Dust Rich Circumstances keep Dust Dry
DRY - WET Boundary Line
WET Condition
DRY Condition
SO3 Concentration (ppm)
Operation range ofLow-Low Temp. ESP System
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1.11 Reheater Tubes after Operation
After 2 years operations(Cooer Side)
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
2000/3 2001/3 2002/3 2003/3 2004/3
Time
Pres
sure
Los
s of
GG
H(k
Pa)
Heat Recovery Side Reheating Side
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1.12 Supply List of GGH System (1/2)
No Customer Location Capacity (m3N/h)(Equiv. MW) Fuel Commercial
Operation Remarks
1 Tokyo Electric Power Co., Ltd Yokosuka #2 925,000(265) COM 6-1985
2 Chugoku Electric Power Co., Ltd Tamashima #3 1,460,000(500) OIL 5-1987
3 Taiwan Power Co., Ltd Hsinta #1 1,934,000(500) COAL 5-1990
4 Taiwan Power Co., Ltd Hsinta #2 1,934,000(500) COAL 5-1990
5 Taiwan Power Co., Ltd Linkou #1 1,160,430(300) COAL 4-1991
6 Taiwan Power Co., Ltd Linkou #2 1,160,430(300) COAL 4-1991
7 Soma Joint ThermalDevelopment Co., Ltd Shinchi #1 3,175,000
(1,000) COAL 6-1994
8 Kyushu Sekiyu Co., Ltd Ohita #1 439,700(149.4) R.O. 4-1999
9 Electric Power DevelopmentCo., Ltd Tachibanawan #2 3,280,000
(1,050) COAL 12-2000 LLTE
Note: “COM”; Coal Oil Mixture, “R.O.”: Residue Oil, “LLTP”; Low-Low Temp. ESP
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1.13 Supply List of GGH System (2/2)
No Customer Location Capacity (m3N/h)(Equiv. MW) Fuel Commercial
Operation Remarks
10 Chubu Electric Power Co., Ltd Hekinan #4 2,916,000(1,000) COAL 11-2001 LLTE
11 Chugoku Electric Power Co., Ltd Tamashima #2 1,000,000(350) OIL 7-2001
12 Chubu Electric Power Co., Ltd Hekinan #5 2,916,000(1,000) COAL 11-2002 LLTE
13 Idemitsu Sekiyu Co., Ltd Aichi #3 782,400(252) OIL 4-2004
14 Kansai Electric Power Co., Ltd Maizuru #1 2,620,000(900) COAL 8-2004 LLTE
15 Korea South-East Power Co., Ltd Yonghung #3 2,474,820
(870) COAL 6-2008 LLTE
16 Korea South-East Power Co., Ltd Yonghung #4 2,474,820
(870) COAL 3-2009 LLTE
17 Kansai Electric Power Co., Ltd Maizuru #2 2,465,000(900) COAL 8-2010 LLTE
18 Tokyo Electric Power Co., Ltd Hitachinaka #2 3,400,000(1,000) COAL 12-2013
(Scheduled) LLTE
Note: “COM”; Coal Oil Mixture, “R.O.”: Residue Oil, “LLTP”; Low-Low Temp. ESP
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1.14 Case Example - 1
Boiler Fuel: Coal
FGD Process: Wet Limestone-gypsum
Gas Flow Rate: 3,130,400 m3 N/h
(Eq. : 1,050 MW)
Inlet SO2 Conc.: 860 ppm
Flue Gas System Low-Low Temp. ESP
Gas Reheating: Non-leak Type GGH
Dust Emission < 10 mg/m3N
Operation December, 2000
MAJOR SPECIFCATION
Low-Low Temperature ESP Flue Gas Treatment System
ELECTRIC POWER DEVELOPMENT CO., / TACHIBANAWAN P.S. / NO. 2
GGH GGH
WFGDDESP
Stack Boiler
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1.15 Pilot Test Plant (1.5MWth) in BHK/Akitsu
Flue gastreatment facility
DESP
Combustionfacility
Control room
SCRWFGD
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1.16 Schematic Diagram of the Pilot Test Plant
Burner
SCRreactor
Dry-ESP Pump
WFGD
Coal
BUFIDF
HeatExchanger
DESP : Dry Electrostatic Precipitator
GGHDESP
WESP
GGH : Gas-Gas Heat exchangerSCR : Selective Catalytic Reduction
WFGD : Wet Flue Gas Desulfurization
Item ConditionCoal Feed Rate 110~130 kg/hGas Flow Rate 1100~1300 m3/h
WESP : Wet Electrostatic Precipitator
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1.17 Structure of Gas-Gas Heater
a Structure of Gas-Gas Heater
Exhaust Gas
Coolingmedium
覗き窓
Nozzle Compressor AirSeal Air
b Soot Blower
c Finned tube
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1.18 Condition of Finned tube
a SO3=43mg/Nm3
(12ppm)b SO3= 143mg/Nm3
(40ppm)c SO3= 321mg/Nm3
(90ppm)
・The amount of ash accumulated on the tubes increased with increasing SO3concentration in the flue gas.
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1.19 Effect of Soot Blower
20
SO3=143mg/m3N(40ppm)
(movie file)
Gas Temp.=130 degC
(movie file)
SO3=286mg/m3N(80ppm)
Gas Temp.=130 degC
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2. Mercury Removal Using Special SCR Catalyst (TRAC®)
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2.1 Process of Mercury Removal
SCR catalyst is a key component for mercury removalSCR catalyst is a key component for mercury removal
HgHg00 HgHg2+2+
SCR SCR Catalyst Catalyst
Hg
Hg
Emission Emission from Stackfrom Stack
Boiler Boiler SCRSCR ESPESP FGDFGD Stack Stack
Elemental Elemental HgHg
Oxidized Hg Oxidized Hg (HgCl(HgCl22))
Particulate HgParticulate Hg
Hg(Oxid)
Ash Particulate (S.A., Gas Temp.)
Spray Nozzle
Absorption(HgCl2,SO2)
SO3(Hg adsorption)
Emission from Stack
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2.2 Mercury Removal Key Technology
Technology Key Item Advantage Disadvantage/Challenge
Adsorption ActivatedCarbon
Injection (ACI)
- Commercialized- w/o SCR- High Hg removal
- High Operating Cost- Difficulty of ash disposal- Addition of ACI facility- Difficulty of Operation and Maintenance
- SO3 impact on Hg removal efficiency
Oxidation Halogen Injection
- Commercialized
- Simple system
- High Hg removal
- Relatively low cost
- Balance of plant impacts
- Ineffective on bituminous coal
SCRCatalyst
-Commercialized - Low operating cost- No additional facility- Easy to replace- High operation reliability
-Correspondence with Customer's
needs
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2.3 Concept of Special Catalyst TRAC®
Hg Oxidation Activity
SO2
to S
O3
Con
vers
ion
Low
High
Low High
ConventionalTechnology
TRAC®
(Mercury Oxidation Catalyst)
TRAC® = Triple Action CatalystTRAC® = Triple Action Catalyst
Lower SO2 conversion is required while keeping higher Hg oxidation.
Catalyst
α
NO NO NN22
NHNH33
SOSO22
HC
HgHgClHgCl22
SO2+1/2O2 → SO3Hg+2HCl+1/2O2 →HgCl2+H2O
HCl
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2.4 Key Parameters for Mercury Oxidation
NH3/NOx ratio
Temperature
Halogen concentration(HCl, HBr etc.)
Catalyst DeteriorationArea velocity (volume)
SO2, SO3 concentration
Hg Oxidation Rate
O2 concentration
H2O concentration
Hg0 / Hg2+ ratio
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Deterioration rate
Blue Color : Mercury Oxidation ActivityGray Color : DeNOx Activity
Rel
ativ
e A
ctiv
ity R
atio
1
0 5000 10000 15000 20000 25000 30000Operation Time (hours)
TRAC®
Hg Oxidation and DeNOx activity deterioration rates of TRAC®
trace the same curve with excellent DurabilityHg Oxidation and DeNOx activity deterioration rates of TRAC®
trace the same curve with excellent Durability
2.5 Catalyst Deterioration for Mercury Oxidation
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2.6 Full-Scale Results for PRB Unit (1/2)
Stack Gas Flow Rate 3,397,200 m3N/hr
Temperature 382 ℃
NOx 130-230 ppm
SO2 125-325 ppm
HCl Approx. 3 ppm
NOx Removal 90 %
Slip NH3 <2 ppm
IDFA/H WFGD
BoilerSCR
ESP
- Plant Capacity: 720 MW
- PRB Coal
- TRAC® Supplied in spring 2011
Hg Removal: 30% 60%
Flue Gas Condition
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2.7 Full-Scale Results for PRB Unit (2/2)
Hg-CEM (Continuous Emission Monitor) at the Stack
Prior to TRAC® installationAve. Hg Emission =4.8lb/TBtuDeNOx=80%(estimated)
After TRAC® installationAve. Hg Emission =2.4lb/TBtuDeNOx=80%
1 Layer of TRAC®
Installation
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TRAC®
HoneycombCatalyst
2.8 Full Scale Results for Bituminous Units (1/3)
Temperature 725 F
Hg in coal 0.043 – 0.073 ppm
Cl in coal 43 – 120 ppm
- Bituminous fired Plant (550 MW)- Bituminous Coal- TRAC® Supplied in spring 2010- Measurement Date :
1st Run – Nov., 20102nd Run – Dec., 20103rd Run – Nov., 2011 (after 1 year)
-Measurement point :SCR Inlet, TRAC® Inlet, TRAC® Outlet
: Measurement point
Flue Gas Condition
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0102030405060708090
100
Hg2+
/ H
gtota
l (%)
Nov., 2010 Dec., 2010 Nov., 2011
TRAC®
InletSCRInlet
TRAC®
Outlet
Honey-comb
Honey-comb
Honey-comb
TRAC®
TRAC®
1 layer
80 % of Hg oxidation was achieved by adding 1 layer of TRAC®
from 40% by 3 layers Honeycomb80 % of Hg oxidation was achieved by adding 1 layer of TRAC®
from 40% by 3 layers Honeycomb
Honeycomb catalyst3 layers
2.9 Full Scale Results for Bituminous Units (2/3)
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1
0 5000 10000 15000 20000 25000 30000Operation Time (hours)
Rel
ativ
e M
ercu
ry O
xida
tion
Act
ivity
Rat
io (-
)
Design value
Mercury oxidation rateResults : 56.8% (Average of Nov., 2010 and Dec. 2010 )Design : 55.3%
Mercury oxidation rateResults : 55.1% (Nov., 2011)Design : 51.1%
Hg oxidation activity is still high at one year operation.Hg oxidation activity is still high at one year operation.
2.10 Full Scale Results for Bituminous Units (3/3)
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2.11 TRAC® Record
No. Owner Load (MW)
Coal Supply Country
1 A 640 PRB 2008 US2 B 550 Bituminous 2010 EU3 SC 735 PRB 2011 US4 SC 735 PRB 2011 US5 SC 773 Bituminous 2011 US6 AEP 1,300 Bituminous 2011 US7 SC 950 Bituminous 2011 US8 AEP 600 Bituminous 2012 US9 C 800 Bituminous 2012 EU
10 SC 537 Bituminous 2012 US11 SC 910 Bituminous 2012 US12 SC 950 Bituminous 2012 US13 D 511 Bituminous 2013 US14 E (Full Layers) 418 PRB 2013 US
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