2013 advanced aqcs technology for further emission control · advanced aqcs technology for further...

All rights reserved Copyright © 2013, Babcock-Hitachi K.K. 0

Advanced AQCS Technology for Further Emission Control

-CONTENTS-

1. Ultra Low PM Emission Control Using Gas Cooler

2. Mercury Removal Using Special Catalyst

All rights reserved Copyright © 2013, Babcock-Hitachi K.K.

Takanori Nakamoto (Babcock-Hitachi K.K.)27 Nov., 2013 @ VGB-TENPES EXPERT MEETING


1. Ultra Low PM Emission Control Using Gas Cooler


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


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


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


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


1.5 Heat Recovery Tubes (Low Dust Operation)

Initial

After the operation


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


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.)


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


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


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


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


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


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


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


1.15 Pilot Test Plant (1.5MWth) in BHK/Akitsu

Flue gastreatment facility

DESP

Combustionfacility

Control room

SCRWFGD


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


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


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.


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


2. Mercury Removal Using Special SCR Catalyst (TRAC®)


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


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


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


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


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


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


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


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


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



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.



2.11 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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2013 advanced aqcs technology for further emission control · advanced aqcs technology for further...

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