High Efficiency Double Contact Flow Scrubber for the

U.S. FGD Market

Dr. Jonas S. Klingspor

URS Corporation

9400 Amberglen Blvd

Austin, TX 78790

Kiyoshi Okazoe,

Tetsu Ushiku

Mitsubishi Heavy Industries Ltd.

Yokohama, Japan

George Munson

TVA

101 Market Street

Chattanooga, TN 37402

Abstract

Recent awards in the U.S. have highlighted the advantages of the MHI "double contact

flow scrubber" or DCFS FGD system which has been applied to large-scale units during

the latter years of the 1990's. This paper provides a detailed description of the DCFS

FGD system including operating data from recent installations.

The DCFS design features are discussed in detail including the single header stage

fountain spray design, including the single and twin tower design. The operating

experience of recent installations is reviewed including case studies for selected

systems.

Recent operating experience is reviewed in detail. In particular, the paper highlights

design requirements to achieve 802 removal efficiencies as high as 99.9 percent on high

sulfur coals without the use of buffer additives, particular removal efficiencies as high as

90 percent, while produdng wallboard grade gypsum and maintaining 100 percent

system availability in operation for the duration of over 2 to 4 years.

The DCFS design allows utilities to use a high degree of standardized equipment on a

single installation. Modularization of the DCFS design extends the standardization

features to multiple plants regardless of differences in absorber size. The

standardization and modularization features of the DFCS design are discussed in detail.

The Paradise DCFS system currently in the engineering phase is discussed in detail.

1
Background

MHI is the world's leadirg supplier of FGD systems,w ith over 60,000 MNe installed on

154 boilers in 14 countries. The first MHI FGD system was installed in 1964. MHI's wet

FGD system has evolved to a very simple, reliable and highly efficient single loop,

Double Contact Flow Scrubber. During recent years, prominent technology

improvements have included the single stage DCFS spray header design, air rotary

sparger for combined slurry mixing and gypsum oxidation, and jet air sparger for gypsum

oxidation without use of oxidation compressors. This paper presents an overview of the

MHI Double Contact Flow Scrubber, recent operating experience, and provides an

overview of the scrubber design for the TVA Paradise FGD system currently in the

engineering phase.

DCFS Features

The double contact flow scrubber comes in two design configurations; single tower and

twin tower as shown in Figure 1. The single tower design is typically used on low-tomedium sulfur coals and S02 removal efficiencies up to 97 percent. The twin tower

design is typically used on medium-ta-high sulfur coals and S02 removal efficiencies

above 97 percento r to achieve very high particulate removal efficiencies. This paper will

mainly focus on the twin tower design.

Figure 1. Single and Twin Tower DCFS system

Twin Tower DCFS

As the flue gas enters the top of the first tower, the wet dry interface is located nearly 8

feet into the top part of the vessel. This interface is washed routinely with fresh make-up

water to minimize build-up of fly ash entrained in the flue gas. The flue gas encounters

the top of the fountain spray as the gas flows counter-a.ment to the spray in the first of

the twin towers. The recycle slurry is spouted upwards in fountain-like spray by multiple

single-stage nozzles installed on a single spray header located at the lower section of

the first and second towers. This fountain or liquid column in the DCFS contacts the flue

gas as itp roceeds counter-current to the liquid spray and again co-current as liquid and

gas flow downward together. This "Double Cootact" provides for intimate contactf or

2
absorption of 802, excellent utilization of the limestone reagent, and a very high level of

removal of incoming fly ash.

As the gas leaves the first tower, it traverses the top of slurry in the reaction tank before

entering the second tower. In the second tower, the flue gas passes co-current to the

flow of the fountain spray and counter-current to falling droplets of slurry. This additional

second tower and "double contact" design provides the additional gas-liquid contact

such that the resulting 802 removal efficiency can be as high as 99.9%. The gas velocity

in the first tower is typically between 15 to 30 fps while the velocity in the second tower

is typically between 14 to 20 fps. This makes the absorber tower very compact and cost

effective.

The absorber tower is equipped with a singlelevel spray header in each tower. Lowpressure silicon carbide nozzles are used to

provide a fountain-like spray reaching about

15 ft to 30 ft in height. The recycle slurry exits

the spray nozzle much like a liquid rod that

gradually disintegrates into very large spray

droplets as the slurry decelerates and is

pulled back into the recycle tank by gravity.

The fountain-type spray header design

provides a very high degree of gas-ta-Iiquid

contact and a high degree of surface renewal

that improves the recycle slurry's

neutralization capacity. The flue gas also

contacts the slurry twice as the liquid exits

the nozzles and ultimately returns to the

reaction tank. A picture of the fountain

spray is shown in Figure 2.

The spray headers are connected to a single

recycle header pipe that in turn is connected

to the recycle pumps. The spray nozzle has

no internals,p rovide maximum free passage,

and a very low pressure drop as it is

essentially an open pipe. The nozzle is made

from a ceramic material and, because of the

low pressure drop, experiences essentially no

wear over the life of the FGD system. The

MHI spray nozzle is shown in Figure 3. The

spray from the spray nozzle is introduced

parallel to the absorber walls and hence, wall

erosion or header to hecder erosion is not a

problem with this design. Also, as the spray

is directed away from the inlet duct, no

buildup in the inlet duct is experienced.

Figure 2. MHI full-scale spray header

test rig

TI

Figure 3. MHI low pressure drop,

maximum free passage spray nozzle

A pump suction deflection/screening plate is located in close proximity to the pump

suction and spans the entire side of the reaction tank. The screening plate is installed to

3
prevent air that is sparged into the reaction

tank from being entrained into the recycle

pumps and recycle piping. Each pump is

connected to a common recycle header and

is isolated on the suction and discharge sides

of the pump with knife-gate or butterfly valves.

Each pump,g ear box, and motor is identical

providing a high degree of standardization.

The first series of pumps are connected to a

common manifold which feeds the single

spray header in the 2nd tower. The last

series of pumps are connected to a common

manifold that feeds the 1st tower. A spare

pump is available to conned to the 1st or 2nd

recycle header. A typical arrangement of the

recycle pump bay is shown in Figure 4.

The reaction tank operates at 30 percent Figure 4. The DCFS recycle pump bay

solids which promotes gypsum crystal growth

and significantly reduces gypsum scaling.

Also, the high level of suspended solids in the reaction tank provides elevated levels of

limestone which promotes S02 removal and makes the system more tolerant to swings

in inlet S~ concentration.

The twin tower design has the added advantage of using top-mounted agitators,w hich

also double as air spargers. This proprietary design, called the Air Rotary Sparger or

"ARS,n is highly efficient in terms of mixing and oxidation. The ARS oxidation and

agitation system is shown in Figure 5.

In addition to superior agitation, top-mounted

agitators are inherently leak free as the

penetration through the absorber shell is

above the slurry level in the reaction tank.

The ARS is also used to distribute the

oxidation air. COlTlJressed air is distributed to

the horizontal arms of the agitator and

sparged into the recycle slurry. This approach

is highly efficient and requires a lower

quantity of air compared to side entry

agitators or a fixed grid sparger system.

Hence, the power spent on agitation is more

than offset by the reduction in power

consumed by the oxidation air blcmers.

Figure 5. Air rotary sparger for agitation After the flue gas exits the spray zone of the and forced oxidation

second tower, it passes through a two-stage

vertical flow mist eliminator. A 9 ft slurry

and gas disengagement zone is provided between the top of the spray zone and the

face of the first-stage mist eliminator. The provided disengagement zone, coupled with

the very large droplets produced by the fountain-type spray headers, results in a very

low liquid loading to the mist eliminator, even at elevated gas velocities.

4
As the DCFS FGD system operates at 30 percent suspended solids, the system does

not require a primary dewatering system. The absorber bleed pumps can feed directly to

a belt-filter or drum filter for dewatering to desired moisture level. This efficient design

eliminates the primary dewatering step reducing the ca;t and complexity of the overall

system.

Single Tower DCFS

The single tower DCFS system is very similar to twin tower with a few exceptions. First,

this tower design is typically applied on low to medium sulfur coals and for S02 removal

efficiencies at or below 97 percent. In the single tower design, the flue gas enters the

absorber module from the side through a traditional absorber inlet design and exits the

absorber at the top of the module as shown in Figure 1. A single fountain type spray

header is located immediately above the inlet duct. No buildup in the inlet duct is

experienced as the fountain spray is directed away from the inlet duct and parallel to the

absorber walls. The Recycle slurry pumps configuration is identical to the twin tower

design.

Agitation is achieved with either side entry agitators or by using the jet air sparger

system. The single tower design has a fixed front to back distance of about 30 ft which

makes side entry agitators very effective. An alternative to side entry agitators is the Jet

Air Sparger (JAS) system which use a small portion of the recycle slurry flow to inject

oxidation air through a eductor configuration. The eductors are located at the same

place side entry agitators would be located. Hence, the JAS system can provide

efficient oxidation and agitation without the use of agitators and the need of oxidation

compressors. JAS systems operate successfully at several installations.

Standardization and Modularization

The MHI DCFS FGD system is specifically designed to simplify design, engineering, and

construction, and to maximize the portion of the system that can be prefabricated and

brought to the site in large pieces:

• The absorber walls are comprised of standardized panels thata re joined

together.

• The front-ta-back distance is constant for absorber sizes larger than 200 MWe up

to an absorber size as large as 1,200 rvrNe.

• All recycle pumps systems are identical, including flow rate, discharge pressure,

gear boxes, and electrical motor.

• All recycle pump isolation valves are identical.

• All top mounted (ARS) or side-mounted agitators are identical.

• All spray headers and spray nozzles are identical.

The design of the MHI DCFS system is highly standardized, and the size of the absorber

tower only expands in one drection to accommodate differentv olumes of flue gas, as

shown in Figure 6. Therefore, the DCFS design, in addition to standardization, lends

5
itself to adopting a modular design approach. This approach is ideal for system-wide

application when multiple size boilers are involved.

By using a modular approach and

multiple absorber sizes in steps of 200

MWe, the cost of the FGD retrofit

project can be reduced substantially. All

FGD module sizes considered would be

identical except for the width of the

absorber module. The depth and the

height will be the same; the pump size,

header size, nozzle size, agitator size,

and air compressor size will all be the

same - making it possible for plants to

share spare parts or have a common

spare parts facility. Finally, in the MHI

FGD design, all recycle pumps,

gearboxes, and motors are identical

since the DCFS design only uses one

spray header at one elevation, exposing

all recycle pumps to the same pump

head pressure.

i

i

\1

--J -

~,: ,

- _0"

Figure 6. DCFS modularization Approach

For a typical system wide applications of the DCFS system, a base absorber of e.g. 300

MWe in size is selected and add-on modules of 200 MWe in size used to provide

module sizes of 500,700,900, and 1100 MWe. As shown in Table 1, the DCFS system

can provide a very high degree of standardization on multiple absorber sizes including

these different sized modules will use the same size, model, and type of equipment,

including recycle pumps, gear boxes, motors,a gitators, blowers, spray headers, spray

nozzles and mist eliminator, etc.

Table 1 Standardization and Modularization capability of the DCFS system

I - . ,- -- ,>- ,'. I ~, I - .. - - - '-

. ._- -- - - .. -. - -. - -- - - -~ - . -- - ."]: .....4'_·_ - . - ~-~- .-...:....- -:::..._..... .. < --- . - :......--=.~-~-

Recycle Pumps Same Same Different Same

Recycle Pumps Gear Boxes Different Same Different Same

Recycle Pump Motors Different Same Different Same

Recycle Pump Isolation Valves Same Same Different Same

Agitators Same Same Different Same

Agitator Motors Same Same Different Same

Recycle Headers Same Same Different Same

Recycle Nozzles Same Same Different Same

Mist Eliminator Same Same Same Same

Mist Eliminator Wash Nozzles Same same Different Same

6
Installed FGD capacity -60,000 MWe

FGD Orders Last 10 'ttlars -30,000 MWe

Highest 502 QJarCl1teed Removal 99.sor.

Highest 502 Removal w/O AdditIVes 99.9Or.

Highest 502 ConC9l'ltJatJoo 7,800 ppm

largest Single Absorber 1,OSOMWe

Longost TIme berw-een OUtages 4yrs

Spare Modules InstaUed None

Highest Availability, SIngle Module lcm,/~

The modularization approach makes it possible to benefit from standardized equipment

across a fleeto f FGD system basically independent of absorber size. Hence, a shared

or a common spare parts inventory is feasible. It is also feasible to minimize the number

of absorber modules required can be reduced by treating two boilers with one absorber

module. For example, a 178 MW and a 348 MW module can be treated in one 600 MW

absorber module as is currently done at the Bailly Station in Indiana.

Development History of DCFS

After completion of fundamental tests using 15,000 m3N/h pilot facility at MHI Hiroshima

R&D Center, the DCFS was subjected to joint Verification tests with Chubu Electric

Power Co. and Chugoku Electric Power Co. using actual coal flue gas in 15,000 m3N/h

and 300,000 m3NIh facilities respectively. Subsequently, counter-current DCFS was

selected for the 136 MW heavy oil-fired NO.2 unit of Kashima-minami Joint power

station in 1993 followed by a co-current DCFS system for coal-fired 175 MW NO.1 unit

of Chugoku Electric's Shimonoseki power station in 1994. A large scale co-current

DCFS system was installed in 1998 at the 1,OOOMW Misumi Power station of Chugoku

Electric Power Co., followed by a 2000 1,050 MW twin tower DCFS system at the

EPDC Tachibanawan station and a 700MW twin tower DCFS system at Shikoku Electric

Power Co. Tachibanawan A high performance twin tower DCFS system was installed

in 1998 at the 149 MW KOA oil refinery in Osaka. This system provides a S~ removal

efficiency of 99.9 percent on high sulfur fuel oil. More than 20,000 MW of DCFS

systems have been sold and/or installed sinCE the introduction of the DCFS system in

1993.

Experience

MHI has experience with a Table 2. Overview of MHI FGD Experience

wide range of operating

conditions as shown in Table 2.

It is noteworthy that MHI has

never installed a sp:lre operating

module at any of its 155

installations. However, most of

the MHI systems operate a very

high availability levels. The

experience on hgh sulfur coals

is very extensive with the

highest S02 concentration

experienced at 7,800 ppm. The

experience v.Ath large single

modules and high S02 removal

efficiencies is also extensive.

7
Large Single Modules

MHI has experience with the single

absorber modules starting at a

moderate size of 150 MWe to the

largest absorbers in the world at 1,050

MWe. The vast majority of our FGD

systems are based on a single absorber

module, regardless of size. All systems

operate without installed spare module

capacity.

The experience with different size

absorbers is less of an issue with the MHI

design. The depth and height of the MHI

absorber are basically independent of

absorber size. To accommodate a larger

flue gas volume, the absorber tower is

made wider, keeping all critical

dimensions impacting gas/liquid contact

unchanged from project to project The

experience IMth large single modules is

shown in Table 3.

High S02 Removal Efficiency

The fountain spray design generates very

effective gaslliquid contact, and the

DCFS FGD design is capable of very

high S02 removal efficiencies. The DCFS

system has proven performance on all

ranges of sulfur and very high S02

removal performance up to 99.9%. Table

4 provides a partial listing of FGD plants

operating at an S02 removal efficiency of

98% or higher.

The highestS O2 removal guaranteed by

MHI was 99.8% on a sulfur loading of

2,200 ppm S02. During guarantee

testing, this unit recorded an S02 removal

efficiency of 99.9% or 2 ppm S02 in the

outlet duct. MHI has 50 FGD plants

operating at an S02 removal efficiency of

95% or higher, 25 plants above 96%, 12

plants above 97%, 10 plants above 98%,

and 4 plants above 99%.

Table 3. Experience IMth Large Absorber

Modules

Elldric_,De.elopmem Co lid 1.050'1 B82 44 950 (T_,Japan)

Tohakw EIICIriC Power Co. Inc:. 1,000·1 910 70 92.3 (HanunocIl.l.J8pan)

Sohma Joint Thermal 1000-1 1.015 102 90.0 Power. LId (Sohma. Japan)

Chugoku EJec:trjc Powe, Co LOOO·1 921 91 90.2 lnc.(\,IlIun'Uapan)

___'Co,

700>1 1015 91 91,0 Inc. (IoIalsuln. Japan)

Ctwllu EIodt1c powtlr Co" Inc 700>1 803 51 93,6 (Heldnan, Japan)

Chubu EIec:anc Power Co_, Inc. 100>11 803 51 93.6 (HeUlan Japan)

Chullu EJec:trjc Powe' CO, Inc. 700-1 803 51 93,6 (H-n, Japan)

EJedtidly Genet8llng AutllOf1ly 0' 700·1 1.733 79 95,4 ThaiaOO (RalcMIlurt. Thailand)

Eledr1c:IIy Gene",1Ing AUlhort!y 01 700-1 1,733 79 954 Th81800 (RakNIlurt, Thailand)

--- 700-1 840 46 945 Co .IJll.(T--,Japan)

ENE\.(8- Sud. 14. ftlly) eeO·l 1.610 81 950

ENE\. (8_1 Sud, 113. lilly) 660-1 1,810 81 95,0

Table 4. Experience IMth High S02

Removal Efficiencies

, . .'

- I l'"

- ...- - -- -

- - ~---

1 2003 COSMOOtLCo.LlJl. lY_

... 223><' 3.433 17 99,5 )

1 2004 KOAOlLCo.. Ud- (Uanll ...) 1<&811 4.087 25 994

I 1997 ENEL (SUds, 113, Italy) 240'1 5.740 8' 98,6

1994 ENEL (SUcis.-:2, Italy) 240'1 5,740 81 986

19i3 ENS. (sua.. 1f1. Italy) I 240" 5,740 81 986

2004 -_P....- lWxl 2,917 50 983 RIIIr*1o eo... Ud. (MlWoran_ JIO~)

2003 Kalhini Northern Elec::tl1e POMlr 300<1/2 5.686 117 98.0 Co. (l(aal'/ma-Klla fJ, Jopon)

2002 K-..I Bedric Power Co .Inc 600rl 554 18 970 (Gobo03.~)

1975 Tolin. Ud. (e*ne....1 1.740 53 970

1977 CIugoku _-Co. 400'1 1,845 53 96.8 Inc (5I1Im<ln_kl, Japan)

1964 NKKCorp. 3,070 102 967 -)

8
'00

'00

100

'00

100

100

95.3 ...

95..

95.0

"$

"'2

eolHncI

Co..~

eo.I.f'Ir.cli &w 95.0

~SGulh"",~r

1~7t .:.o·~a~"

~-""I\J

1* Ir~:==:-'Co, ,1llX).1

Table 5. Availability of single module

DCFS Systems

High System Availability

Historically, the fundamental

shortcoming of FGD systems has been

their availability and the resulting impact

on power generation. This shortcoming

was particularly evident in the late '70s

and early '80s. The Clean Air Act Phase I

FGD systems had addressed mosto f the

earlier problems and improved the

availability records to be in the high 90s.

However, most Phase 1 FGD systems

included a spare absorber module.

The drive in the domestic Japanese

market has been to higher and higher

availability, up to and including 100%

online time. The DCFS technology was

successfully developed to meet the

market need for ultra high availability

using a single absorber module. Table 5

shows the DCFS availability record of selected DCFS installations. The availability data

shown on Table 5 are the cumulative availability over the operational period (life of

system) thus far. The simplicity of the DCFS design, combined with extensive

experience and lessons learned, makes it possible to design the DCFS system to

achieve 100% availability with a single absorber.

Case Studies

EPDC - 1,050 MW Single Module DCFS System

The FGD system at EPDC's

Tachibanawan station is the largest

capacity absorber in the world, treating

the entire flue gas volume of the 1,050

MW boiler in a single module. The

absorber is the twin-tower Double

Contact Flow Scrubber (DCFS) type

including a co-currentf low tower and a

counter-current flow tower. The absorber

was designed to comply with extremely

stringent particulate and S02 regulations.

Particulate emissions are regularly below

5mg/Nm3 and SO:1 removal efficiency

above 95 percent. The FGD process

control system is designed to

automatically control the number of Figure 7. EPDC Tachibanawan 1,050

pumps in service depending on boiler MW Single module DCFS system

load and coal sulfur levels. Since the inlet

9
Figure 8. KOA high efficiency DCFS

system

S02 concentration is lower than the designed value, the absorber is automatically being

operated with a reduced number of slurry recirculation pumps, resulting in reduced

power consumption. Th system produce wallboard grade gypsum which is sold locally.

The FGD plant has been in commercial operation for two years and has achieved

cumulative availability of 100 percent.

KOA - 99.9% S02 Removal

The FGD plant at the KOA refinery is a

high sulfur twin tower DCFS application

that has achieved the industry's highest

desulfurization performance of 99.9%

exceeding the guaranteed S02 removal

efficiency of 99.8 percentw ithout using

performance additives. The FGD system

has the equivalent size of 149 MNe and

treats flue gas from a vacuum residue

boiler. The S02 concentration ahead of

the FGD system is typically about 2,000

ppm while the S~ concentration in the

stack is below 2 ppm. In addition to

emitting very low S02 emissions,

particulate emissions are typically below

1.3 mg/Nm3

. In the past, such a high

desulfurization capability has been

considered impossible without the use of

additives. It is achievable with the twin

tower DCFS design, due to the excellent

gas/liquid contact and the absence of gas

sneakage along the absorber walls. The

unit went into operation in 1998 and has achieved a cumulative availability of 100

percent since startup.

North American Activities

MHI in partnership with URS through a Joint Venture company named Advatech is

marketing MHI's DCFS FGD system in North America. Advatech is currently providing

design and implementation services for the Tennessee Valley Authority for up to five

FGD systems. The first FGD system will be installed at the Paradise station on the Unit

3 boiler. This system will be put in operation in 2005 to 2006 time frame. Also, a

conversion of the Widows Creek Unit 8 FGD system to a twin tower DCFS design is

currently underway. The Widows Creek DCFS system will be operational in December

of 2003. A more detailed description of the Paradise project is provided below.

Paradise Unit 3 FGD System

Advatech has been awarded the FGD system for the Paradise Unit 3 station which is a

1,050 MNe pulverized coal-fired boiloer firing high sulfur eastern bituminous coal.

Advatech will provide EPC services for the entire scope induding limestone preparation,

absorber island, fans, ductwork, stack and balance of plant.

10
The FGD system will based on the MHI DCFS twin tower design and will utilize a single

absorber tower which will provide a S02 removal efficiency of 98 percent. A pictorial of

the FGD system layout is shown in Figure 9. The FGD inlet is symmetrically divided to

take flue gas from each of the ESP trains. New booster fans are provided and are close

coupled with each of the absorber inlet ducts

Figure 9. Layout of the new FGD system at Paradise

Unit 3

As the gas leaves the first

tower, it traverses the top of

slurry in the reaction tank

before entering the second

tower. In the second tower,

the flue gas passes cocurrent to the flow of the

fountain spray and countercurrent to falling drops of

slurry.

The flue gas encounters the top of the fountain spray as the gas flows counter-current to

the spray in the first of the twin towers. The recycle slurry is spouted upwards in

fountain-like spray by multiple single-stage nozzles installed on a single spray header

located at the lower section of the first and second towers. The nature of this design

makes it impossible to get recycle slurry into the absorber inlet ductwork or booster fans,

which has been a common problem with spray and tray towers in recent years. This

fountain or liquid column in the DCFS contacts the flue gas as itp roceeds countercurrent to the liquid spray

and again co-current as

liquid and gas flow

downward together. This

"Double Contact" provides

for intimate contact for

absorption of S02, excellent

utilization of the limestone

reagent, and a very high

level of removal of incoming

fly ash.

The recycle pump bay is located in fronto f the second tower. The FGD system will

require 11 slurry recycle pumps rated at 48,000 gpm. Four recycle pumps discharge

into a common external recycle header which provide slurry for the first absorber tower

which operates at about 21 fps gas velocity. Six recycle pumps discharge into a second

common recycle header which provides slurry to a the second absorber tower. The

second tower operates at about 15 fps gas velocity. The 11th pump is located between

the two recycle headers and provide spare capacity to either external header.

Each of the twin towers is equipped with a single level spray header. Low-pressure

silicon carbide nozzles are used to provide a fountain-like spray reaching about 16 to 20

ft in height. The recycle slurry exits the spray nozzle much like a liquid rod that gradually

disintegrates into very large spray droplets as the slurry decelerates and is pulled back

into the recycle tank by gravity The fountain-type spray header design provides a very

high degree of gas-to-Iiquid contacta nd a high degree of surface renewal that improves

11
the recycle slurry's neutralization capacity. The flue gas also contacts the slurry twice as

the liquid exits the nozzles and ultimately returns to the reaction tank.

The low-pressure drop nozzle has no internals, a maximum free passage, and a very

low-pressure drop. The nozzle is made from silicon carbide and, because of the lowpressure drop, experiences essentially no wear.

The single module, twin tower design has the added advantage of using top-mounted

agitators,w hich also double as air spargers. This proprietary design, called the Air Rated

Sparger or "ARS,n is highly efficient in terms of mixing and oxidation. The new system

includes three top-mounted "ARS,n agitators. Adequate agitation is critical to scale-free

operation. The ARS is also used to distribute the oxidation air. Compressed air is

distributed to the horizontal arms of the agitator and sparged into the recycle slurry. This

approach is highly efficient and requires a lower quantity of air compared to side entry

agitators or a fixed grid sparger system. Hence, the power spent on agitation is offset by

the reduction in power consumed by the oxidation air blovvers. Two operating

compressors and one spare air compressor provide oxidation air.

A pump suction deflection/screening plate is located in close proximity to the pump

suction and spans the entire side of the reaction tank. The screening plate is installed to

prevent air that is sparged into the reaction tank from being entrained into the recycle

pumps and recycle piping.

After the flue gas exits the spray zone of the second tower, it passes through a twostage vertical flow mist eliminator. The provided design is based on using a high velocity,

high efficiency chevron type of mist eliminator. An 8 ft disengagement zone is provided

between the top of the spray zone and the face of the first-stage mist eliminator. The

provided disengagementz one, coupled with the large droplets produced by the fountaintype spray headers, results in a very low liquid loading to the mist eliminator, even at

elevated gas velocities.

A fixed grid wash system is provided to wash the leading and trailing edges of the first

mist eliminator and the leading edge of the second mist eliminator.

The proposed system is designed to operate in an open loop configuration and does not

include any dewatering system other than reaction tank bleed pumps thatw ill pump

reaction tank slurry to a pond. The water in the pond is not reclaimed or reused in the

process.

A wet stack will be provided to discharge the clean flue gases to the atmosphere.

A new limestone grinding system will be installed which will provide a limestone grind of

90% less than 325 mesh.

12
Summary

MHI introduced the DCFS system in the early '90s and, to date, more than 20,000 MW

has been installed and/or sold. The DCFS system was specifically designed to provide

absolute reliability as demonstrated by the numerous installations operating at 100

percent availability with a single a absorber module. The absorber tower is equipped

with a single spray header which by design does notg enerate any wall erosion from

spray impacting on the walls or any header to header erosion. The fountain spray

provides a very efficient gas/liquid contact which is also demonstrated by the very high

particulate removal provided by the system. The experience with high sulfur coals, very

high removal efficiencies, high availability with a single absorber module is

considerable. The firstg reenfield DCFS system in the U.S. is being installed at the TVA

Paradise station which will go into operation in 2006. A second system is being installed

at TVA's Widows Creek station through a rebuild of the existing FGD system to the

DCFS design. The Widows Creek DCFS system will be operation in late 2003.

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