6 The Babcock & Wilcox Company

WFGD Case Study -- Maximizing SO2 Removal

by Retrofit with Dual Tray Technology

BR-1785

Technical Paper

A.A. Silva and P.J. Williams

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

J. Balbo

Michigan South Central Power Agency

Litchfield, Michigan, U.S.A.

Presented to:

EPRI-DOE-EPA-AWMA

Combined Power Plant Air Pollutant Control

Mega Symposium

August 28-31, 2006

Baltimore, Maryland, U.S.A.
WFGD Case Study - Maximizing SO2

 Removal

by Retrofit with Dual Tray Technology

BR-1785

James Balbo

Michigan South Central Power Agency

Litchfield, Michigan, U.S.A.

Anthony A. Silva and Paul J. Williams

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

Abstract

Michigan South Central Power Agency (MSCPA) operates a

nominal 55 MW unit with a limestone forced oxidized WFGD

system. It has been in operation since 1983. The absorber was a

tray tower with a single tray designed for 90% SO2 removal and

supplied by The Babcock & Wilcox Company (B&W). The boiler

fires high sulfur eastern bituminous coal producing SO2 loadings up

to 7.5 lbs/MBtu. To increase the removal in the WFGD system,

MSCPA and B&W added a second tray in 2002 to take advantage

of dual tray technology. SO2 removal has been increased from 90%

to 98% without the use of organic acids. Performance tests and

parametric tests have been performed on the system over the last

two years. The testing also included tests for SO3, HF, HCl, and

PM. This paper discusses the absorber design, operating parameters, results of the testing and system chemistry.

Introduction

The need for maximum SO2 removal is necessary with the upcoming Clean Air Interstate Rule (CAIR). To meet these demands,

high efficiency scrubbers are necessary. This paper provides an

evaluation based on limestone, forced oxidized systems since this

is the most common type of system being used now and in the

foreseeable future. High efficiency can be gained by changes to the

chemistry of the slurry or by increasing the contact of gas and

slurry in the absorber. The typical change to the system chemistry

is the addition of adipic acid or a composite dibasic acid such as

DBA. Contacting can be increased by increasing the liquid to gas

ratio (L/G), which also increases the alkalinity available per pass.

It is difficult to add more L/G, physically and financially, because

this usually involves adding more spray headers and absorber recirculation pumps. There is usually not enough space available to

accommodate this. Increased contacting can also be achieved by

the addition of a contacting device such as an absorption tray or by

reducing the open area of an existing tray. In these cases the L/G

remains the same, but the absorption of SO2 per unit volume of

slurry increases. In order to add another tray, the space must be

available to do so. Adding a tray or decreasing the tray open area

increases the absorber pressure drop.

B&W has 6 units operating with two trays and has 19 other

dual tray units in the design, construction and startup phases. The

purpose of the described project was to convert a conventional,

90% SO2 removal scrubber into a high efficiency (>95% SO2 removal) scrubber. B&W proposed to maximize SO2 removal by

adding another tray to this limestone forced oxidized scrubber.

Michigan South Central Power Agency was an ideal location for the

demonstration because their wet flue gas desulfurization (WFGD)

system is a limestone, forced oxidized system with a single existing

absorption tray and because of the good working relationship between the two companies. Their absorber design also had provisions for an additional future tray. The baseline performance measured in 1998 is as follows (Table 1):

After the modifications were made to the system, field performance tests were carried out. The last of the testing occurred

during November 2005. In addition to SO2 being tested, some

multi-pollutants were also tested to gather baseline data of the

plant. Those multi-pollutant tests included solid particulate matter, sulfuric acid mist, hydrogen chloride and hydrogen fluoride.

These results are presented with the SO2 data.

Background

Michigan South Central Power Agency’s Endicott Generating

Station, Unit 1, was supplied by The Babcock & Wilcox Company

in 1981. See Fig. 1. The boiler is a Sterling design rated for 480,000

lb/hr steam flow and a nominal 55 MW while burning bituminous

coal. The air quality control system (AQCS) consists of a cold

Parameter

SO2 removal

Inlet SO2

 loading

pH

Stoichiometry

L/G

Absorber pressure drop

Table 1

 MSCPA 1998 Performance

Units

%

lb/MBtu

--

Ca/S

gpm/macfm

in. wg

Values

90

6.5

5.6

1.06

85

3.6

Presented to:

EPRI-DOE-EPA-AWMA

Combined Power Plant Air Pollutant Control

Mega Symposium

August 28-31, 2006

Baltimore, Maryland, U.S.A.
2 The Babcock & Wilcox Company

electrostatic precipitator (ESP) and wet FGD. The FGD system is

a forced oxidation design consisting of a single absorber, a reagent

preparation system, and primary and secondary dewatering systems. Prior to adding the new, second tray, the scrubber performance had deteriorated and the plant struggled to meet compliance

at high sulfur loadings, > 6.5 lb/MBtu and high boiler loads, 60

MW. The primary reasons for this poor performance were sulfite

blinding and inadequate flow of limestone slurry to the absorber.

The limestone feed slurry density was about 13% which limited

the limestone flow. The pH was limited to 4.6 to 4.8. SO2 removal

averaged about 83% with a single tray.

The absorber system consists of one 22’6" diameter absorber

tray tower. The original design was a single absorption tray. In

October 2003, a second absorption tray was added. The material

of construction above the inlet is 317L. The absorber inlet has a

C276 awning and side shields to prevent absorber inlet plugging.

The absorber has two slurry spray levels operating above the tray.

There is no spare spray level. Three absorber recirculation pumps,

two operating and one standby, are provided to feed the slurry

spray headers. The absorption spray zone is lined with Stebbins

tile to protect it from spray impingement. Two stages of mist

eliminators are supplied in the absorber tower with automatic sprays

above and below the 1st stage and below the 2nd stage of mist eliminators (ME). The 2nd stage ME overspray is provided with a wash

header, manually operated. A sparge grid oxidation system is provided for insitu oxidation of the tank. Additionally, four air lances

have been installed at the bottom of the tank to provide additional

air flow and to fully oxidize the tank at the higher than designed

removal efficiency and inlet SO2 loading.

The scrubbing reagent used is limestone, which is ground by a

single, 100% vertical tower mill. Dewatering consists of primary

and secondary systems. The absorber blowdown slurry is sent to

a single, 100% thickener for primary dewatering. The underflow

from the thickener is sent to a thickener underflow tank and then

batched to the rotary drum vacuum filters. Two vacuum filters are

provided, one operating and one spare. A gypsum byproduct is

produced from the cake of the vacuum filter and is currently being

landfilled.

In 2003, a second absorption tray was added to the absorber

tower. See Fig. 2. This new tray did not have the same pressure

drop as the existing tray because of limitations on the ID fan.

Improvement of SO2 removal on the system was seen, but the full

effect was not observed. The removal increased from 83% to about

89%. The main reason was continued sulfite blinding. It was expected that the delivered oxidation air was adequate for the increase

of SO2 removal, but that was not the case. Also, the limitations on

the ID fan were observed to be an absorber inlet plugging related

problem. At least twice per year, the absorber inlet needed to be

cleaned before upsetting boiler operations because of high differential pressure drop.

In 2005, a few more modifications were made to the system for

system reliability and to enable the second tray to be more effective. During the plant outage, the C276 inlet awning was cleaned to

remove some hard solids, which developed over the years, at the

top gap in the awning. After cleaning, it was discovered that the

awning was severely corroded and needed replaced. This new

awning resolved the inlet plugging issues. Next, some rubber plugs

were added to the second absorption tray to increase the pressure

drop so that it equaled the first tray. Lastly, oxidation air lances

were added to the bottom of the absorber reaction tank to improve

oxidation and stop sulfite blinding. The combination of these improvements allowed the FGD system to reach its full performance

capacity. SO2 removals can now reach as high as 98%.

SO2 absorption theory

Scrubber design and SO2 absorption

The design of a wet scrubber can be reduced to just two basic

requirements. The first is to contact the gas and slurry. The second

is to provide alkalinity to neutralize the acid formed when SO2 is

absorbed.

Contacting the gas and slurry can be accomplished using only

the absorber slurry sprays (L/G) such as in an open spray tower

design. The key to this is getting good gas distribution and good

slurry spray distribution. In an open spray tower the contact

surface of the spray droplets and the contact of the gas with these

droplets is the primary means of removing SO2

. This leaves one

primary parameter, pump flow, to be adjusted to achieve the desired performance. The contact surface can also be increased by

providing more droplet surface area (higher nozzle pressure drop),

but also at the expense of pump power, and increasing the droplet

surface area quickly reaches the point of diminishing returns.

The gas and slurry contacting and SO2

 removal can be greatly

improved by using some type of contacting device(s). B&W’s

choice of contacting device is a perforated tray(s). The absorber

tray provides intimate contacting between the gas and slurry. The

contact surface provided by the tray is much more effective for SO2

removal than that of the slurry droplets in a spray tower design.

Fig. 1 Michigan South Central Power Agency’s Endicott Station.

Fig. 2 A second absorption tray was added in 2003.
The Babcock & Wilcox Company 3

Gas distribution

First the tray provides a resistance to distribute the gas flow

uniformly over the tower cross-section. This resistance is provided at the start of the gas and slurry contact zone, or the absorption zone, in the absorber. Therefore, the contact of the gas with

slurry is optimized over the full height of the absorption zone. In

an open spray tower, the pressure drop across each spray level will

tend to distribute the gas. However, by the time the successive

pressure drops have redistributed the gas, the gas has already traveled through much of the absorption zone. This is not making full

use of the L/G being provided. Uneven gas distribution results in

areas of high and low L/G within the absorber. In areas where the

L/G is higher than the design L/G, the SO2 removal will be higher

than design. However, areas of lower L/G will have less than the

average removal. When designing to 98% removal, the area of lower

L/G does not have to be too large to seriously limit the overall SO2

removal efficiency.

Contacting effectiveness

The tray provides a much more efficient means of gas and slurry

contact than slurry sprays. Contacting devices are well known to

provide the optimum design in most gas–liquid absorption systems. In fact, most of the first utility scrubber designs were based

on the use of some type of packing or trays. The use of a tray in

an absorber is typically worth 25 to 30 L/G. That is, the absorber

with a tray requires 25 to 30 L/G less than an open spray tower

design. This is illustrated in field unit test data presented in Fig. 3.

The curves indicate that 80% removal efficiency could be achieved

operating without a tray at 60 L/G or with a tray at about 35 L/G.

The data also indicates 95% removal at 60 L/G and using a single

absorption tray.

Dual tray technology

The effect of using a single tray or using a dual tray design can be

demonstrated from field and pilot plant data. Table 2 presents the

test results achieved by adding trays. The increase in removal

efficiency via adding a second tray in a recent pilot plant test

program is also presented.

The results presented in Table 2 verify the capabilities of using

trays in achieving high removal efficiencies at relatively low L/G

ratios. In addition to SO2 removal, Table 2 also provides the Number of Transfer Units (NTU) obtained by the absorber. Transfer

units are a measure of the actual mass transfer work done by a

scrubber and are related to SO2 removal as shown in Fig. 4. A

comparison of the NTU for the results listed in Table 2 indicates

that the addition of a tray increases the NTU by about 50%, or an

enhancement factor of 1.5.

Equation 1 – Relationship between NTU and SO2 fractional

efficiency: NTU 1ln( −−= fractional efficiency)

Chemistry, alkalinity and SO2 absorption

In addition to gas and slurry contacting, sufficient alkalinity has

to be provided to neutralize the acid formed when SO2 is absorbed,

the alkaline species being the calcium carbonate in the limestone.

The on-line measurement of dissolved alkalinity is the pH of the

slurry in the reaction tank. An increase in pH indicates higher

concentrations of dissolved alkalinity with the resultant increase in

the SO2 removal (all other parameters being equal). However, the

pH is only a measure of the alkalinity in solution in the reaction

tank or the recirculated slurry sprayed into the gas. This dissolved

alkalinity is not sufficient to neutralize the SO2 removed in the

absorption zone. There is also dissolution of limestone in the

absorption zone. Therefore, if this dissolution can be increased,

there will be an increase in SO2 removal. The amount of limestone

that dissolves in the absorption zone is dependent on the time the

slurry spends in the zone. This holdup time is longer when using a

tray. The slurry holdup time is dependent on the tray pressure

drop. So the tray or trays increase SO2 removal due to improved

and more efficient contacting than L/G and also by providing more

dissolved alkalinity in the absorption zone.

A dual tray absorber designed for 98% removal with a medium

to high sulfur coal provides approximately 3.5 seconds of slurry

residence time, slurry holdup, on the trays. The pH of the slurry

on the tray is lower than that in the reaction tank. If the pH in the

reaction tank is 5.5 then the pH of the slurry on the trays will be

about 4.0. The rate of dissolution of limestone is directly proportional to the concentration of hydronium ion [H+] in the slurry. At

a pH of 4.0, [H+] is 31 times higher than the [H+] at a pH of 5.5.

Therefore, the rate of limestone dissolution is 31 times faster than

in the reaction tank. The 3.5 seconds of retention time on the trays

is equivalent to 1.9 minutes of reaction tank retention time. The

Unit

Winyah

Winyah

Pilot

Pilot

MSCPA

MSCPA

Table 2

Effect of Trays on SO2 Removal

# Trays

1

2

1

2

1

2

L/G

48

48

40

40

70

70

Removal

82

93

82.4

92.6

90

96.5

NTU Enhancement

Base Winyah

1.54 Base

Base Pilot

1.5 Base

Base MSCPA

1.47 Base

Fig. 3 SO2 removal with and without tray.

Fig. 4 Number of transfer units (NTU) vs. efficiency.
4 The Babcock & Wilcox Company

Parameter

SO2

 Removal

Inlet SO2

Inlet SO2

pH

Stoichiometry

L/G

Absorber ∆P

Gas Velocity

Table 3

Summary of SO2 Test Results

Units

%

ppmdv

lb/MBtu

--

--

gal/kacf

in. wc

ft/sec

1998

Baseline

90

2400

6.5

5.6

1.06

85

3.6

8.7

2003

Single Tray

83

1900

n/a

4.6 – 5.0

1.06

93

3.7

8

2003

 Dual Tray

89

2400

5.3

5.0

1.05

87

5.3

8.5

2005

Dual Tray

95

3100

6.4

5.8

1.03

95

7.6

7.6

Test Method

Controlled

Condensate –

NCASI

Method 8A

U.S. EPA

Method 26A

U.S. EPA

Method 26A

U.S. EPA

Method 5B

Table 5

 Multi-Pollutant Test Results

Multi-Pollutant

H2

SO4

(1)

HCl

HF

Solid Particulate(2)

FGD Inlet

lb/MBtu

0.0066

0.1671

0.0120

0.017

FGD Outlet

lb/MBtu

0.0025

0.0004

0.0001

0.015

Removal

%

62

99.8

99.5

11

Note 1 — Based on 4 run average

Note 2 — Based on 2 run average

Parameter

SO2 Removal

Inlet SO2

Inlet SO2

pH

Stoichiometry

L/G

Absorber ∆P

Gas Velocity

Table 4

Summary of Maximum SO2 Removal Test Results

Units

%

ppmdv

lb/MBtu

--

--

gal/kacf

in. wc

ft/sec

2005 Dual Tray –

high pH

98

2900

5.8

6.1

1.05

87

8.9

8.3

2005 Dual Tray –

high L/G

97

3200

6.8

5.9

1.02

107

8.9

7.8

slurry retention time in the reaction tank is typically 5 minutes.

Therefore, the dual trays provided roughly 30% of the limestone

dissolution in the system.

One question to ask in setting the design of an absorber is at

what point the slurry will exceed an absorption limit for the slurry

in pounds of SO2 per unit volume of slurry. This can be loosely

considered as a minimum L/G required to get alkalinity into the

absorption zone and onto the tray. For the purpose of this paper,

this measurement will be pounds of SO2 absorbed per gallon of

recirculated slurry. It is obvious that a tray tower operating at a

lower L/G than a spray tower must have a higher absorption. The

question becomes, what is the upper limit to this absorption? B&W

has demonstrated absorptions as high as 6.7 lbs SO2 per 1000

gallons of slurry. The SO2 absorption with 2 trays at MSCPA is

about 5.0.

Test program and results

Multiple field performance tests for SO2, absorber gas flow,

absorber static pressure drops and other important performance

parameters occurred from September 2003 to November 2005.

Samples of absorber and limestone slurry were also taken and analyzed during this test period. SO2 data was collected by U.S. EPA

Method 6C. SO2 data collection was also taken and compared with

the plant CEMS.

Emission testing for SO3, HCl, HF, F and solid particulate was

performed during November 2005. This data was taken to gather

some baseline performance of how the absorber module could remove these multi-pollutants.

SO2 removal

Sulfur dioxide was compared from some 1998 baseline data of

the scrubber, 2003 single tray baseline data, and 2003 and 2005

dual tray data to determine the effect each modification had to the

system. All SO2 concentrations were measured by U.S. EPA Method

6C at the inlet and outlet of the absorber module. The absorber “P

was measured by static pressures from the absorber module. Gas

velocities were calculated from the absorber module gas flow and

absorber module diameter. The gas flows were measured by U.S.

EPA Method 2G, gas flow measurement by 2D probes. The L/G

was calculated from pump flow estimates and the actual gas flow.

The pH was measured using a portable, calibrated hand held meter

from a slurry slip stream from the absorber module.

A summary of the data taken during the tests is presented in

Table 3. The difference between the 1998 to 2003 single tray data is

attributed to low limestone slurry feed flows to the absorber modules. The plant was operating at low limestone slurry feed densities, about 13 to 15%, and could not get enough limestone into the

absorber module. After the second tray was installed in 2003, SO2

removal increased from 83% to 89%. But, the system was still

limited by low limestone slurry feed densities and some sulfite

blinding. In 2005, the system was corrected to increase the limestone feed density to 24% and additional air was added to the

bottom of the reaction tank to stop the sulfite blinding. These

changes, plus the increase of pressure drop across the second tray,

improved the SO2 removal to 95%.

Additional data was taken during the 2005 dual tray tests to

maximize the SO2 removal across the FGD. This included raising

the pH and operating the spare absorber recirculation pump. This

data is presented below in Table 4.

The absorber was tested to attain SO2 removal as high as 98%.

These tests were performed to determine the maximum SO2 the

scrubber could remove and it should be noted that the plant does

not necessarily need to operate at these conditions.

Multi-pollutant results

Some multi-pollutant tests were taken as baseline data from the

dual tray 2005 tests. Testing was completed at the inlet and outlet

of the FGD system to gather absorber module removal efficiencies

of these multi-pollutants.

Testing is based on 3 run averages unless stated otherwise and is

shown in Table 5.

Conclusions

• The dual tray demonstration was a success; it dramatically

increased SO2 removal across a conventional absorber module.

• SO2 removal was increased from 90% to a maximum of 98%

at the high pH case.

• At normal conditions, the plant typically operates at 95%

SO2 removal.

• The plant can stay in compliance, for SO2

, even when burning extremely high sulfur fuel, 6.5 to 7.5 lb/MBtu.
The Babcock & Wilcox Company 5

Copyright © 2006 by The Babcock & Wilcox Company

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