6 The Babcock & Wilcox Company 

# WFGD Case Study -- Maximizing SO 2

# 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 SO 2

# 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% SO 2 removal and supplied by The Babcock & Wilcox Company (B&W). The boiler fires high sulfur eastern bituminous coal producing SO 2 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. SO 2 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 SO 3 , HF, HCl, andPM. This paper discusses the absorber design, operating parameters, results of the testing and system chemistry.



## Introduction
The need for maximum SO 2removal 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, becausethis 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 SO 2per 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% SO 2 removal scrubber into a high efficiency (>95% SO 2removal) scrubber. B&W proposed to maximize SO 2 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 existingabsorption 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 SO 2 being tested, some multi-pollutants were also tested to gather baseline data of theplant. Those multi-pollutant tests included solid particulate matter, sulfuric acid mist, hydrogen chloride and hydrogen fluoride. These results are presented with the SO 2data.



## 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
SO 2 removal Inlet SO 2 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 reagentpreparation 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. SO 2 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 1 st stage and below the 2 ndstage of mist eliminators (ME). The 2 nd stage ME overspray is provided with a washheader, 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 SO 2loading. 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 SO 2 removal on the system was seen, but the full effect was not observed. The removal increased from 83% to about89%. The main reason was continued sulfite blinding. It was expected that the delivered oxidation air was adequate for the increase of SO 2 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 becleaned before upsetting boiler operations because of high differential pressure drop. In 2005, a few more modifications were made to the system forsystem 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 improveoxidation and stop sulfite blinding. The combination of these improvements allowed the FGD system to reach its full performance capacity. SO 2 removals can now reach as high as 98%.



## SO 2 

## absorption theory

Scrubber design and SO 2 

### 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 SO 2 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 SO 2 . This leaves oneprimary 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 SO 2removal 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 SO 2 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 flowuniformly 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 successivepressure 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 SO 2 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 SO 2 removal ef ficiency. Contacting effectiveness The tray provides a much more efficient means of gas and slurry contact than slurry sprays. Contacting devices are well known toprovide 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 SO 2 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 SO 2 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 SO 2 fractional efficiency: 

## ) 1ln( efficiency fractional NTU −−=
Chemistry, alkalinity and SO 2 

### absorption In addition to gas and slurry contacting, sufficient alkalinity has to be provided to neutralize the acid formed when SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2removal 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 beabout 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 SO 2 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 SO 2 removal with and without tray.

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

SO 2 Removal Inlet SO 2 Inlet SO 2 pH Stoichiometry L/G Absorber ∆ P Gas Velocity Table 3 Summary of SO 2 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

H 2 SO 4 (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

SO 2 Removal Inlet SO 2 Inlet SO 2 pH Stoichiometry L/G Absorber ∆ P Gas Velocity Table 4 Summary of Maximum SO 2 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 SO 2 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 SO 2 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 SO 2 per 1000 gallons of slurry. The SO 2absorption with 2 trays at MSCPA is about 5.0. 

## Test program and results Multiple field performance tests for SO 2 , 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. SO 2data was collected by U.S. EPA Method 6C. SO 2data collection was also taken and compared with the plant CEMS. Emission testing for SO 3 , HCl, HF, F and solid particulate was performed during November 2005. This data was taken to gathersome baseline performance of how the absorber module could remove these multi-pollutants.



### SO 2 

### 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 SO 2concentrations 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 isattributed 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, SO 2 removal increased from 83% to 89%. But, the system was still limited by low limestone slurry feed densities and some sulfiteblinding. 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 SO 2removal to 95%. Additional data was taken during the 2005 dual tray tests to maximize the SO 2 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 SO 2removal as high as 98%. These tests were performed to determine the maximum SO 2 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 SO 2removal across a conventional absorber module.
• SO 2removal was increased from 90% to a maximum of 98% at the high pH case. • At normal conditions, the plant typically operates at 95% SO 2removal. • The plant can stay in compliance, for SO 2 , 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 All rights reserved.

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