Fayette Power Project Unit 3 FGD Upgrade:

Design and Performance for More CostEffective SO2 Reduction

Technical Paper

BR-1845

Authors:

C. Frazer

Lower Colorado River Authority

Austin, Texas, U.S.A.

A. Jayaprakash

S. M. Katzberger

Sargent & Lundy, L.L.C.

Chicago, Illinois, U.S.A.

Y. J. Lee

B. R. Tielsch

Babcock & Wilcox

Power Generation Group, Inc.

Barberton, Ohio, U.S.A.

Presented to:

EPRI Power Plant Air Pollutant 

Control Mega Symposium

Date:

August 30 - Sept. 2, 2010

Location:

Baltimore, Maryland, U.S.A.
Babcock & Wilcox Power Generation Group 1

Fayette Power Project Unit 3 FGD Upgrade: Design and Performance 

for More Cost-Effective SO2 Reduction

A. Jayaprakash

S. M. Katzberger

Sargent & Lundy, L.L.C.

Chicago, Illinois, U.S.A.

BR-1845

Introduction

Lower Colorado River Authority’s (LCRA) Fayette 

Power Project – Unit 3 (FPP3), located near La Grange, 

Texas, was completed in 1988. The original wet flue gas 

desulfurization (WFGD) system design was to reduce sulfur 

dioxide (SO2) by approximately 90% across the absorbers, 

while burning high-sulfur Texas lignite and bypassing up 

to 20% of the flue gas. In the future, the station will require 

95.5% SO2 capture without flue gas bypass, while firing 1% 

sulfur Powder River Basin (PRB) coal. Sargent & Lundy, 

L.L.C. (S&L) performed an FGD upgrade study that identified a concept for achieving these goals. S&L subsequently 

prepared a specification to obtain bids for performing the 

upgrade work on a supply and erect basis. BE&K, and their 

subcontractor Babcock & Wilcox Power Generation Group, 

Inc. (B&W PGG) were selected as the supplier for these 

modifications, which included new spray headers, the addition of trays, turning vanes, and a new mist eliminator (ME) 

system. Non-proprietary details of the design modifications 

as well as actual performance data comparing the original 

installation and the modified installation are presented in 

this paper.

Overview of Fayette Power Project – Unit 3

LCRA Fayette Station is located near La Grange, Texas, 

and consists of three pulverized coal-fired units that burn 

PRB sub-bituminous coal. Unit 3 is a nominal 470 MW 

tangentially fired unit, which was designed to burn highsulfur Texas lignite, but is currently firing 1.0 lb SO2/

MBtu sub-bituminous coal. The boiler was manufactured 

by Combustion Engineering (Alstom). The flue gas passes 

through a pair of regenerative Ljungstrom air preheaters, 

before passing through a cold-side electrostatic precipitator 

(ESP) and then approximately 95 to 99% of the flue gas is 

treated in a WFGD system. The treated flue gas is mixed 

with bypassed flue gas and then emitted from the station 

through a dry chimney.

Original air quality control system (AQCS) 

technology

The FGD system was originally designed as a wet limestone, forced oxidation system by Combustion Engineering, and consists of a 3x50% absorber arrangement. Each 

absorber is 38 ft x 36.5 ft in the spray zone with expansion of 

the absorber to 40 ft x 41.5 ft as the flue gas passes through 

the ME zone. Each absorber was fabricated of 317 LMN 

stainless steel, including the ladder vanes located at the inlet 

of each absorber. The reaction tank for each absorber is not 

integrated to the spray zone and slurry is funneled through 

the base of the absorber into the separate reaction tank.

In the spray section of each absorber, the original design 

included five spray levels, each with 42 spray nozzles spaced 

evenly across the absorber. At the time the project began, 

only Absorber A still had all five spray levels. Absorbers B 

and C had the lowest spray header previously removed. The 

lowest spray header in Absorber A was removed during this 

project. The headers were supported from beams across the 

absorber using simple rod hangers, which have frequently 

failed in the past. This led to a number of instances where 

one of the spray headers inside the absorber collapsed due to 

a broken hanger rod, resulting in a lack of support along the 

span of the header. Additionally, some of the spray nozzles 

have broken off in the past, leading to a maldistribution of 

Presented to:

EPRI Mega Symposium 2010

August 30 - Sept. 2, 2010

Baltimore, Maryland, U.S.A. 

Y. J. Lee

B. R. Tielsch

Babcock & Wilcox 

Power Generation Group, Inc.

Barberton, Ohio, U.S.A.

C. Frazer

Lower Colorado River Authority

Austin, Texas, U.S.A.
2 Babcock & Wilcox Power Generation Group

slurry across the absorber as well as a loss of atomization 

of the slurry across the affected spray header, due to the 

significant decrease in pressure drop across that section of 

the header.

The original ME system consisted of three ME levels 

and a retractable, lance-style ME wash system. The MEs 

consisted of a flat level of chevron blades, known as the 

bulk entrainment separator, and two “tepee” style levels. 

The MEs were washed by the lance-style wash system that 

was mechanically inserted in and out of the absorbers. The 

MEs were washed with 100% reclaim water. Even though 

this system kept them clean, the MEs were no longer supported by the original equipment manufacturer (OEM) and 

the lance-style wash system had come to require increasingly 

higher maintenance.

Flue gas flow through the spray zone, with two absorbers in service, at full load was originally designed for 12.1 

ft/s, based on firing lignite. Subsequent to the PRB coal 

conversion, the velocity of the flue gas through the spray 

zone dropped to 9.71 ft/s.

Original design conditions

Fuels

The WFGD system was originally designed to treat flue 

gas generated from the firing of 10 lb SO2/MBtu lignite. 

After the design of the absorbers was completed, it was decided to burn a sub-bituminous fuel instead of Texas lignite. 

As a result, the absorbers and all ancillary equipment are 

significantly oversized for current operating conditions. For 

example, while typical recycle tank solids residence time 

for a new WFGD system is approximately 16-24 hours, the 

solids residence time at FPP3 is approximately seven days.

SO2 removal efficiency

Prior to the upgrade, the FPP3 AQCS was capturing 85 

to 88% of the SO2 present in the flue gas that passed through 

the absorber. This treated flue gas was then blended with the 

WFGD (1 to 5%) bypass gas to maintain a dry stack. As a 

result, the overall efficiency of the WFGD system, from 

WFGD inlet to stack outlet, was operating at 81 to 84%, as 

shown in Table 1.

Performance prior to upgrade

Considering the current firing of low-sulfur, sub-bituminous coal, the SO2 removal capability has been adequate 

to meet current emission limits. However, there was reason 

to improve the performance of the scrubber in anticipation 

of future emission limits set by the plant-wide flexible air 

permit that will go into effect in 2012. Coupled with the 

upgrade driven by the flexible air permit requirements, there 

was also an opportunity to improve the cost effectiveness 

of the upgrade by purchasing lower-cost higher-sulfur coal 

and by selling excess SO2 credits that would result from the 

upgrade. Additionally, the spray headers and ME systems 

were approaching end-of-life and were either obsolete, or 

not supported by the OEM.

Bypass to maintain dry stack

Originally, to maintain a dry stack, a portion of the flue 

gas was bypassed around the WFGD to keep the temperature 

of the bulk flue gas above the gas saturation temperature. 

Current operation bypasses approximately 1 to 5% of the 

flue gas around the WFGD system. Dampers are present in 

the bypass duct to control the amount of flue gas bypassed 

based upon temperature measurements in the stack. Once 

the stack is upgraded for wet operation, LCRA will have the 

option to operate with a closed flue gas bypass.

Goals of the upgrade project

Based on regulatory requirements and on the experiences 

of the station with operating the WFGD system on FPP3, 

as detailed above, the goals of this project were to improve:

• SO2 removal efficiency across each absorber to meet a 

minimum of 95.5%, with zero bypass.

• FGD system reliability to reduce maintenance costs.

Preliminary engineering

Upgrade study

In 2006, S&L was tasked with assisting LCRA to accomplish the goals set forth above to improve FPP3 FGD 

overall performance. In doing so, S&L prepared a study to 

address the two goals. The results from that study are summarized below.

Upgrade performance

A number of options were investigated to determine 

the best potential performance upgrade choice for FPP3. 

Quotes were solicited from FGD OEMs to provide accurate assessments of the expected costs associated with wall 

baffles, trays, DBA injection systems, replacement spray 

nozzles to improve coverage in the absorber, and conversion 

to scrubbing 100% of the flue gas. A cost-benefit analysis 

was performed for each option and several combinations 

thereof to determine which solution was the most cost effective for FPP3. Using capital and O&M cost estimates for 

each upgrade option as well as an LCRA-prescribed index 

Table 1 

Progression of SO2 Removal Efficiency

Design Original Design Original 

Operation

Post-Upgrade 

Operation

Fuel

Texas Lignite

(10 lb SO2/

MBtu)

PRB Coal

(1 lb SO2/MBtu)

PRB Coal

(2 lb SO2/

MBtu) Tested

Bypass 20% 1-5% 0%

Overall 

SO2 removal 72% 81-84% 95.5%
Babcock & Wilcox Power Generation Group 3

for the expected sale price for SO2 credits and the cost of 

higher-sulfur coal, the overall SO2 removal efficiency and 

cost effectiveness of each of the upgrade technologies were 

evaluated over the life of the project.

The results of the study indicated that the most costeffective solution for FPP3 was the installation of one tray 

in each absorber, increasing the number of spray nozzles per 

spray level, replacing the original turning vanes (which had 

corroded and been removed), and converting the chimney 

for wet operation.

Upgrade reliability

A number of options were investigated to determine the 

best potential reliability upgrade choice for FPP3. Quotes 

were solicited from FGD OEMs to provide accurate assessments of the expected costs associated with self-supporting 

spray headers, new MEs and ME wash systems, and lining 

the floors and walls of the reaction tanks with Stebbins tile. 

A cost-benefit analysis was performed for each option and 

several combinations thereof to determine which solution 

was the most cost effective for FPP3.

The results of the reliability upgrade study indicated that 

the most cost-effective upgrades for FPP3 were self-supporting spray headers and new MEs and ME wash systems.

Two versus three absorbers/no FGD bypass

The FGD system was originally designed for two absorbers in operation, with the remaining absorber serving 

as a spare. Periodically, one absorber would be taken out of 

service and the spare absorber would be returned to service. 

The absorber off line would be maintained and then cycled 

back into service. Additionally, as stated above, the chimney 

was designed to operate dry. To achieve this, the FGD design 

incorporated a bypass, which is approximately 5% of the 

flue gas for typical operation. When considering the options 

to upgrade both the performance and the reliability of the 

WFGD absorbers, operation of the absorbers in a 2x50% arrangement and elimination of the FGD bypass were considered. Ultimately, the options selected, and discussed above, 

offer the station the flexibility to permanently remove one of 

the absorbers from regular service and provide the option to 

stop the FGD bypass. Outside of the addition of a tray and 

turning vanes to each absorber, only two of the absorbers 

needed to be fully upgraded, thereby saving capital cost for 

the project. The addition of a tray and turning vanes to the 

third absorber is to maintain equal pressure drop and flow 

balance if the third absorber is used as an emergency backup.

Computational fluid dynamic (CFD) modeling 

results

S&L was also tasked during the study phase to determine 

if there was potential for improvement in the flue gas flow 

path to reduce pressure drop throughout the system. Using 

the ANSYS CFX suite of software, the FGD system for 

FPP3 was modeled from the inlet manifold of the absorbers 

through the outlet manifold into the chimney. This included 

CFD modeling of the bypass duct and the absorbers, as well 

as the spray zones.

The inlet manifold modeling was conducted to determine 

if pressure drop to the system could be reduced, while also 

maintaining a 50:50 ratio of flows to the two active absorbers in all three potential operating configurations. The base 

model with no modifications to the inlet manifold showed 

the flow splits between the two active absorber inlets, for 

all operating scenarios, to be within ±5% of each other. The 

model indicated that the existing design of the inlet ducts 

was adequate from a flow distribution standpoint. While 

vanes added in the inlet manifold could reduce pressure drop 

through the system, they could also alter the flow split to 

each FGD absorber. It was determined that no vanes were 

needed in the inlet manifold duct.

Each absorber was also modeled to determine any potential vaning that could be applied to the unit to reduce pressure drop and improve performance by improving gas flow 

distribution. Based on the results from the inlet manifold 

modeling, it was assumed that the gas flow to each absorber 

was the same for modeling purposes. Each absorber was 

designed to have certain flow improvement devices. For 

instance, at the end of the inlet duct, the rain hood, which 

prevents “short-circuiting” of gas along the near wall and 

forces the gas into the bulk of the limestone slurry spray, 

was modeled. Additionally, new and modified ladder vanes 

were modeled to prevent the flue gas from having an impact 

on the far wall of the absorber. The modeling results suggested vanes could be added to the absorber to improve the 

gas flow inside the absorber. These would include an angled 

vane in the inlet duct to each absorber to force a portion of 

the flue gas entering from the bottom of the duct to the top, 

and an extension to the existing ladder vanes to further direct 

flow to the center of the absorber, where the concentration 

of slurry spray is the highest. However, since a tray (which 

inherently provides good gas/liquid distribution) was part of 

the recommended option for improving overall SO2 removal 

efficiency, it was determined that the benefit associated with 

these vanes was not required.

The outlet of each absorber was also modeled to determine any potential vaning that could be applied to the unit 

to reduce pressure drop and improve performance by improving gas flow distribution. OEM drawings of the outlet 

elbow show that the absorbers were designed to have turning 

vanes in this location. Discussion with LCRA personnel 

indicated that these turning vanes had corroded over time 

and had previously been removed from service. These vanes 

were modeled to determine any benefit provided and it was 

determined that these vanes should be reinstalled using a 

material suitable for the wet environment.

Lastly, the outlet manifold duct connecting the bypass 

duct and the outlet ducts from all three absorbers with the 

chimney was modeled. OEM drawings of the outlet ducts 

show that the ducts were designed to have turning vanes in 

this location. Discussion with LCRA personnel indicated 
4 Babcock & Wilcox Power Generation Group

that these turning vanes had also corroded over time and 

been removed from service. Flow was modeled to reduce 

pressure drop and to allow for no temperature maldistributions due to improper mixing. Cases were modeled based 

both on continued operation of the dry stack due to bypass 

of flue gas and on scrubbing of 100% of the flue gas. The 

results of this modeling showed that by installing turning 

vanes near the chimney-side wall of each absorber outlet, 

the pressure drop could be significantly reduced.

Implementation phase

To support the FGD upgrades determined during the study 

phase, a specification was written to solicit competitive bids 

for the work. The specification encompassed the scope of 

work for the engineering, procurement and construction 

of all the specified upgrades. These included installation 

of a tray in each of the three absorbers, replacement of the 

existing spray header/spray nozzle system, replacement of 

the MEs and ME wash system in two of the absorbers, and 

installation of the turning vanes based on the results of the 

CFD modeling performed by S&L. A tray and turning vanes 

were installed in the third absorber so that the pressure drop 

across any two of the operating absorbers in service would 

be equal. The other upgrades were installed only in two 

absorbers to reduce capital cost. Performance guarantees 

were required for a number of parameters, but in particular, 

focused on SO2 removal and absorber pressure drop increase. 

The required performance guarantees for burning 2 lb/MBtu 

SO2 coal at full load with three spray headers operating and 

no bypass are summarized in Table 2.

Based on the review of the competitive bids received 

in response to the specification, BE&K (with B&W PGG 

as its engineer subcontractor) was selected to perform the 

upgrades to the FPP3 FGD system.

Tray design and implementation

Each of the three absorber modules was retrofitted with 

a single tray (Figure 1). As flue gas passes through the absorber, it is quenched by absorber slurry falling from sprays 

as it passes through the perforated absorber tray. The tray 

Table 2 

Required Performance Guarantees

Guarantee Guarantee Value

SO2 removal efficiency 95.5

Increase in absorber pressure drop ≤2.0 in. W.C.

ME carryover 0.0004 gpm/ft2

Limestone consumption rate 16,000 lb/hr

ME wash water consumption 342 gpm

Particulate emission 0.030 lb/MBtu

Fig. 1 Tray sections with hold-down plates.

Fig. 2 Access door to tray level.

Fig. 3 Spray headers, supports and spray nozzles.
Babcock & Wilcox Power Generation Group 5

supports and tray were constructed of alloy 2205 and the 

tray was sectioned into compartments by baffles. The baffles 

in the tray assist in the even distribution of limestone slurry 

on top of the tray, which provides an area of close contact 

between the flue gas and the active reagent. The tray supports also serve as an excellent platform for inspection and 

maintenance (provided proper planking is used on top of the 

baffles) of the slurry spray headers and nozzles, which will 

aid in future O&M of the absorber.

At each tray level, an access door and platform were 

provided (Figure 2). The new platforms are accessible from 

existing platforms for each of the three absorbers.

Spray headers/spray nozzles design and 

implementation

Absorber modules A and C were retrofitted with new 

spray headers and spray nozzles (Figure 3). The existing 

absorber recirculation pumps (three operating and one spare) 

and piping were reused to supply the absorber spray headers 

with slurry from the absorber reaction tank.

The six new headers per spray level were constructed 

of alloy 2205. The spray nozzles are hollow cone, nitridebonded, silicon carbide and are designed to provide uniform 

spray coverage over the entire cross-sectional area of the 

tower. For comparison, the spray coverage before and after 

the FGD upgrades is shown in Figure 4. Before the upgrade, 

it is clear that a significant portion of the cross-section, either 

inside the absorber or along the wall, was not covered by 

the spray circles. After the upgrade, the spray pattern shows 

a minimum of 200% coverage, except for a small portion 

of the perimeter section. The overlapped upgraded spray 

coverage greatly reduces flue gas escape and effectively 

increases liquid-gas contact.

ME design and implementation

Absorber modules A and C were retrofitted with new ME 

wash systems (Figure 5). Each module was equipped with 

two stages of MEs, which remove carryover mist by inertial contact. The primary stage captures large particles and 

the secondary stage captures wash water droplets and finer 

particles. The two-stage ME is kept free of slurry deposits 

by a new stationary water wash system. ME wash water is 

directed to the upstream face for washing the primary stage 

ME using an array of spray headers and spray nozzles. The 

top surface of the primary stage and the bottom surface of the 

secondary stage MEs are also washed with ME wash water. 

A 50/50 mixture of fresh water and reclaim water is used 

for ME wash due to tight water balance and zero discharge 

requirements at the facility.

The MEs were designed to be washed sequentially by section to optimize the wash flow rate. The primary underspray 

and the primary overspray/secondary underspray levels are 

each divided into four sections. The primary overspray and 

Fig. 4 Spray coverage of slurry nozzles – before and after upgrades.

Fig. 5 Mist eliminator design – original and upgraded.

Absorber Spray Pattern – Original Absorber Spray Pattern – Upgrade
6 Babcock & Wilcox Power Generation Group

secondary underspray levels are washed simultaneously 

using the existing ME wash pumps.

The ME blades are constructed of FRP. The ME wash 

spray headers and wash nozzles are constructed of alloy 

2205.

Turning vanes design and implementation

Three turning vanes were installed in each tower outlet 

duct in the 90-degree turn toward the plenum (Figure 6). 

Each tower also received a turning vane at the connection 

to the common outlet plenum. The turning vanes are constructed of AL6XN® steel alloy.

The purpose of the turning vanes is to evenly distribute 

flow into the common outlet plenum and reduce pressure 

drop.

Performance testing results

Upon completion of the implementation phase of the 

upgrades, the FGD system was tested between January 

26-28, 2010, to determine the performance of the system 

and compare the results with B&W PGG’s guarantees. 

In particular, two criteria of paramount importance were 

tested: SO2 removal efficiency and absorber pressure drop. 

Additionally, the reliability of the system was monitored to 

determine if one of the absorbers could be removed from 

future operation. The results from that performance testing 

are discussed below.

SO2 removal efficiency

Three tests by a third-party independent testing company 

were taken over the course of three days. For the tests, the 

boiler burned 2 lb SO2/MBtu sub-bituminous coal. The FGD 

modules received 100% of the flue gas flow and three spray 

headers were operating. Measurements of SO2 concentrations were taken at specified sampling locations in the inlet 

and outlet ducts of Absorbers A and C. These measurements 

were then adjusted in accordance with 40CFR60, Appendix 

A, Method 7E to a common basis of 7% O2 in the flue gas. A 

summary of the results from the testing is shown in Table 3.

These raw results were then used to compute the overall 

removal efficiency of the upgraded FGD absorbers as summarized in Table 4.

When compared against the guaranteed SO2 removal 

efficiency of 95.5%, the performance testing showed compliance with the guaranteed value with significant margin.

Pressure drop

To determine the increase in pressure drop across the 

system due to the installation of the upgrades, a baseline 

test was run in April 2009, prior to the installation of the 

tray and the turning vanes. These data were then compared 

with the measured data taken during performance testing. 

The data collected in the baseline test are shown in Table 5.

During the performance testing performed in January 

2010, the static pressure at both the inlet and the outlet of 

each absorber was measured. The resulting pressure drop 

determined by the difference of these two values was then 

compared against flow-adjusted baseline data to determine 

the change in pressure drop across the absorber as a result 

of the FGD upgrade. A summary of the data collected is 

shown in Table 6.

Compliance with the guaranteed value was determined 

by comparing the measured pressure drop across each tested 

absorber with the expected pressure drop determined in 

Table 4 

SO2 Removal Efficiency

Run Absorber A Absorber C

1 99.6% 99.2%

2 99.3% 98.9%

3 99.3% 98.8%

Average 99.4% 99.0%

Site Average 99.2%

Table 5 

Baseline Absorber Pressure Drop Results

Run Load

(MW)

Volumetric Flow 

(scfm, wet)

Pressure Drop 

(in. W.C.)

1 469 679,451 4.06

2 399 803,717 3.47

3 352 598,942 3.15

* Due to abnormally high volumetric flow, Run 2 was omitted 

from calculations.

Table 3 

SO2 and O2 Emission Measurements

Inlet Duct Absorber A Outlet Duct Absorber C Outlet Duct

Run O2

% dry

SO2

ppm dry

SO2

ppmc *

O2

% dry

SO2

ppm dry

SO2

ppmc

O2

% dry

SO2

ppm dry

SO2

ppmc

1 6.28 709.8 674.8 6.49 2.7 2.6 6.72 5.6 5.5

2 6.33 769.7 734.3 6.48 5.3 5.1 6.69 8.4 8.2

3 6.44 765.5 735.9 6.59 5.3 5.1 6.76 8.7 8.6

* ppmc refers to parts per million corrected to a fixed O2 concentration of 7%.
Babcock & Wilcox Power Generation Group 7

the baseline testing. The baseline pressure drop was also 

adjusted to match the flow from the performance testing. 

The measured data and the expected pressure drop data 

were then compared by difference to establish compliance 

with the performance guarantee. These data are summarized 

in Table 7.

When compared against the maximum guaranteed 

absorber pressure drop increase of 2.0 in. W.C., the performance testing showed compliance with the guarantee and 

a marked improvement from the guaranteed value. Furthermore, the addition of the turning vanes in the outlet elbow 

and outlet manifold, the addition of the high-efficiency ME 

system, as well as the dampening effect of the tray pressure 

drop, seems to have improved any flow maldistributions to 

the point that the FGD upgrade work has reduced the overall 

pressure drop across each absorber when compared with the 

baseline testing.

Reliability

The performance testing for the modules was completed 

in late January, 2010. Prior to the FGD upgrade, one module 

was always in maintenance mode. Every six months, the 

absorber out of service for maintenance would be returned 

to service and another would be taken off line for service in 

accordance with the station’s maintenance schedule. Reasons 

for continuous maintenance, as detailed above, included 

broken spray nozzles and fallen spray headers. The intent 

of the upgrade was to improve the reliability of the absorbers to the point where LCRA could reliably expect the two 

upgraded absorbers to operate on a two-year cycle without 

going off line for forced maintenance issues.

To date, the unit has not experienced the maintenance 

problems that occurred in the past. LCRA is monitoring 

the availability of the absorbers with the goal of reducing the overall maintenance for the FPP3 FGD system by 

permanently removing one of the absorbers from service. 

However, this goal will require time to achieve, as the absorbers must show consistent availability in the next couple 

of maintenance cycles, as a minimum, before one can be 

permanently removed from service. Also, the modifications to the chimney liner to convert to wet operation must 

be completed before operating with the FGD bypass in the 

closed position.

Fig. 6 Outlet turning vanes.

Table 6 

Performance Measurement of Absorber Pressure Drop

Run A Inlet A Outlet Pressure Drop C Inlet C Outlet Pressure Drop

1 3.00 0.30 2.70 3.00 0.49 2.51

2 3.10 0.35 2.75 3.00 0.49 2.51

3 3.45 0.36 3.09 3.50 0.49 2.64

Average 3.18 0.34 2.74 3.17 0.49 2.68
8 Babcock & Wilcox Power Generation Group

Conclusions

The FPP3 FGD upgrade project was a tremendous success for LCRA, BE&K, B&W PGG, and S&L. The upgrades 

should enable this system to operate efficiently for many 

years. The improved SO2 removal efficiency will allow the 

unit to effectively meet the permit emission limits and offer 

the option for selling credits should that market return. The 

unit also has the option to burn lower-cost, high-sulfur coal, 

while still maintaining emissions limits. Additionally, with 

the upgrades aimed at improving the reliability of the FGD 

system, it is anticipated that overall maintenance associated 

with the FPP3 FGD system will be significantly reduced.

In the future, LCRA will convert the existing FPP3 dry 

stack to a wet stack, which will provide the option for the 

unit to operate without an FGD bypass.

Table 7 

Comparison of Measured Pressure Drop with 

Expected Pressure Drop

Performance Test 1 Module A Module C Total

Measured pressure drop 2.70 2.51 2.61

Expected pressure drop 4.19 2.94 3.62

Pressure increase -1.01

Performance Test 2 Module A Module C Total

Measured pressure drop 2.75 2.51 2.64

Expected pressure drop 4.30 2.41 3.48

Pressure increase -0.84

Performance Test 3 Module A Module C Total

Measured pressure drop 3.09 3.01 3.05

Expected pressure drop 4.22 2.64 3.52

Pressure increase -0.46

AL6XN is a trademark of Allegheny Ludlum Corporation.
Copyright © 2010 by Babcock & Wilcox Power Generation Group, Inc.

a Babcock & Wilcox company

All rights reserved.

No part of this work may be published, translated or reproduced in any form or by any means, or incorporated 

into any information retrieval system, without the written permission of the copyright holder. Permission requests should be addressed to: Marketing Communications, Babcock & Wilcox Power Generation Group, P.O. 

Box 351, Barberton, Ohio, U.S.A. 44203-0351. Or, contact us from our Web site at www.babcock.com.

Disclaimer

Although the information presented in this work is believed to be reliable, this work is published with the 

understanding that Babcock & Wilcox Power Generation Group, Inc. and the authors are supplying general 

information and are not attempting to render or provide engineering or professional services. Neither Babcock 

& Wilcox Power Generation Group, Inc. nor any of its employees make any warranty, guarantee, or representation, whether expressed or implied, with respect to the accuracy, completeness or usefulness of any information, product, process or apparatus discussed in this work; and neither Babcock & Wilcox Power Generation 

Group, Inc. nor any of its employees shall be liable for any losses or damages with respect to or resulting from 

the use of, or the inability to use, any information, product, process or apparatus discussed in this work.