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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

RESULTS OF FGD UPGRADE PROJECTS ON LOW-RANK COALS

Paul Farber, Bill Siegfriedt, Steve Katzberger 

Sargent & Lundy, L.L.C. 

Don Caverly Joseph G. Eutizi Tommy J. Slater

Tucson Electric Power San Miguel Electric Cooperative AEP/SWEPCO 

ABSTRACT

This paper describes the approaches used to successfully implement flue gas desulfurization 

(FGD) upgrade projects at three power generating stations. Specifically, the FGD projects 

consisted of: 

• Upgrades of the wet scrubber at American Electric Power/Southwestern Electric 

Power Company’s (AEP/SWEPCO) Pirkey Unit 1. 

• Upgrades of the wet scrubber at San Miguel Electric Cooperative, Inc.’s (SMEC) San 

Miguel Unit 1. 

• Increase of dry scrubber capacity at Tucson Electric Power’s (TEP) Springerville 

Units 1 and 2. 

Impetus for these upgrades was the following, either singly or in combination: 

• Tightening of emission regulations 

• Increase in SO2 emission allowance prices 

• Degradation of coal quality over time. 

• Need to reduce emissions to allow expansion 

• Desire for improved reliability 

The design alternatives and the challenges encountered on each of these projects, as well as their 

results, are presented below. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

INTRODUCTION

Over the last several years a combination of factors, including capacity increases, rise in SO2

allowance prices, and new legislation, such as the Clean Air Interstate Rule (CAIR), have driven 

utilities to upgrade existing FGD systems. Many of these FGD systems came on line in the earlyto mid-1980s and are typical of the first-generation technologies introduced after promulgation of 

the Clean Air Act Amendments of 1977. The first generation FGD technologies were typified by: 

• Multiple absorber modules (for either wet or dry FGD) 

• SO2 removal between 75% and 90% 

• Use of either natural or inhibited oxidation 

Consequently, system upgrades focus on increasing removal efficiency, balancing and optimizing 

parallel systems, and improving overall system availability through reduced maintenance 

problems. Many of the FGD systems being upgraded today serve boilers firing low-rank coals. 

While these FGD systems may have been designed to treat flue gas from a moderate-sulfur fuel, 

over the years the mines supplying these low-rank coals have gradually used fuels containing 

increasingly higher amounts of sulfur. Fuels higher in sulfur than the original design fuels 

complicate efforts to successfully achieve the goals of the upgrades. Table 1 lists the analyses of 

the coals being fired at the three generating stations covered in this paper. 

Table 1. Coal Used at Subject Generating Stations

Ultimate 

(% weight) 

Pirkey 

Unit 1 

San Miguel 

Unit 1 

Springerville 

Units 1 and 2 

Ash 15 to 38 26 to 29 18.10 

Moisture 25 to 36 27 to 31 15.00 

Carbon 23.6 to 24.4 52.19 

Hydrogen 2.6 3.91 

Oxygen 9.4 to 9.6 8.96 

Nitrogen 0.6 to 0.7 0.94 

Sulfur 0.4 to 2.5 2.0 rising to 2.5 0.88 

Chlorine 0.01 to 0.02 0.02 

Total 100 100 

HHV (Btu/lb) 4,900 to 7,700 5,400 9,154 

SO2 (lb/million Btu) 2.0 to 8.0 7.7 rising to 9.5 1.92 

Sargent & Lundy, L.L.C. (S&L) has been working with several utilities to upgrade both wet and 

dry FGD systems treating flue gas from low-rank coal combustion. All of these upgrades have 

been successful, having increased the overall SO2 removal efficiency as well as the system 

availability. The approach to any upgrade is, of course, site-specific, but variously includes the 

addition of scrubbing modules, elimination of bypass systems, improvement of gas-to-liquid mass 

transfer, and upgrades to ancillary subsystems. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

PIRKEY GENERATING STATION

Pirkey Unit 1 is a nominal 650-MW subcritical pulverized lignite-fired unit owned and operated 

by AEP/SWEPCO. The unit is located approximately 140 miles east of Dallas, near Hallsville, 

Texas. The plant, which was commissioned in 1985, currently burns medium-sulfur Texas lignite 

(Table 1). At the time of boiler commissioning, several emission control technologies were also 

installed, including low-NOX burners, a cold-side electrostatic precipitator (ESP), and a natural 

oxidation wet limestone FGD system. 

The FGD system supplied by UOP’s Air Correction Division included four 33%-capacity (one 

spare) double-loop absorber modules with a full-flow bypass duct and an ambient air, steamreheat system to maintain a dry stack (see Figure 1). The 525-foot-tall stack has an acid-resistant 

brick liner. Over time, modifications have been made to the FGD system operation, including: 

• An absorption tray was added to each absorber. 

• A dibasic acid feed (DBA) system was added. 

• Limestone grind size was reduced. 

• Dry stack operation was maintained by controlling the bypass damper to achieve an 

outlet SO2 concentration of 1.2 lbs SO2/mmBtu. 

The design basis inlet SO2 concentration is 5.0 lbs SO2/mmBtu, although the lignite varies from 

2-8 lbs SO2/mmBtu. The Pirkey FGD system is operated in the inhibited oxidation mode by the 

addition of emulsified sulfur to form sodium thiosulfate. 

In 2004, S&L was engaged to perform a study to identify the improvements that would be 

necessary to achieve the goal of 100% scrubbing of flue gas, and maximum achievable SO2

removal efficiency, with a wet stack. Physical modifications to the existing absorbers were 

investigated as a means to realize the goal of 100% scrubbing. However, the analysis determined 

that simply by increasing the feed rate of the existing DBA system, the existing absorbers would 

be capable of an SO2 collection efficiency of 95% without any physical changes. Previous testing 

at Pirkey sponsored by the U.S. Department of Energy showed that high SO2 removal was 

achievable. Changes to the slurry recycle pumps, piping, and spray nozzles were considered, but 

no cost-effective options were identified. Therefore, no physical changes were made to the 

absorbers to increase SO2 removal efficiency. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Figure 1. Pirkey Dual-Loop Absorber

All four of the existing absorbers (4 x 25%) were operated by the plant both before and after the 

upgrades. 

In order to achieve the goal of 100% scrubbing, S&L recommended: 

• Addition of a new double-louver bypass damper in the bypass duct to achieve 

isolation. 

• Modifications to the existing outlet ductwork and stack to tolerate the wet conditions. 

Additionally, in order to maintain the overall availability of the system, the following components 

were specified and procured: 

• A third reagent preparation train, including limestone day bin, silo, gravimetric 

feeder, ball mill, mill product tank, and hydrocyclones. 

• A new, zoned washing system for the mist eliminators. 

All of these improvements were implemented during the spring 2006 outage, with the exception 

of the ball mill installation, which occurred during summer 2006, with the unit on line. 

New Bypass Damper and Modifications to the Existing Outlet Ductwork 

The original bypass system included an opposed, six-blade, single-louver damper constructed of 

Incoloy 825. The damper was divided into two side by side sections, with independent operators 

for both sides. By manipulating the orientation of the blades, the station was able to control the 

amount of flue gas being bypassed around the absorbers. Due to the increase in the value of SO2

emission allowances, AEP decided to convert the system to zero bypass (100% scrubbing) to 

generate additional SO2 allowances. Because the existing damper no longer closed tight, a 

change in the bypass damper was required. S&L developed a design for two smaller two-blade, 

single-louver dampers in series that would only be opened to protect the absorbers during startup 

and shutdown. The new damper was designed for parallel-blade operation. Seal air is used to 

pressurize the space between the two dampers. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

This new design occupies approximately one-third the duct area of the original bypass design. 

Additionally, due to the reduced design area of the bypass duct, the ductwork downstream of the 

new dampers has been reduced in size as compared with the original ductwork. Figure 2 and 

Figure 3 show, respectively, the original and new arrangements. 

Figure 2. Original Bypass Damper Configuration 

Figure 3. New 1/3-Capacity Damper in Horizontal Arrangement 

Since the damper normally operates in the closed position, when the downstream duct was 

redesigned, a drainage system was also installed to collect any liquid dropout, including sulfuric 

acid, from the passing saturated gas stream exiting the FGD absorbers. 

The new system has been in use since installation during the 2006 spring outage. Since that time, 

the system has achieved zero bypass. The seal air system has also been operating without 

problems. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Modifications to the Stack 

The original stack was designed for dry operation and did not have a diameter large enough to 

meet Electric Power Research Institute (EPRI) flue gas velocity guidelines for wet stack 

operation (100% flue gas scrubbing). Because the acid-resistant brick liner is tapered from top to 

bottom, the velocity at the breeching level is lower than that specified by the EPRI guidelines, but 

the velocity at the exit exceeds the guidelines. AEP commissioned Alden Research Laboratory, 

Inc. (Alden) to conduct a study to model the operation of the existing stack with 100% scrubbing. 

Modifications to the outlet duct and stack were made in accordance with those recommended in 

the Alden study. These modifications included the addition of moisture collection devices to the 

stack for wet operation and the addition of a flow stabilizer in the chimney liner opposite the 

breeching duct. Drains were placed in the ductwork and the stack for water removal. The stack 

now operates wet with only minor water droplet discharge from the exit. Opacity monitoring was 

relocated from the chimney to the ducts exiting the ESPs upstream of the FGD system. 

Reagent Preparation Train 

In order to help maintain the availability of the FGD system and increase the capacity of the 

limestone preparation system to support the increased SO2 collection, a new reagent preparation 

train was desired. The original system included two ball mill trains, each originally sized to 

produce 16 tph of limestone slurry at a design grind size of 75% through 200-mesh. This 

production level has since been reduced to about 8 tph of limestone slurry per ball mill as a result 

of changing the design grind size to 90% through 325-mesh. 

The new ball mill train (shown on the left in Figure 4) was designed for 15 tph at 95% through 

325-mesh, effectively doubling the capacity of the limestone preparation system. Though the 

existing ball mills could meet the limestone slurry requirements while burning the design basis 

lignite at 5.0 lbs SO2/mmBtu, there was no extra capacity to allow for maintenance downtime. 

Also, the full potential range of lignite sulfur is between 2.0-8.0 lbs SO2/mmBtu. The addition of 

the third ball mill served to ensure availability of the station, which had been previously operating 

with two 50% ball mills that were over 20 years old. The new mill was installed in the summer 

of 2006, and has been operated on a startup/checkout basis. 

Figure 4. Pirkey Ball Mills
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Zoned Mist Eliminator Washing System 

The existing two-stage mist eliminator system is constructed of 317L stainless steel and equipped 

with a two-level washing system. The original design included washing of the underside of each 

stage. Plant personnel modified the second level of washing to spray the top of the first-stage 

mist eliminator rather than the bottom of the second stage. The original mist eliminator washing 

system was continuous, designed to use 1500 gpm of recycled water to wash the bottom of the 

first stage and the bottom of the second stage continuously (all four absorbers, at all times). 

The goals of altering the washing system scheme were to improve the overall cleanliness of the 

mist eliminator and to prevent the formation of scale deposits that reduce the availability of the 

FGD system. To that end, due to the alloy construction of the mist eliminator blades, no changes 

were made. The washing system was changed to a new design provided by Munters Corporation. 

This new design included washing both the top and the bottom of the first layer and the bottom of 

the second layer. A zoned washing logic was also installed through a programmable logic 

controller (PLC) system to control the water distribution. The new washing scheme sequences 

through a series of eight zones, covering the two stages in each absorber. This is done while the 

mist eliminators of two of the three remaining absorbers are continuously sprayed at a low rate to 

keep them wet and the fourth absorber has no water sprayed on its mist eliminator. 

Overall Improvements to FGD System 

The overall result of the improvements implemented for the Pirkey Unit 1 FGD system was 

achievement of the goal of 100% scrubbing of the flue gas, at the maximum efficiency possible. 

The FGD system operates regularly at 97% SO2 removal efficiency and consumes less SO2

emission allowances than its allocation. The system has had no outages as a result of the installed 

upgrades. 

SAN MIGUEL GENERATING STATION

SMEC is a power generating entity serving southern Texas. SMEC’s sole unit is the 440-MW 

mine-mouth San Miguel Unit 1. San Miguel was commissioned in 1982, with a Babcock & 

Wilcox (B&W) wet limestone FGD system designed for medium-sulfur lignite. Typical of the 

period, the unit featured 4 x 33% absorber modules, natural oxidation, thickeners for primary 

dewatering, and steam-heated fresh air reheat. As is common in B&W designs, the FGD system 

included venturi quenching and tray-type absorbers. The system was designed for 86% SO2

removal at a stoichiometric ratio of 1.20 (removed basis). Figure 5 is a photograph of the overall 

FGD system, with Module A shown in Figure 6. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Figure 5. San Miguel Unit 1 FGD System 

Figure 6. San Miguel Unit 1 FGD System – Module A 

During its years of operation, the San Miguel FGD system has evolved in many ways. A 

summary follows. 

Increased Duty Severity 

Over the years, the lignite has gradually increased in sulfur content, as shown in Table 2. Further, 

changing regulations and the opportunity to sell SO2 emission allowances have created a need to 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

reduce the SO2 emission rate. These conditions have led to the need to enhance system 

performance over the original design. 

Table 2. San Miguel’s Higher Sulfur Fuel – Lower Emission Requirements

Parameter 

Original 

Design 

2005 

Test 

2006 

Test 

Future 

Need 

Lignite properties: 

HHV, Btu/lb 5,000 5,428 5,627 5,042 

Sulfur content, % 1.67 2.08 2.71 2.50 

Uncontrolled SO2 emissions, lb SO2/mmBtu 6.68 (Note 1) 7.66 9.63 9.92 

Flue gas flow, million acfm 1.59 2.09 2.18 2.04 

Desired SO2 emission rate, lb SO2/mmBtu 1.2 0.62 0.38 0.30 

SO2 removal, % 82 (Note 2) 92 96 97 

Notes: 

1. Design for 8.6 lbs SO2/mmBtu (2.15% sulfur). 

2. Design for 86% (2.15% sulfur) 

Performance Evolution 

Prior to 2005, various upgrades were made over the years to help achieve the necessary 

performance level. These included: 

• Operation of all four modules (4 x 25%, rather than 4 x 33%). 

• Addition of DBA to enhance reactivity of the limestone. 

• Addition of sodium thiosulfate to inhibit oxidation, reducing scale potential. 

Design Drift 

Over time, the design of any system inherently undergoes planned, gradual changes, e.g., design 

defects are corrected, components and materials are replaced, etc. Inadvertent or unplanned 

process changes can also occur. The desire to improve San Miguel unit performance and 

minimize maintenance costs resulted in less than optimum FGD system operation in a variety of 

ways: 

• Due to foaming of the reaction tanks, the tank level was lowered, shortening reaction 

time. 

• Reaction tank pH setpoints drifted downward, resulting in excessive scale buildup in 

the sumps and tanks. 

• Flow orifices on recycle lines ceased operation. In some cases, the orifices were 

removed from the pipe, resulting in a significant flow increase on those pumps. 

• The double-louver bypass damper with seal air was reduced to a single-louver bypass 

damper with no seal air. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

• The module inlet double-louver damper with seal air (first damper with throttling 

capability) was modified on Modules A and D by changing the first damper to a 

guillotine-type. 

• A separate bleed line was added to the second thickener, resulting in velocities too 

low to prevent settlement. 

• A bleed line shortcut was installed at the thickener rim, resulting in short-circuiting 

of solids. 

Phase 1 Performance Enhancements 

In 2004, SMEC determined that the San Miguel Unit 1 FGD system was in need of further 

performance improvement. The major equipment suppliers recommended demolishing much of 

the existing system and replacement with major new components. Due to the significant costs 

associated with such a plan, SMEC pursued a more conservative approach to improve system 

performance. In early 2005, SMEC engaged S&L to examine the factors that were limiting the 

performance of the San Miguel FGD system and recommend upgrades. 

In May 2005, baseline testing of the unit was performed using S&L protocol and a third-party 

testing firm, METCO, out of Dallas, Texas. Additional tests were conducted to determine the 

system’s sensitivity to DBA concentration and its ability to operate effectively on only three 

modules. Based on this testing, S&L recommended a staged plan for implementation of upgrades 

to the FGD system. This would provide SMEC with several advantages: 

• Investment could be made in moderate increments. 

• Progressive review of upgrades before undertaking subsequent upgrades. 

• As performance goals are reached, remaining (higher-cost/benefit ratio) upgrade 

opportunities can be avoided. 

In response to S&L’s prioritized list of potential upgrades, SMEC commissioned S&L to design 

the following upgrades for installation during the 2006 spring outage: 

• Increase liquid-gas ratio, both on the quencher and the absorber. 

• Improve absorber spray nozzles to achieve finer spray. 

• Convert quencher from venturi to open spray to reduce induced draft (ID) fan power. 

The increased L/G was accomplished in three ways. The most significant improvement resulted 

from an investigation of the piping system. Originally, recycle slurry flow was measured using 

orifice plates. As would be expected, this system was abandoned due to the pluggage of the 

pressure ports. However, due to data irregularities and engineering expertise, S&L concluded 

that some of the orifice plates were still in place. The pump curves were found to be very flat, 

that is to say that simply removing the orifice plate would double the flow through the pump. 

During the outage, 50% of the pumps were found still pumping against an orifice plate, and so 

were removed. Quencher L/G was improved by using spray nozzles with lower ΔP than the 

venturi sprays and eliminating the slurry wall wash. 

The existing absorber spray nozzles were of a local design that was easy to build and maintain, 

but did little more than distribute the slurry to the trays. S&L identified an open spray nozzle that 

would require little maintenance, but with similar ΔP, would produce a fine spray cone. The 

effect was to create a third SO2 absorption layer in the absorber. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

The existing quencher was a venturi type, which is very effective at quenching the flue gas and 

forms an excellent barrier/mixer to prevent hot gas from reaching the rubber-lined walls of the 

sump and absorber. However, this mixing creates a 6 in. H2O pressure drop across the quencher. 

Because at times San Miguel Unit 1 was fan-limited, the quencher ΔP was considered a potential 

opportunity to improve the system. S&L researched other venturi quencher FGD units and found 

that at least two had been successfully converted to co-current open-spray towers. After further 

research of those conversions, S&L designed an open-spray quencher for SMEC. The design 

accommodated the constraint of the lower part of the venturi consisting of a hollow girder that 

supports the quencher/absorber sump, which hangs above the separate reaction tanks. The 

original and new quenchers are shown, respectively, in Figure 7 and Figure 8. The draft loss has 

been reduced by about 3 in. H2O. 

Figure 7. San Miguel Original Venturi Quencher

Figure 8. San Miguel New Open-Spray Quencher

The bypass dampers, originally double-louver type, have been operating as single-louver type for 

many years. During 2005-2006, SO2 emission allowances became sufficiently valuable that 

consuming allowances through leakage of the bypass dampers became unacceptable. A rebuild 

of the FGD outlet duct during the 2007 outage would eliminate the bypass connections entirely. 

In the interim, SMEC caulked the dampers closed to minimize leakage. 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

In addition to the performance-enhancing upgrades, a variety of corrective measures were 

implemented that eliminated the problems that had occurred inadvertently over years of design 

drift. 

Performance Results 

In August 2006, San Miguel Unit 1 was re-tested. The results showed that although the sulfur in 

the lignite was 20% higher than during the baseline testing, the average SO2 removal (module 

inlet to outlet) improved from 92% to 96%. The mass of SO2 removed increased by 24%. At the 

same time, limestone consumption decreased by 8%, as a result of the stoichiometric ratio 

improving by 26%. 

Overall, Stage I was successful. However, in 2015, the San Miguel FGD system will have to 

achieve 97% removal to stay within its Clean Air Interstate Rule (CAIR) allotment of SO2

emission allowances. 

During the September 2006 outage, an inspection of the FGD system revealed a new 

phenomenon - extensive pluggage of the lower tray in each absorber had occurred. There was an 

accumulation of a crystalline growth on the bottom of the tray. The causes of the growth were 

attributed to localized flow distribution and lack of available calcium. S&L developed a 

computer flow model of the FGD module and verified the flue gas maldistribution at the plate. 

Planned Upgrades 

SMEC is planning further upgrades during the scheduled 2007 and 2008 spring outages. These 

are: 

• Add flow straighteners to achieve uniform flow at the absorber trays (2008). 

• Balance flue gas flow, module to module (2007 and 2008). 

• Blank off the bypass (2007). 

• Institute monitoring and control of inhibited oxidation (2007). 

• Upgrade instrumentation to improve control, e.g., pH, SO2, and module ΔP (2007). 

SPRINGERVILLE GENERATING STATION

TEP’s Springerville Unit 1 commenced operation in 1985, with Unit 2 following in 1990 (on the 

right in Figure 9). These are replicate units, each with gross capacity of 425 MW and firing a 

New Mexico (Lee Ranch) sub-bituminous coal (analysis summarized in Table 1). Both units are 

equipped with Combustion Engineering (now Alstom Power) tangentially fired boilers and with 

Joy Manufacturing-Niro (now B&W) spray dryers with reverse air fabric filters (dry FGD 

system). 

The planned construction of the new Springerville Units 3 and 4 units (approximately equivalent 

in size to Units 1 and 2) required an offset in the emissions by reducing the NOX and SO2

emissions from Units 1 and 2. The original and revised emissions limits are noted in Table 3. 

Table 3. Springerville Units 1 and 2 Emission Rates 

Parameter Prior to Unit 3 Operation Post-Unit 3 Operation 

SO2, lb/mmBtu 0.69 0.24 

NOX, lb/mmBtu 0.45 0.20 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Figure 9. Springerville Generating Station

The dry FGD system for each unit comprises three spray dryer absorbers (SDA) with rotary 

atomizers and a reverse-air fabric filter. The Springerville Station receives high-calcium pebble 

lime via rail, and a pneumatic system transports the lime to a day bin located at each unit. 

Horizontal ball mill slakers convert the pebble lime to lime slurry, which is combined with a 

slurry of recycled material from the fabric filter just prior to being fed to the rotary atomizer. 

When the units were constructed, the dry FGD systems were built with a partial bypass for 

purposes of flue gas reheat. 

TEP, with S&L as Owner’s Engineer, implemented the following modifications to reduce NOX

and SO2 emissions: 

• Installation of low-NOX burners and overfire air (NOX). 

• Installation of a fourth spray dryer and elimination of the flue gas bypass (SO2). 

Based on an evaluation of proposals received, B&W was selected as the turnkey contractor for 

the FGD upgrade. 

To complete the upgrade, two infrastructure upgrades were necessary: 

• Relocation of the cooling tower water blowdown tank for each unit (cooling tower 

blowdown is used to make up the recycle slurry for the dry FGD system). 

• Installation of a new 10-ton/hour lime slaker to accommodate the increased lime 

usage. 
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Both upgrades were successfully completed and the gas path tie-ins coordinated with the 

scheduled unit outages. The new spray dryers were installed just outside the building housing the 

existing spray dryers (Figure 10 and Figure 11) with access to the new spray dryer penthouses at 

the existing SDA penthouse level. 

Figure 10. Springerville Unit 1 Spray Dryer 

The performance testing of the upgraded Springerville Unit 1 FGD system was done during 

April 29, 2005 through May 3, 2005, and consisted of tests at low-load (140 MW gross), 

medium-load (250 MW gross), and high-load (420 MW gross). 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

Figure 11. Springerville Unit 2 Spray Dryer Installation 

For the low-load testing, the entire flue gas flow was directed through the new spray dryer 

chamber (Module D). Consequently, approximately 33% of the total design flue gas flow rate 

was channeled through 25% of the total spray dryer capacity. 

During the medium-load testing, approximately 65% of the total design flue gas flow rate was 

directed through 50% of the operating spray dryer modules. 

In the high-load testing, the entire flue gas flow was sent through all four spray dryer modules. 

The purpose of the high-load testing was not only to confirm that the SO2 emission rate was in 

accordance with the contract between TEP and B&W, but also that the flue gas flows were 

properly balanced between modules. The full-load testing on May 2 also had the purpose of 

acquiring data on the lime slurry feed to the FGD system, pressure drop across the modules, and 

electrical power consumption by the new module to determine contract compliance with these 

values. 

The objective of the performance testing was to validate the guarantees provided by B&W in the 

contract with TEP. Flue gas flow and SO2 measurements were performed by a third-party testing 

company, METCO, out of Dallas, Texas. These measurements were taken at the inlets of each 

module’s central gas disperser (CGD) and roof gas disperser (RGD). Similar measurements were 

taken in the exit duct of each spray dryer module. Summaries of the Springerville Unit 1 test 

results are provided in Table 4 and Table 5. 

Flow measurements were taken in accordance with U.S. EPA Methods 1 and 2. SO2 and oxygen 

measurements were taken in accordance with U.S. EPA Methods 1, 6c, and 3a, respectively. All 

concentrations determined by METCO were source-gas-sampled, with the moisture removed, and 

therefore measured on a dry basis. The design coal for the upgrade project had a calculated SO2

emission of 2.6 lbs SO2/mmBtu. The SO2 emissions from the coal being fired at Springerville 
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Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

during the performance tests were lower than would have been measured if the design coal had 

been available. TEP expressed concern that if a coal with an SO2 content equal to the design coal 

is fired in the boilers at the Springerville, there might be difficulty in achieving an emissions rate 

of 0.24 lbs SO2/mmBtu. Consequently, TEP requested that the testing demonstrate the capability 

of the system to achieve a minimum of 91% SO2 removal (the removal required to meet the 

required emissions rate while firing the design coal) during the full-load tests. The results of the 

testing demonstrated that indeed the system was capable of achieving the desired 91% removal 

requested by TEP. 

Table 4. Springerville Unit 1 SO2 Removal 

Run 

SO2 Inlet 

(lb/mmBtu) 

SO2 Outlet 

(lb/mmBtu) 

Percent 

Removal 

Low-load 1.870 0.206 89 

Medium-load 1.887 0.196 89.6 

High-load, May 5, 2005 (Note 1) 2.086 0.113 94.6 

High-load, May 3, 2005 (Note 1) 1.792 0.145 91.9 

Note: 

1. Based on inlet SO2 measurements taken by METCO. SO2 emission rates achieved during the high-load tests are not 

indicative of long-term operation, but are reflective of a new, well-tuned dry FGD system. During long-term operation, it is 

expected that an emission rate of 0.24 lb SO2/mmBtu will be achieved in normal operation. 

Similar to the concentration measurements, the flow measurements at the inlets to the spray dryer 

modules were analyzed. It was determined that the distribution, calculated from the measured 

inlet flows to the modules, was balanced to within approximately 5% of the average module gas 

flow. Consequently, based on the flow and emissions measurements, TEP and S&L concluded 

that the upgrade of the FGD system at Springerville Unit 1 had met all of its requirements. 

Table 5. Springerville Unit 1 Flow Distribution (Note 1)

Run Module A Module B Module C Module D 

Medium-load -- 45% -- 55% 

High-load 24.3% 23.3% 26.3% 26.1% 

Note: 

1. Distribution percentages are based on total flow to the module at the time of the test. 

The performance testing of the upgraded Springerville Unit 2 FGD system was done during 

June 9 through June 10, 2005, and consisted of tests at high-load (420 MW gross). Similar to the 

Unit 1 testing, the purpose of the high-load testing was not only to confirm that the SO2 emission 

rate was in accordance with the contract between TEP and B&W, but also that the flue gas flows 

were properly balanced between modules. 

Due to operating problems on June 9, SDA Module A was isolated and the entire flue gas flow 

was directed through Modules B, C, and the new SDA Module D. On June 10, Module A was 

returned to service and a series of gas flow measurements performed to determine flue gas 

distribution. Consequently, and with B&W’s concurrence, the official performance test for 

Unit 2, with regard to SO2 removal and lime consumption, was performed on June 9. As 

indicated in Table 6, the system achieved emissions well below the 0.24 lb SO2/mmBtu permit 

value and nearly achieved the 91% removal efficiency attained by Unit 1 during its performance 

testing. Since, during the SO2 removal tests, Springerville Unit 2 was operating at 100% MCR 
Page 17 of 17 

Presented at Electric Power 2007, May 1-3, 2007. SL406-208. Copyright 2007. 

with all of the flue gas being sent through 75% of the modules, it was concluded that this 

demonstrated satisfactory operation of the upgraded FGD system. The testing on June 10 was 

used to determine the flue gas distribution within the four Unit 2 SDA modules. Both in the 

three-module and four-module cases, the flow distribution was within 3.5% of the average gas 

flow through each module.

Table 6. Springerville Unit 2 SO2 Removal 

Inlet Measurement SO2 Inlet (lb/mmBtu) SO2 Outlet (lb/mmBtu) Percent Removal 

SO2 inlet monitor 1.90 0.195 89.7 

Coal analysis 2.105 0.195 90.7 

Table 7. Springerville Unit 2 Flow Distribution (Note 1)

Run Module A Module B Module C Module D 

June 9, 2005 Offline 32% 32% 36% 

June 10, 2005 28.4% 23.9% 22.1% 25.6% 

Note: 

1. Distribution percentages are based on total flow to the module at the time of the test. 

CONCLUSIONS

Many of the FGD systems installed in the 1980s were designed for SO2 collection efficiencies of 

between 75% and 90% to meet the then current emission limits (typically 1.2 lbs SO2/mmBtu). 

Upgrading these FGD systems to achieve 90% or more SO2 removal presents an opportunity to 

generate SO2 allowances for sale or to offset the emissions of new units. Upgrades to the existing 

equipment of that vintage, i.e., 20 years old, also is typically required to restore the original 

design function, improve operability and maintainability and ensure unit availability. 

The three FGD upgrade projects described in this paper posed unique requirements and 

challenges, and all were successfully upgraded to meet the Owners’ needs.