Page 1 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. 

## R ESULTS OF 

## FGD U PGRADE 

## P ROJECTS ON 

## L OW 

## -R ANK 

## C OALS
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



## A BSTRACT This paper describes the approaches used to su ccessfully 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 Tucs on 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 SO 2 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 encount ered on each of these projects, as well as their results, are presented below.Page 2 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. 

## I NTRODUCTION Over the last several years a combination of factors, including capacity increases, rise in SO 2 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-genera tion technologies introduced after promulgation of the Clean Air Act Amendments of 1977. The fi rst generation FGD technologies were typified by:

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

• SO 2 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 co als 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 genera ting stations covered in this paper.
Table 1. Coal Used at Su bject 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
SO 2 (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 work ing 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 SO 2 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.Page 3 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. 

## P IRKEY 

## G ENERATING 

## S TATION Pirkey Unit 1 is a nominal 650-MW subcritical pulverized lignite-fired unit owned and operated by AEP/SWEPCO. The unit is located approximate ly 140 miles east of Dallas, near Hallsville, Texas. The plant, which was commissioned in 1 985, currently burns medium-sulfur Texas lignite (Table 1). At the time of boiler commissioning, several emission control technologies were also installed, including low-NO X 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 c ontrolling the bypass damper to achieve an outlet SO 2 concentration of 1.2 lbs SO 2 /mmBtu. The design basis inlet SO 2 concentration is 5.0 lbs SO 2 /mmBtu, although the lignite varies from 2-8 lbs SO 2 /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 SO 2 removal efficiency, with a wet stack. Physical modifications to the existing absorbers were investigated as a means to realize the goal of 10 0% 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 SO 2 collection efficiency of 95% without any physical changes. Previous testing at Pirkey sponsored by the U.S. Department of Energy showed that high SO 2 removal was achievable. Changes to the slurry recycle pumps , piping, and spray nozzles were considered, but no cost-effective options were identified. Ther efore, no physical changes were made to the absorbers to increase SO 2 removal efficiency.Page 4 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 av ailability of the system, the following components were specified and procured:

• A third reagent preparation train, incl uding 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 durin g 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 si de 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 absorb ers. Due to the increase in the value of SO 2 emission allowances, AEP decide d to convert the system to zero bypass (100% scrubbing) to generate additional SO 2 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 pa rallel-blade operation. Seal air is used to pressurize the space between the two dampers.Page 5 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 compar ed 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 Damp er in Horizontal Arrangement

Since the damper normally operates in the cl osed 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.Page 6 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 (EPR I) flue gas velocity guidelines for wet stack operation (100% flue gas scrubbing). Because the ac id-resistant brick liner is tapered from top to bottom, the velocity at the breeching level is lowe r 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 th e addition of moisture collection devices to the stack for wet operation and the addition of a fl ow stabilizer in the chimney liner opposite the breeching duct. Drains were placed in the ductwor k and the stack for water removal. The stack now operates wet with only minor water droplet di scharge from the exit. Opacity monitoring was relocated from the chimney to the ducts ex iting 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 SO 2 collection, a new reagent preparation train was desired. The original system include d 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 t ph 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 slur ry requirements while burning the design basis lignite at 5.0 lbs SO 2 /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 SO 2 /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 ol d. The new mill was installed in the summer of 2006, and has been operated on a startup/checkout basis. Figure 4. Pirkey Ball MillsPage 7 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 sec ond 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 con tinuously (all four absorbers, at all times). The goals of altering the washing system schem e 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 cons truction 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 ab sorbers are continuously sprayed at a low rate to keep them wet and the fourth absorber h as 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% SO 2 removal efficiency and consumes less SO 2 emission allowances than its allocation. The syst em has had no outages as a result of the installed upgrades. 

## S AN 

## M IGUEL 

## G ENERATING 

## S TATION SMEC is a power generating entity serving southe rn Texas. SMEC’s sole unit is the 440-MW mine-mouth San Miguel Unit 1. San Miguel w as 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 modul es, 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% SO 2 removal at a stoichiometric ratio of 1.20 (remove d basis). Figure 5 is a photograph of the overall FGD system, with Module A shown in Figure 6.Page 8 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 SO 2 emission allowances have created a need toPage 9 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. reduce the SO 2 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 SO 2 emissions, lb SO 2 /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 SO 2 emission rate, lb SO 2 /mmBtu 1.2 0.62 0.38 0.30
SO 2 removal, % 82 (Note 2) 92 96 97

Notes: 1. Design for 8.6 lbs SO 2 /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 occu r. 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 ai r was reduced to a single-louver bypass damper with no seal air.Page 10 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 sec ond 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 mo re 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 pe rformed using S&L protocol and a third-party testing firm, METCO, out of Dallas, Texas. Additional tests were c onducted 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, remain ing (higher-cost/benefit ratio) upgrade opportunities can be avoided. In response to S&L’s prioritized list of poten tial 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 spra y 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. Orig inally, 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 irregular ities 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 orifi ce 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 impr oved by using spray nozzles with lower Δ P than the venturi sprays and eliminating the slurry wall wash. The existing absorber spray nozzles were of a lo cal design that was easy to build and maintain, but did little more than distribute the slurry to th e trays. S&L identified an open spray nozzle that would require little maintenance, but with similar Δ P, would produce a fine spray cone. The effect was to create a third SO 2 absorption layer in the absorber.Page 11 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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. H 2 O pressure drop across the quencher. Because at times San Miguel Unit 1 was fan-limited, the quencher Δ P was considered a potential opportunity to improve the system. S&L research ed 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 ha ngs above the separate reaction tanks. The original and new quenchers are shown, respectivel y, in Figure 7 and Figure 8. The draft loss has been reduced by about 3 in. H 2 O. Figure 7. San Miguel Or iginal 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, SO 2 emission allowances became sufficiently valuable that consuming allowances through leakage of the byp ass dampers became unacc eptable. A rebuild of the FGD outlet duct during the 2007 outage woul d eliminate the bypass connections entirely. In the interim, SMEC caulked the da mpers closed to minimize leakage.Page 12 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 SO 2 removal (module inlet to outlet) improved from 92% to 96%. The mass of SO 2 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 SO 2 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 botto m 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 contro l of inhibited oxidation (2007).

• Upgrade instrumentation to improve control, e.g., pH, SO 2 , and module Δ P (2007).


## S PRINGERVILLE 

## G ENERATING 

## S TATION 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 (ana lysis summarized in Table 1). Both units are equipped with Combustion Engineering (now Alst om 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 un its (approximately equivalent in size to Units 1 and 2) required an offset in the emissions by reducing the NO X and SO 2 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 Opera tion Post-Unit 3 Operation
SO 2 , lb/mmBtu 0.69 0.24
NO X , lb/mmBtu 0.45 0.20Page 13 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. Figure 9. Springerville Generating Station

The dry FGD system for each unit comprises thr ee spray dryer absorber s (SDA) with rotary atomizers and a reverse-air fabric filter. Th e 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 lim e 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 constructe d, the dry FGD systems were built with a partial bypass for purposes of flue gas reheat. TEP, with S&L as Owner’s Engineer, implemen ted the following modifications to reduce NO X and SO 2 emissions:

• Installation of low-NO X burners and overfire air (NO X ).

• Installation of a fourth spray dryer and elimination of the flue gas bypass (SO 2 ). Based on an evaluation of proposals received, B& W was selected as the turnkey contractor for the FGD upgrade. To complete the upgrade, two infr astructure upgrades were necessary:

• Relocation of the cooling tower water bl owdown 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.Page 14 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. 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).Page 15 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 SO 2 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 SO 2 measurements were performed by a third-party testing company, METCO, out of Dallas, Texas. These m easurements were taken at the inlets of each module’s central gas disperser (CGD) and roof g as disperser (RGD). Si milar 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. SO 2 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 SO 2 emission of 2.6 lbs SO 2 /mmBtu. The SO 2 emissions from the coal being fired at SpringervillePage 16 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. Copyright 2007. during the performance tests were lower than woul d have been measured if the design coal had been available. TEP expressed concern that if a coal with an SO 2 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 SO 2 /mmBtu. Consequently, TEP requested that the testing demonstrate the capability of the system to achieve a minimum of 91% SO 2 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 SO 2 Removal

Run SO 2 Inlet (lb/mmBtu) SO 2 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 SO 2 measurements taken by METCO. SO 2 emission rates achieved duri ng 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 SO 2 /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 with in 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 fl ow 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, a nd 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 SO 2 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 c oncurrence, the official performance test for Unit 2, with regard to SO 2 removal and lime consumption, was performed on June 9. As indicated in Table 6, the system achieved emissions well below the 0.24 lb SO 2 /mmBtu permit value and nearly achieved the 91% removal effici ency attained by Unit 1 during its performance testing. Since, during the SO 2 removal tests, Springerville Unit 2 was operating at 100% MCRPage 17 of 17 Presented at Electric Power 2007, May 1-3, 2007. SL 406-208. 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 with in the four Unit 2 SDA modules. Both in the three-module and four-module cases, the flow dist ribution was within 3.5% of the average gas flow through each module. Table 6. Springerville Unit 2 SO 2 Removal

Inlet Measurement SO 2 Inlet (lb/mmBtu) SO 2 Outlet (lb/mmBtu) Percent Removal
SO 2 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 fl ow to the module at the time of the test. 

## C ONCLUSIONS Many of the FGD systems installed in the 1980s were designed for SO 2 collection efficiencies of between 75% and 90% to meet the then current emission limits (typically 1.2 lbs SO 2 /mmBtu). Upgrading these FGD systems to achieve 90% or more SO 2 removal presents an opportunity to generate SO 2 allowances for sale or to offset the emissions of new units. Upgrades to the existing equipment of that vintage, i.e., 20 years old, al so is typically required to restore the original design function, improve operability and main tainability 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.