Duke Energy Carolinas’ WFGD Retrofit Program: 12 Months of Operation at Marshall

Ronald E. Laws, P.E. Senior Engineer, Program Engineering ([email protected] ph. 704-382-8411, fax 704-382-9769) Carolinas 526 S. Church Street Charlotte, NC 28202

Dave Styer FGD Area Coordinator ([email protected] ph. 828-478-7506, fax 828-478-7613) Duke Energy Carolinas Marshall Steam Station 8320 East NC Hwy. 150 Terrell, NC 28682

Kelly Barger Technology Manager ([email protected] ph. 865-560-1654, fax 865-694-5203) Jürgen Dopatka, P.E. Technology Manager ([email protected] ph. 865-694-5342, fax 865-694-5203) Alstom Power Environmental Control Systems 1409 Centerpoint Boulevard Knoxville, TN 37932

Jim McCarthy, P.E. Chief Engineer Mechanical/Piping, Power Division – Fossil Sector, Shaw Group ([email protected] ph.704-331-6043, fax 704-331-1310) 128 S. Tryon St., Suite 400 Charlotte, NC 28202

Presented at: POWER-GEN International 2007 New Orleans, LA December 11 - 13, 2007

Page 1 of 15 ABSTRACT Duke Energy Carolinas is committed to a multiphase fleetwide SO2 emissions reduction program where four of eight -fired stations are being retrofitted with high efficiency WFGD systems by 2012. Engineering started in 2003, one station has started up, one station is being commissioned, construction is under way at the third, and the fourth started engineering in 2007. A brief overview of the retrofit progress at each site will be presented.

The state-of-the-art WFGD system at the Marshall Station has been operating for 12 months, and the performance testing on each of three absorbers and the overall system has been completed. The operating experience, maintenance requirements, and performance results at Marshall are the main focus of this paper. Specifics include:

· Absorber performance without spare spray levels, with dual orifice spray nozzles, and with organic acids · Operation of the damperless open-bypass flue gas handling system employing very long duct work runs and unique materials · Selection of FRP outlet flues and stack liners · HDPE piping: engineering, construction, and operation · Duke’s Gypsum Recycling Program · Effectiveness of wetlands for removal of selenium and mercury from WFGD blowdown · Overall operating and maintenance experience during the first 12 months, including O&M provisions and equipment reliability

Page 2 of 15 1. INTRODUCTION In 2002 Duke Energy Carolinas embarked on an ambitious program to retrofit flue gas desulphurization equipment on 12 of its largest units over the course of the next 10 years. The total affected generating capacity exceeds 6,000 MW. This is the largest and most complex plant modification program ever undertaken on the Duke Energy Carolinas fossil fleet. Total predicted costs approach $1.5 billion. The affected stations are summarized in Table 1.

Table 1: Stations Affected by Desulphurization

Station/Unit Location Approx. Net Expected Startup Capacity Each (MW) Allen 1 and 2 Belmont, NC 165 2009 Allen 3, 4 and 5 Belmont, NC 275 2009 Belews Creek 1 and 2 Walnut Cove, NC 1,120 2008 Cliffside 5 Cliffside, NC 560 2010 Marshall 1 and 2 Terrell, NC 385 2007* Marshall 3 and 4 Terrell, NC 660 2007*/2006* *Denotes actual startup

Duke Energy Carolinas has teamed with ALSTOM Power and Shaw/Stone & Webster to engineer, procure, construct and commission these systems. The size and importance of this program has posed numerous challenges and opportunities for innovative engineering solutions. Implementation of the SO2 emission reduction program is based on a staged approach. Using the results of the fleetwide Phase I study as a starting point, a site- specific Phase II study was conducted for each unit. Actual implementation (Phase III) commenced upon approval of funding, usually 3 – 4 months after completion of the Phase II study.

The first of these retrofits, Marshall Steam Station with its four boiler units, has been operating with a new state-of-the art WFGD system for 12 months. The operating experience, maintenance requirements, and performance results at Marshall are the main focus of this paper. A discussion of the overall program approach is discussed elsewhere.1, 2

Page 3 of 15 2. CURRENT PROGRAM STATUS Marshall Steam Station The Marshall Station is located on , approximately 35 miles northwest of Charlotte, North Carolina. The plant was constructed in the 1970s and consists of four (4) tangentially fired pulverized coal units. Units 1 and 2 have an approximate net capacity of 385 MW each while Units 3 and 4 are larger at 660 MW (net) each.

Construction on the Unit 4 FGD absorber started in summer 2005. In late fall 2006, Unit 4 FGD was the first one of the program to go into service, and Unit 3 followed in March 2007. The final two boiler units, Units 1 and 2, have been operating with a WFGD since May 2007. Figure 1 shows clean flue gas from Marshall Units 3 and 4 leaving the stack. Figure 1. Marshall’s New Stack with Unit 3 & 4 WFGD Online. Belews Creek Steam Station The Belews Creek Station is the largest coal-burning power plant operated by Duke Energy Carolinas, and is located on Belews Lake near Walnut Cove, North Carolina. The plant was constructed in the 1970s and consists of two (2) coal-fired units, each of which can generate 1,120 MW net output.

Construction at the Belews Creek Station began in May 2005. As of July 2007, the overall project is over 90% complete. Figure 2 shows the current construction status of the Belews Creek WFGD System.

Allen Steam Station The Allen Station is a five unit station located in Belmont, North Carolina on the . Units 1 and 2 (165 MW net each) began operating in 1957; unit 3 in 1959; unit 4 in 1960 and unit 5 Figure 2. Belews Creek Stacks and Absorbers. in 1961 (all 275 MW net each). Allen is the only Duke Energy Carolinas station with five units under one roof. The current construction status of the Allen stack and absorbers is shown in Figure 3.

The phase II study for Allen was completed in March 2006. The Phase III construction is currently underway with 36% complete as of June 2007.

Page 4 of 15 Figure 3. Allen Stack and Absorbers Embedded Rings.

Cliffside Unit 5 Cliffside Steam Station is a five-unit coal generating facility located in Cliffside, North Carolina. Units 1 – 4 are part of the original plant built in 1940. Due to their small size and age they will not be retrofitted with WFGD. Although part of the same station, Unit 5 (560 net MW) is located in Cleveland County 1/2 mile from the other four units. This unit is equipped with a selective catalytic reduction system.

Although Unit 5 WFGD was part of the original fleetwide program, the scope has been expanded to include AQCS equipment associated with a new Unit 6 plant. Engineering on Cliffside Unit 5 started in May 2007. In July 2007, the engineering related to the Unit 6 Absorber began. 3. 12 MONTHS OF OPERATION AT MARSHALL

Marshall’s first WFGD absorber has been operating since October 2006. Since that time, the remaining two absorbers have come on-line, and performance testing is still being conducted. This section discusses some of the features unique to Marshall’s FGD system and the station’s operations and maintenance (O&M) experience during the first 12 months of operation.

3.1 Absorber Design

The absorber design for all the stations represents the proven state-of-the-art ALSTOM Power open spray tower system with a number of features to improve efficiency and operational flexibility and at the same time reduce capital cost. · The absorbers were designed without a dedicated spare spray level, resulting in capital cost savings associated with the reduced tower height and the spray system (i.e. pumps, piping, valves, motors, switchgear, etc.). In the event of an unplanned

Page 5 of 15 spray pump outage, organic acid (DBA) will be injected into the system allowing the required SO2 removal performance to be maintained with one pump out of service. The design also allows for the flexibility to achieve 99% SO2 removal with all recycle pumps in service and DBA addition for enhanced performance when desired.

· The absorber is equipped with Alstom Power’s patented Performance Enhancement Plates (PEPs), also known as wall rings. These PEPs minimize ‘sneakage’ of untreated gas along the absorber wall, and at the same time re-entrain slurry that got lost to the absorber walls.

· In addition, the PEPs are complemented by state-of-the-art dual orifice spray nozzles, which spray both vertically up and down in all but the upper spray elevation. This increases the retention time of droplets for increased mass transfer with the acidic gases compared to conventional down-spray only configurations, with favorable impact on the draft loss. Both of the above absorber components afford high efficiency operation with practically no extra energy input.

3.2 Absorber Performance

Performance of the Marshall FGD System has met expectations. Unit 4 performance testing was conducted in January 2007. Due to the station’s dispatch requirements, the performance testing was staggered in January to operate at steady state for at least three solids residence times prior to testing. Two phases of testing were completed for Unit 4 – phase I at 2.4 lb SO2/MMBtu without DBA and phase II at 2.8 lb SO2/MMBtu with DBA. Table 2 summarizes the key performance parameter results from the Unit 4 performance testing.

Table 2. Unit 4 Performance Testing Summary Design Test Result SO2 Removal without DBA 95.7%* 96.2% SO2 Removal with DBA 99% 99.4%** Particulate Emission 0.03 lb/MMBtu 0.006 lb/MMBtu Gypsum Quality 95 ± 2 % Purity 94.4% Purity, <10% moisture 9.1% Moisture *Corrected for actual gas flow lower than design and SO2 inlet condition of 2.2 lb/MMBtu during testing **Actual SO2 inlet condition was 2.65 lb/MMBtu

Unit 3 performance testing was conducted in May 2007. Only one phase of testing was completed for Unit 3 – phase I at 2.4 lb SO2/MMBtu without DBA. Note that there was no testing performed at the 2.8 lbSO2/MMbtu, 99% SO2 removal parameter for Unit 3. This was the result of boiler issues as a result of burning these higher sulfur fuels. Due to system load constraints and continued difficulties burning these fuels, this performance test was waived. Refer to Table 3 below for a summary of the Unit 3 key performance parameter testing results.

Page 6 of 15

Table 3. Unit 3 Performance Testing Summary Design Test Result SO2 Removal without DBA 94.8%* 95.9% SO2 Removal with DBA 99% Not Tested Particulate Emission 0.03 lb/MMBtu 0.008 lb/MMBtu Gypsum Quality 95 ± 2 % Purity 96.7 % Purity, <10% moisture 8.07 % Moisture *Corrected for actual SO2 inlet condition of 2.63 lb/MMBtu during testing

Performance testing for the Marshall Unit 1&2 Absorber has not been fully completed as of this writing. All performance testing should be completed by the end of September 2007. Two phases of testing are planned for Unit 1/2 – phase I at 2.4 lb SO2/MMBtu without DBA and phase II at 2.8 lb SO2/MMBtu with DBA. In addition to the two phases of emission testing, the common performance guarantees will be measured. Extended reaction tank N-1 agitator operation will also be tested to ensure that gypsum quality can be maintained when one reaction tank agitator is out of service.

3.3 Damperless Open Bypass Configuration

The selection of an open bypass flue gas handling configuration is one of the unique features at Marshall. As indicated in Figure 4, open bypass means that the gas paths to the WFGD system and to the old stack, which serves as start-up/emergency bypass, are not physically separated by a damper, but instead, are in permanent open connection to each other, hence open bypass. The main function of the open bypass is to protect the boiler from undesired flue gas pressure excursions during transient conditions. The incentive to utilize an open bypass arrangement in lieu of dampers is the inherent simplicity of operation and lack of constant maintenance attention to dampers, which are required to operate within seconds if needed. In order to prevent untreated flue gas leaving through the open bypass, the pressure at the bypass connection (stack base) must be slightly negative. At the same time the inflow of ambient air through the existing stack must be limited to not more than 5% of the total flue gas flow to avoid corrosion in the ductwork and unnecessary expense associated with the excess gas volume.

Page 7 of 15 Boiler ESP ID Fan Existing Stack

New Stack FGD Booster System Fan

Figure 4. Damperless Open Bypass Flow Diagram.

As mentioned previously, the open bypass created a need to protect select areas of the ductwork where the mixed gas temperature may drop below the sulfuric acid dew point temperature. Concerns related to duct corrosion due to cooling and in-flow of colder ambient air with open bypass were exacerbated at Marshall due to the long distance from the main power block to the FGD Island (up to 1,000 ft). Therefore, issues like duct material and lining selection as well as high relative contribution to pressure drop from the ductwork sections required special attention. These issues were addressed to a large degree through Computational Fluid Dynamic (CFD) modeling, in conjunction with material experts.1 The flue gas is transported from the ID fan discharges of the four units to the new booster fans and absorber vessels via ductwork totaling 5,463 linear feet (over 8,400 tons of ductwork).

After evaluating the CFD corrosion results and the material options, S-TEN 1 became the clear choice for a cost effective material option to provide the required protection of the inlet ductwork. S-TEN 1 material was selected for the majority of the WFGD inlet duct with a thick polyurethane asphaltic mastic applied to the carbon steel substrate in the cold air turbulent mixing zones at the junction between the existing ID fans, the existing stacks, and the new ductwork. Borosilicate block directly applied to the mastic on the inside of the duct has been used to protect the mastic. To provide mechanical protection during inspection and maintenance, a 1-¼ inch thick Tuffchem masonry was installed on floor areas accessible for inspection. Material selection for the Marshall Station inlet duct expansion joints, dampers, and booster fans also necessitated careful evaluation.

Because the ambient air inflow through the open bypass does not generate significant velocities in the existing stack, there has been some uncertainty about the accuracy of a flow meter to measure this flow. During the performance testing at Marshall, the Testing Contractor was engaged to measure the open bypass inflow into the existing stack. Comparing the data from Unit 4 performance testing to the flow measured by the meter in the stack, the ambient air inflow was measured by the Testing Contractor to be within the design limit of 5% of total ID Fan outlet flue gas volume.

Page 8 of 15 3.4 FRP Outlet Duct and Stack Liners Each of the three absorber vessels is equipped with a 29’-6” diameter fiberglass reinforced plastic (FRP) outlet duct as shown in Figure 5. These ducts feed a 315’ tall stack equipped with three 29’-6” FRP flue gas liners enclosed in a single 80’-2” outside diameter concrete windscreen. The conceptual design was based on 317LMN outlet ducts and flue gas liners. The cost and lead-time for this material escalated rapidly early in the design process, Figure 5. Marshall Unit 4 Absorber FRP Outlet Duct. thus other options were evaluated. FRP was eventually selected for both the outlet duct and the flue gas liners. The decision to switch to FRP was based on 20-year life cycle cost, superior corrosion resistance and reasonable lead-time. Other materials examined in addition to 317LMN and FRP included 276 clad over carbon steel and epoxy mastic/borosilicate glass block.

FRP had previously been used successfully in similar applications within the power industry. Due to the size and importance of this equipment, steps were taken to build on this experience as outlined below:

· Design Conditions – The maximum expected normal flue gas temperature exiting the absorbers was approximately 125 ºF. The normal operating design temperature for the outlet duct and flue gas liners was established at 140 ºF along with a transient design temperature of 200 ºF. The normal operating mode of the FGD system precluded use of the new stack without the FGD system in operation. A diesel driven emergency quench system was installed upstream of each absorber in order to protect the FRP outlet duct and flue gas liners, as well as the absorber internals, in case of a system upset. This system was sized to provide protection for approximately 10 minutes based on flue gas excursion temperatures of approximately 500 ºF.

· Liquid Collection – Both physical model testing and computational fluid dynamic analysis were used to design liquid collection devices within the outlet ducts and flue gas liners. A maximum flue gas velocity of 55 – 60 ft/sec was used to size the ductwork and liners. This is the recommended design velocity for FRP ductwork to minimize droplet entrainment from liquid on the duct/liner walls. Special attention was paid to the FRP joint that connected the individual duct and liner sections. The contour of the joint was configured to minimize protrusion on the inside diameter of the duct/liner, thus reducing the potential for re-entraining liquid drops into the gas path.

Page 9 of 15 · Third Party Review – The duct and liners were designed and constructed in accordance with ASTM D5364 “Standard Guide for Design, Fabrication, and Erection of Fiberglass Reinforced Plastic Chimney Liners with Coal Fired Units” and constructed by an ASME RTP-1 stamp holder. Although helpful, these standards do not cover all critical aspects of FRP design and construction. An experienced third party consultant was hired to review all engineering assumptions, calculations, material specifications and fabrication drawings as well as provide onsite quality assurance of the fabrication and installation of the FRP sections. All FRP sections were spun in an onsite facility.

3.5 HDPE Piping High density polyethylene (HDPE) pipe was used extensively throughout the Marshall WFGD project. A total of 57,000 lineal feet were installed. HDPE was used almost exclusively for both water and slurry piping in above and below ground services. Notable exceptions include absorber recycle pump suction and discharge, oxidation air, and compressed air.

Duke had experienced numerous problems over the years with corrosion, tuberculation and Asiatic clam infestation in carbon steel raw water piping at its generating stations. Early in the conceptual phase of the program, the decision was made to investigate alternatives to Duke’s traditional use of carbon steel piping for these services. The investigation examined various ways to deal with these issues such as pigging, chemical treatments, etc.; however, the primary focus was on alternate materials. Duke had recently completed a similar study for the raw water systems at other generating stations. This study served as the foundation for the FGD investigation. Alternate materials examined in the FGD study included stainless steel, PVC, rubber lined carbon steel and HDPE. The study examined corrosion resistance, pressure drop, capital cost, long term operating and maintenance costs, impact resistance, availability, etc.

HDPE was ultimately chosen due to its superior corrosion resistance, low net present value cost and good experience to date with a test section of HDPE. The test section did not show any signs of corrosion or biological buildup after a 6-year trial run. During this study the erosion resistant capabilities of HDPE also became apparent. Duke had some experience with HDPE for ash sluicing with good results. The decision to use HDPE was expanded to the WFGD slurry services as well.

The benefits of using HDPE were clear; however, it did pose numerous engineering and construction challenges as outlined below. It should be noted that although ASME B31.1 allows the use of non-metallic pipe, it does not provide any mandatory design rules.

· Temperature sensitive – HDPE loses strength rapidly with increasing temperature. The pressure rating at 130 ºF is only 65% of the rating at 100 ºF. This was a particular issue with slurry piping on the Marshall FGD project as approximately 50% of this piping had a design temperature

Page 10 of 15 greater than 125 ºF. If mitered fittings are used, an additional reduction in pressure rating is required. In order to control costs, two line classes were established for HDPE. The “hot” line class design conditions were established at 95 psig, 125 ºF and utilized SDR 7 piping with both fabricated and molded fittings. The “cold” line class design conditions were 95 psig at 110 ºF and utilized SDR 9 piping with both fabricated and molded fittings. In addition, the thermal expansion coefficient of HDPE is much greater than carbon steel and must be accounted for in piping layouts.

· Supports – HDPE piping has a low modulus of elasticity when compared to carbon steel and requires approximately twice the number of pipe supports, which was accounted for in the economic analysis. A side benefit of the low modulus of elasticity is reduced nozzle loads on equipment.

· Sizing – Although the smooth walls of HDPE pipe offer reduced pressure drop when compared to carbon steel, the required wall thickness often necessitated using the next larger size pipe to maintain a reasonable fluid velocity. Adapter plates were required to accommodate differences between pipe inside diameter and valve inside diameter. Pressure drop data for HDPE, especially fittings, are not as extensive as that for carbon steel. This introduced a degree of uncertainty in pressure drop calculations, which had to be considered when sizing pumps.

· Layout – Long radius bends were used wherever possible to minimize erosion in slurry lines. D/r ranged from 2 to 5. Although mitered fittings were permitted, a source for “hot forged” sweep bends (D/r = 3) was identified and used for most bends. The decision to use HDPE long radius bends was not made until after much of the equipment layout was in place, thus accommodating the long radius bends was particularly challenging.

· Construction – Spools of HDPE piping were prefabricated and lifted into place similar to carbon steel. Flanged connections were used for connecting the spools.

The WFGD system has been operating since late 2006, and there have been no noteworthy issues identified by the station with regard to the use of HDPE piping.

3.6 Gypsum Recycling Program Recognizing the solid waste disposal volume the FGD Program represented and the success other utilities have had with recycling FGD byproducts, Duke searched for a partner for recycling the byproduct that would be generated by the FGD Program. A partnership was developed with a wallboard manufacturer, and plans were developed for the manufacturer to build a new wallboard production plant with Duke being the sole provider of byproduct gypsum for the facility.

Page 11 of 15 A new wallboard production facility was built in the nearby town of Mt. Holly. This facility began operation in August 2007 and will be capable of consuming a significant portion of the gypsum byproduct annually. The wallboard facility has been scheduled to accommodate the build out schedule of the Duke FGD Program as well as meet the needs of the wallboard market in the Carolinas. To date, the gypsum produced in the Marshall FGD System has met the quality requirements of the wallboard facility.

3.7 Constructed Wetland Treatment System Detailed information discussing the prediction of the purge stream composition and the design of the constructed wetlands treatment system (CWTS) is found elsewhere.1, 3, 4, 5

The construction of the Marshall CWTS began in September 2004 and is complete. The wastewater leaving the wastewater solids removal system is blended with service water to assist in decreasing the chloride content of the wastewater. This pretreated wastewater is then treated in a CWTS. The final CWTS configuration includes dual equalization basins and three parallel series of four treatment cells. The system was constructed to achieve gravity flow throughout the system including discharging into the existing ash basin. The total acreage of the equalization basins and treatment cells is approximately 15 acres with the total area required to construct the CWTS approaching 46 acres. The first scrubber unit was placed in service in the fall of 2006, when introduction of the scrubber purge stream to the CWTS began. Wetlands Cells 1A, 1B, 1C shown in Figure 6 are the first treatment cells downstream of the equalization basin and are planted with Bulrush. The CWTS has proven effective in mercury reduction but selenium removal has been Figure 6. Wetlands at Marshall, July 2006. limited. Pilot testing completed by Clemson/Entrix in November 2006 concluded that boron levels as low as 25 ppm could impact the wetlands plants. In addition, DBA levels of 200 ppm impacted the performance of the wetlands system in the pilot testing. Actual boron levels in the wastewater are impacting the wetlands plants; however, the selenium removal in the wastewater solids removal system clarifier and the dilution in the Ash Basin downstream of the CWTS have resulted in the National Pollutant Discharge Elimination System (NPDES) data being well within the projected limits even though no current Marshall NPDES limits for selenium or mercury exist. To date there has been limited DBA addition to the FGD System; therefore, limited concentrations have been observed in the wetlands. Duke is evaluating the need for conducting a study of the effect of DBA on wetlands performance since FGD operation has presented limited opportunities.

Page 12 of 15 3.8 O&M and Reliability

Duke Energy Carolinas’ power stations must operate at high levels of reliability and availability during the periods between planned outages. Careful consideration was given to the reliability, consequences of failure, and time to repair for critical process and auxiliary equipment. Efforts were made to ensure that the failure of a single piece of equipment would not impact the performance or availability of the WFGD system.1

Low cost, reliable operation is key to the success of the Duke Energy Carolinas’ FGD Program. The Fleetwide Program is founded on this premise. The Duke Energy Carolinas’ FGD Program relies on a small operating staff for the day-to-day operations. The Marshall FGD operation is staffed around the clock by two operators (although commissioning personnel are still assisting this role). While routine maintenance (e.g., oil changes, greasing rotating equipment, etc.) is typically handled by the plant staff, maintenance activities of a more significant nature will be handled by a Maintenance Contractor.

O&M Operations at Marshall have been fairly uneventful. There have been a couple of incidences of foaming in the Absorber resulting in overflows of the Reaction Tank. One event was related to the misoperation of the Reagent Feed System, which resulted in a low pH excursion. The other occurrences seem to be related to oil firing of the boiler during startup.

Other than routine maintenance activities, there have been no major maintenance events thus far. Marshall Unit 4 has had an outage to perform some internal inspections of the Absorber after 4 months of operation. The only observations were some scale buildup around the Absorber Inlet Nozzle and some minor scaling of the mist eliminators, which was removed by manual washing. More detailed inspections of Marshall Unit 4 Absorber are planned for Fall 2007 to assess both performance of materials of construction and formation of scale inside the vessel.

Reliability Appropriate application of equipment redundancy has been applied to the Fleetwide FGD Program. The Marshall FGD has experienced a few impacts to reliability. Some of the major events are discussed herein. These events are being evaluated for implementation on the remainder of the FGD Fleetwide Program.

Booster fan trips, resulting in run backs on the unit generation, impacted the Marshall Unit 4 FGD early during the initial operation. These trips were determined to be initiated by Booster Fan motor vibration instrumentation. It was determined that not all indications were the result of vibration, but many were related to construction activities around the Booster Fan motor. These trips were removed from the Booster Fan trip logic.

Page 13 of 15 The Marshall FGD suffered a premature failure of the pump bearings for the Reagent Feed Pumps. This failure was determined to be a result of misinformation/ misunderstanding of the manufacturer’s O&M Literature. While this failure did not specifically cause a reliability issue due to installed redundancy, it highlighted the need to review maintenance procedures for all rotating equipment to validate the plant established maintenance intervals and staff training.

The most significant reliability event has been the total blackout of the FGD Island in July 2007, which was initiated at the 13.8 KV transformer system. The investigation of the sequence of events and root cause is still underway at the time of writing. The blackout event highlighted some other potential equipment reliability issues, which allowed a gas path to exist beyond the operational time constraints of the diesel powered emergency quench pump (10 minutes). The continued flow of flue gas caused a temperature excursion in the Absorber resulting in permanent heat damage of a significant portion of the polypropylene mist eliminators in the Unit 1&2 Absorber. The circumstances surrounding this event are still being evaluated, and a further review of the fleetwide program reliability expectations is planned.

4 SUMMARY AND CONCLUSIONS The Duke Energy Carolinas’ WFGD retrofit program is well underway with all units operating at Marshall and progress being made toward project completion at the other stations. The Marshall WFGD is successfully operating and meeting performance guarantees since Unit 4 came online in late 2006. This paper has highlighted some of the unique features of the Marshall system and noted any pertinent experience with those features since the WFGD system has been operating. While the damperless open bypass, the FRP outlet duct, and the HDPE piping required special design considerations, they have proven to meet the requirements of the WFGD system. Many of these unique features will require further evaluation due to impacts expected from operation, such as the impacts of DBA use on the CWTS effectiveness to remove mercury and selenium. Finally, O&M and reliability was discussed with some noted lessons learned and further evaluations pending.

Page 14 of 15 5 REFERENCES 1. McCarthy, J., J. Dopatka, R. Mardini, P.C. Rader, and C. Bussell, Duke Power WFGD Retrofit Program: Compliance via Standardization and Selective Site-specific Innovations. Proceedings POWER-GEN International, Las Vegas, 2005. 2. McCarthy, J., J. Dopatka, K. Barger, P.C. Rader, and C. Bussell, Duke Energy– Carolinas’ WFGD Retrofit Program: Site-specific Innovations and their Implementation. Proceedings MEGA Symposium, Baltimore, 2006. 3. Emission Factors Handbook: Guidelines for Estimating Trace Substance Emissions from Fossil Fuel Steam Electric Plants, EPRI, Palo Alto, CA: (2002) 105402. 4. McCarthy, J., D.T. Shuping, J.H. Rodgers Jr., J. Dopatka, P.C. Rader, and C. Bussell, Duke Power WFGD Retrofit Program: Achieving the Lowest System-Wide Cost of Compliance. Proceedings Combined Power Plant Air Pollutant Control Mega Symposium, Washington, 2004. 5. Mierzejewski, M. K., Clean Air Shouldn't Mean Dirty Water: FGD Wastewaters and Their Treatment, Proceedings Power-Gen, Orlando, USA, pp 531-542 (1991).

6 KEYWORDS ALSTOM Power, Duke Energy-Carolinas, Shaw, North Carolina, Clean Air, FGD, WFGD, Flue gas desulfurization, SO2, Removal, Retrofit, Open Bypass, Wastewater treatment, Wastewater solids removal system, Constructed Wetlands, Selenium removal, Marshall Steam Station, O&M, Reliability, FRP ductwork, Open spray tower, HDPE piping, Gypsum recycling

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