Duke Energy Carolinas’ WFGD Retrofit Program: 

Operation at Marshall and Belews Creek Stations

Paper #: 48 

Ronald E. Laws, P.E. 

Consulting Engineer, Program Engineering 

(relaws@duke-energy.com ph. 704-382-8411, fax 704-382-9769) 

Duke Energy Carolinas 

526 S. Church Street 

Charlotte, NC 28202 

Ed Byers

FGD Area Coordinator 

(ecbyers@duke-energy.com ph. 336-445-0388) 

Duke Energy Carolinas 

Belews Creek Steam Station 

3195 Pine Hall Road 

Belews Creek, NC 27009 

Jürgen Dopatka, P.E. 

Technology Manager 

(jurgen.dopatka@power.alstom.com ph. 865-694-5342, fax 865-694-5213) 

Rita Mardini 

Senior Process Engineer 

(rita.h.mardini@power.alstom.com ph. 865-560-1393, fax 865-694-5213) 

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 

(James.McCarthy@Shawgrp.com ph.704-331-6043, fax 704-331-1310) 

128 S. Tryon St., Suite 400 

Charlotte, NC 28202 

Presented at: 

MEGA Symposium 2008 

Baltimore, MD 

August 25-28, 2008 

Page 1 of 18 

10.3155/2008CP175.48
1. ABSTRACT 

Duke Energy-Carolinas committed to a multiphase fleet-wide SO2 emissions reduction. 

Four of eight coal-fired stations are being retrofitted with high efficiency WFGD by 

2012. Engineering started in 2003, two stations are already operating, one is being 

commissioned, and another being constructed. 

The state-of-the-art WFGD systems at Marshall and Belews Creek Stations have been in 

operation between 8-20 months. Performance testing on the absorbers and overall 

systems has been completed. Operating experience, maintenance requirements, and 

performance results are the main focus of this paper. Specifics include: 

• Absorber performance without the presence of spare spray levels 

• Damperless open-bypass system employing unique materials 

• Selection of FRP outlet flues and stack liners 

• HDPE piping: engineering, construction, operation 

• Duke’s Gypsum Recycling Program: Gypsum quality, contract approach, 

transportation arrangement, dedicated supply. 

• Biological and wetlands removal of selenium and mercury from WFGD 

blowdown 

• Overall operating and maintenance experience, including O&M provisions and 

equipment reliability during the recent 20 months at Marshall Steam Station and 

eight months at Belews Creek Station. 

Page 2 of 18 
2. 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 

Capacity Each 

(MW) 

Expected or 

Actual* Startup 

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* 

Duke Energy Carolinas has teamed with Alstom Power and Shaw 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 20 months. The second WFGD 

retrofit, Belews Creek Station with its two large boilers, has been operating its absorbers 

as much as eight months. Allen Station with its five boilers and two absorbers is close to 

completion of construction. The operating experience, maintenance requirements, and 

performance results at Marshall and Belews Creek are the main focus of this paper. A 

discussion of the overall program approach is discussed elsewhere.1, 2

Page 3 of 18 
3. CURRENT PROGRAM STATUS 

Figure 1. Marshall’s New Stack with Marshall Steam Station all three FGD units in service. 

The Marshall Station is located on Lake Norman, 

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 2004. 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 cleaned flue gas 

from Marshall leaving the stack. 

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. 

Figure 2. Belews Creek Units 1 & 2 WFGD, Dec. 2007 

Construction at the Belews Creek 

Station began in May 2005. The 

two absorbers serving Unit 1 went 

into service in January 2008, 

followed by the absorbers for Unit 

2 in April 2008. Figure 2 shows 

the recently completed Belews Creek WFGD System. 

Allen Steam Station 

The Allen Station is a five unit station located in Belmont, North Carolina on the 

Catawba River. Units 1 and 2 (165 MW net each) began operating in 1957; unit 3 in 

1959; unit 4 in 1960 and unit 5 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 WFGD system is shown in Figure 3. 

Page 4 of 18 
The Phase III construction is approximately 

70% complete as of June 2008. The first 

absorber is expected to go on line in spring 

2009. 

Figure 3. Allen Inlet Duct, Absorbers 1 & 3 and 

Stack (June 2008) 

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 and will be retired in 

2012. 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. 

Unit 5 WFGD was part of the original fleetwide program, the scope has been expanded to 

include AQCS equipment associated with a new, 800 MW ultra supercritical unit (Unit 

6). Detailed engineering started in the summer of 2007 and is approximately 25% 

complete as of June 2008, with construction recently started. Unit 5 FGD is scheduled 

for Commercial Operation in the Fall of 2010. Unit 6 is scheduled for Commercial 

Operation in the Spring of 2012. 

4. COMMON FEATURES OF THE WFGD SYSTEMS OF EACH 

STATION 

4.1. 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. 

• At several stations, multiple boilers are feeding into a single absorber vessel 

(Marshall, Allen, see Table 2), afforded by the reliability of recent open spray tower 

designs. 

• 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 

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. 

Page 5 of 18 
• 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.

4.2. FRP Outlet Duct and Stack Liners 

All absorber vessels are equipped 

with fiberglass reinforced plastic 

(FRP) outlet ducts as well as FRP 

flues. A summary of the key 

absorber outlet duct and flue gas 

outlet flue data is provided in Table 

2. While Marshall (Figure 4) 

utilizes extended outlet ducts, the 

FGDs at the remaining stations 

utilize more closely coupled 

extended absorber outlets and 

extended stack breeches (See 

Figure 2 for Belews Creek). 

Figure 4. Marshall Unit 4 Absorber FRP Outlet Duct 

Table 2. Overview of FRP Outlet Ducts and Stack Liners at each Station 

Station Unit Absorber Outlet 

Duct Diameter 

Flue 

Diameter 

Windscreen 

Diameter

Stack 

height

Allen 1, 2, 5 29’+6” 

(Common Absorber)

29’+6” 

3, 4 29’+6” 

(Common Absorber)

29’+6” 

74’ 

(Common Stack) 

365’+0” 

Belews 

Creek 

1 26’+2” ea 

(2 Abs.) 

36’+0” 47’+10” Top 

63’+0” Bottom 

500’+0” 

2 26’+2” ea 

(2 Abs.) 

36’+10” 47’+10” Top 

63’+0” Bottom 

500’+0” 

Cliffside 5 25’+0” 25’+0” 

6 29’+0” 29’+0” 

72’+0” 

(Common Stack) 

575”+0” 

Marshall 1, 2 29’+6” 

(Common Absorber) 

29’+6” 

3 29’+ 6” 29”+6” 

4 29’+ 6” 29’+6” 

80’+2” 

(Common Stack) 

315’+0” 

(Common 

Stack) 

Page 6 of 18 
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, 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 C-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. 

• 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. 

Page 7 of 18 
4.3. HDPE Piping 

High density polyethylene (HDPE) pipe was used extensively throughout the Fleetwide 

WFGD retrofits. In excess of 150,000 ft is installed across all the projects. 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 these FGD projects 

as approximately 50% of this piping had a design temperature 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, 

Page 8 of 18 
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 Marshall 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 Marshall 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. 

4.4. CWTS General 

While Constructed Wetlands Treatment System (CWTS) was the initial choice for FGD 

Waste Water treatment, early in the Belews Creek preliminary engineering there was 

concern developing about the viability of the CWTS. For Belews Creek, a biological 

treatment system was chosen to provide the bulk of the FGD waste water treatment 

downstream of a conventional physico-chemical treatment system. CWTS was expected 

to provide polishing treatment in case of a shortfall in the biological treatment system. 

The Allen and Cliffside FGD projects have not incorporated CWTS in their designs. 

Rather, biological treatment systems have been chosen as the FGD waste water treatment 

system. 

The predicted selenium concentration for Belews Creek was bracketed to 6.4 ppm min., 

8.2 ppm avg., and 17.5 ppm max. The predicted mercury concentrations were 0.04 ppm 

min., 0.11 ppm avg., and 0.44 ppm max. Detailed information discussing the prediction 

of the purge stream compositions and the design of the constructed wetlands treatment 

system (CWTS) is found elsewhere.1, 3, 4, 5

Page 9 of 18 
With the predicted ranges in mind, the Belews Creek WWTS was designed for a 

selenium concentration of 4.00 ppm max. and a mercury concentration of 0.30 ppm max.. 

During the tuning process in February 2008 at Belews Creek, WWTS inlet samples were 

analyzed and the selenium concentration ranged between 1.7 – 10.1 ppm for digested Se, 

between 0.56 – 1.86 for dissolved Se, and between 0.0011 – 0.0021 ppm for mercury. It 

must be noted that as of this writing the underlying inlet concentrations of these elements 

in coal, limestone and water at that particular time were not cross-checked to see where 

they ended up in comparison to the value ranges used for the prediction. This would 

allow an assessment of the prediction quality. 

4.5. 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. 

A new wallboard production facility was built in the town of Mt. Holly, North Carolina. 

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 and Belews Creek FGD Systems have met the quality requirements of the 

wallboard facility. 

5. 20 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 all performance testing has been 

completed. 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 20 

months of operation. 

 

5.1. 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. 

Page 10 of 18 
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. 

Performance testing for the Marshall Unit 1&2 Absorber was conducted in August 2007. 

Two phases of testing were completed 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. The agitator out of service 

and Electrical Consumption testing was not performed due to Non-FGD operational 

issues which curtailed the testing. Table 3 summarizes the key performance parameter 

results from the Marshall performance testing. 

Table 3. Marshall Performance Testing Summary. 

Test Results 

 Unit 1&2 Unit 3 Unit 4 

SO2 Removal without DBA, 

Design/Actual 

95.0% / 95.3% 94.8%* / 95.9% 95.7%** / 

96.2% 

SO2 Removal with DBA 99% / 99.4%† Not Tested 99.4%††

Particulate Emission, lb/MMBtu 

(Design of 0.03 lb/MMBtu) 

0.0014 0.008 0.006 

Gypsum Quality 

 Purity (Design 95 ± 2 %) 

 Moisture (Design <10 %) 

97.7 wt% 

7.7 wt % 

96.7 wt% 

8.1 wt% 

94.4 wt% 

9.1 wt% 

*Actual SO2 inlet condition was 2.63 lb/MMBtu 

**Corrected for actual gas flow and actual SO2 inlet conc. lower than design during 

testing 

† Actual SO2 Inlet Condition was 2.53 lb/MMBtu 

††Actual SO2 inlet condition was 2.65 lb/MMBtu 

5.2. 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 5, 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 

Page 11 of 18 
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. 

Figure 5. Damperless Open Bypass Flow Diagram. 

Boiler ESP

ID Fan Existing 

Stack

Booster 

Fan

FGD 

System

New 

Stack

S-TEN 1 material was selected for the majority of the WFGD inlet duct with a thick 

polyurethane asphaltic mastic applied 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 1-1⁄4 inch thick Tuffchem masonry was installed on floor areas accessible for inspection. 

Due to low ambient air velocities in the existing stack, there has been some uncertainty 

about the accuracy of a flow meter to measure this flow. Performance testing at Marshall 

confirmed the ambient air flow to be within the design limit of 5% of total ID Fan outlet 

flue gas volume. 

5.3. Constructed Wetland Treatment System at Marshall 

The construction of the Marshall 

CWTS began in September 2004. 

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 

Figure 6. Wetlands at Marshall, July 2006. 

Page 12 of 18 
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 not fully 

met expectations. 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. 

5.4. 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, and therefore also uses multiple boilers feeding into one absorber at two 

stations. 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 

Page 13 of 18 
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 occurred in the Spring of 2008 to assess both performance of materials of 

construction and formation of scale inside the vessel. Areas of significant scale buildup 

appears to be limited to the wet/dry interface at the Absorber Inlet Nozzle. Corrosion 

was observed on the 317LMN material as well as some small areas of C-276. Mist 

Eliminator materials were found to be clean with only a few small areas of solids buildup. 

The HDPE piping is performing well. The only issue after 20 months has been a sweep 

elbows on the mill return line (classifier underflow) to the ball mill. This line is the most 

abrasive service in the FGD System. Since the line is a gravity flow line, a temporary 

repair was performed which consisted of banding a sheet of rubber to the exterior 

Reliability 

Appropriate application of equipment redundancy has been applied to the Fleetwide FGD 

Program. The Marshall FGD has experienced a only few impacts to reliability. 

6. EIGHT MONTHS OF OPERATION AT BELEWS CREEK 

6.1. Absorber Performance 

Performance of the Belews Creek FGD System has met expectations as of July 2008. The 

Unit 1 tuning process was conducted in February 2008 with lower sulfur coal 1.6 

lbSO2/MMBtu. Performance testing is scheduled for the overall whole plant in August, 

2008 while burning design sulfur coal of 2.4 lbSO2/MMBtu. Table 4 summarizes the key 

performance parameter results from the Unit 1 & 2 Tuning processes. 

Table 4. Belews Creek Tuning Results Summary. 

Unit 1 Unit 2 

SO2 Removal without DBA 

(Design 95%) 

>96.0% >96.0%* 

Gypsum Quality 

 Purity (Design 95% ± 2%) 

 Moisture (Design <10%) 

96.5% 

8.7% 

96.3% 

8.5%, 

*Three out of four spray levels operating while burning low sulfur coal of 1.4-1.6 lb 

SO2/MMBtu. 

Performance testing for the Belews Creek Unit 1&2 Absorber has not been fully 

completed as of July 2008. All performance testing is expected to be completed by the 

end of August 2008. One phase of testing is planned for Unit 1 & 2 - at 2.4 lb 

SO2/MMBtu without DBA. In addition to the emission testing, the common performance 

guarantees will be measured. 

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6.2. Waste Water Treatment System – Mercury and Selenium 

The FGD purge stream is unsuitable for reuse by other power plant facilities and 

therefore must be treated separately before being discharged. The characteristics of this 

wastewater stream are such that it requires extensive treatment. A dedicated wastewater 

treatment system has been provided that consists of physical-chemical, biological, and 

constructed wetlands (CWTS) treatment steps. 

Physical-Chemical Treatment 

The physical-chemical process consists of hydrated lime addition to elevate pH to effect 

the precipitation of soluble metals as insoluble hydroxides and oxyhydroxides. An 

organosulfide reagent is added also to form organosulfide heavy metal complexes, which 

have very low solubility products thus resulting in maximum heavy metal removal 

(mercury). Ferrous or ferric chloride and Polymer are added too to form a dense floc and 

enhance the settling characteristics of the precipitate. Hydrochloric acid is added to 

readjust the pH value to meet effluent requirements. 

Performance of the Belews Creek Waste water Mercury Removal System has met and 

exceeded expectations. Belews Creek Mercury Removal testing was conducted in 

February 2008. Table 5 summarizes the key performance parameter results from the 

testing. 

Table 5. Belews Creek Mercury Removal Testing Summary 

Design Avg. Test Result

FGD Purge Effluent Mercury Concentration, ppm 0.30 0.0016 

EQ Tank Effluent Mercury Concentration, ppm 0.0014 

Clarifier Influent Mercury Concentration, ppm 0.0010 

Clarifier Effluent Mercury Concentration, ppm BRL* 

Bioreactor 1 Influent Mercury Concentration, ppm BRL* 

Bioreactor 2 Influent Mercury Concentration, ppm BRL* 

Bioreactor 2 Effluent Mercury Concentration, ppm 0.001 BRL* 

* BRL: Below Reporting Limit of 0.0002 ppm 

 

Biological Selenium Removal 

The physical and chemical treatment will be followed by a biological treatment where 

microbes will be utilized to reduce selenite and selenate to elemental selenium. A nutrient 

is sdded to the system to ensure a viable biogrowth. 

Performance of the Belews Creek Biological Selenium Removal System has met and 

exceeded expectations. Testing of the Selenium in the waste water influent stream from 

the FGD has yielded constituent levels frequently exceeding the Selenium design value. 

Belews Creek Selenium Removal testing was conducted in February 2008. Table 6

summarizes the key performance parameter results from that testing. 

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Table 6. Belews Creek Biological Selenium Removal Testing Summary. 

Design Avg. Test Results 

Influent dissolved Se Concentration, ppm 4.00 1.12 

Influent digested Se Concentration, ppm 4.00 4.28 

Effluent dissolved Se Concentration, ppb 100 31 

Effluent digested Se Concentration, ppb 100 12 

CWTS at Belews Creek 

The Belews Creek CWTS design is very similar to that constructed for the Marshall FGD 

Project. Unfortunately, plant growth has been very frustrating. The initial planting of 

Bulrushes did not root well and became displaced in the cells resulting in loss of the 

plants. The resultant replanting was destroyed by a flock of geese who feasted on the 

young plants. The third replanting has been performed with the addition of geese counter 

measures including wolf effigies and the use of Kevlar wire strung over the planted cells. 

These numerous replantings caused the CWTS schedule to extend beyond the First 

Absorber startup. Subsequently, it is fair to classify the CWTS as not performing at this 

writing due to plant infancy. 

As already mentioned in section 4.4, the CWTS at Belews Creek was intended for 

polishing only in case of a shortfall of the biological treatment system. Since start-up of 

the FGD system, the effluent limits were met already ahead of the CWTS. 

6.3. O & M and Reliability 

Initial operation of Unit 1 was fairly uneventful. Operations was challenged maintaining 

Reaction Tank chlorides below the 12,000 ppm limit. Some of this challenge was a 

function of burning low sulfur coal with near maximum coal chloride content. Piping 

design issues compounded operations ability to address this issue. The piping resolution 

involved adding vents to gravity return lines which seemed to be scavenging the Purge 

Stream and reducing the ability to purge chlorides. The low sulfur/high chloride fuel 

issue was anticipated and the provisions were incorporated in the design to accommodate 

this prospect. Some additional modifications are being implemented to make the task of 

dealing with low sulfur-high chloride coals more palatable. 

Initial operation of Unit 2 has been experiencing significant foaming due to a booster fan 

lube oil leak. Due to high system demand on generation, the Station was unable to take a 

load reduction or Unit outage to resolve the leak for several weeks. The leak has been 

resolved early July, although the foaming issue continued through most of July 2008 due 

to the accumulated oil. However, the FGD performance has been meeting design 

requirements for SO2 removal and gypsum quality since start-up. 

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Performance Testing has been delayed due to test fuel (2.4 lb SO2/MMBtu) availability. 

As of this writing, the testing is scheduled to occur in early August 2008. 

The typical maintenance issues with starting up new systems have occurred at Belews 

Creek. These include bearings, electrical equipment, etc. While these have been 

troubling, none have resulted in forced outages of the Units. 

7. SUMMARY AND CONCLUSIONS 

The Duke Energy Carolinas’ WFGD retrofit program is well underway with all units 

operating at Marshall and Belews Creek while progress is being made toward project 

completion at the other stations. The Marshall and Belews Creek WFGDs are 

successfully operating and meeting performance guarantees since coming online in late 

2006/early 2007 at Marshall and early 2008 for Belews Creek. This paper has 

highlighted some of the unique features of the Marshall and Belews Creek 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 17 of 18 
8. 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). 

9. KEYWORDS 

Alstom Power, Duke Energy-Carolinas, Shaw, North Carolina, Clean Air, FGD, WFGD, 

Flue Gas Desulfurization, SO2, Removal, Retrofit, Open Bypass, Wastewater treatment, 

Biological, Wastewater solids removal system, Constructed Wetlands, Selenium removal, 

Belews Creek Steam Station, Marshall Steam Station, O&M, Reliability, FRP ductwork, 

Open spray tower, HDPE piping, Gypsum recycling 

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