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Case Histories: Asheville Power Station’s Retrofit First to Meet North Carolina’s Clean Smokestacks Act

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Case Histories: Asheville Power Station’s Retrofit First to Meet

North Carolina’s Clean Smokestacks Act

09/01/2006 | Steve Cisek, Project Manager, WorleyParsons

Asheville Power Station’s Unit 1 in Arden, North Carolina, was the first coal-fired unit to be modified with

a flue gas desulphurization (FGD) system and placed in service to meet the clean air requirements of the

state’s Clean Smokestacks Act. As of November 16, 2005, at least 97% of the sulfur dioxide that had been

emitted from the plant’s boiler is now being removed. The FGD system for Unit 2, the second FGD to be

placed in service in the state, went into operation May 17, 2006.

Asheville is part of an $82 million Clean Smokestacks Program contract awarded by Progress Energy

Carolinas in 2002. The goal of the program is to provide air quality control systems for a number of the

company’s coal-fired units throughout the state.

Asheville’s Units 1 and 2 are drum-type units rated at net generating capacities of 200 MW and 194 MW

respectively. They include a single wall-fired boiler and reheat steam turbine with auxiliary facilities

common to both units. Unit 1 went into commercial operation in 1964; Unit 2 joined it in 1971.

The retrofit project encompassed the installation of a wet FGD system for each unit with new individual

flues enclosed in one common concrete stack. In addition to the FGD work, selective catalytic reduction

(SCR) systems were added to both units with a common two-unit ammonia supply system.

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The SCR systems were designed to remove a minimum of 90% of nitrogen oxides from the boiler flue gas.

Unit 2 was converted to balanced-draft operation. Asheville’s Unit 1 SCR is on schedule to be operational

by April 2007.

In addition to the FGD and SCR systems retrofit, a generator step-up transformer was installed on Unit 1,

and SO mitigation systems were installed on both units. Larger steam coil air heaters to raise the flue

gas temperature above the acid dew point were also installed on the units. Prior to this addition, the low

flue gas temperature led to corrosion of Unit 1’s precipitator and ductwork. This retrofit required

installation of a new high-efficiency electrostatic precipitator (ESP) to replace the existing ESP.

Meeting the aggressive in-service dates, which were tied to Progress Energy Carolinas’ planned

maintenance schedules, required close coordination and cooperation of the project team. That team

consisted of WorleyParsons, The Babcock & Wilcox Co., and Fluor.

Challenging schedule dates and the need to reduce overall cost while maintaining plant operations

throughout the erection, required the team to follow tight sequencing of an accelerated schedule of 26

months (27 to 30 months is the norm). Efficiency was enhanced by the use of an integrated 3-D model of

the plant with continual real-time input from the entire team. As a result, it allowed for a smooth

transition from engineering and design to construction execution.

Communication

Communication among project team members and the client was critical in order to minimize rework and

to address concerns in a timely manner. Weekly teleconferences were rigorously held to review the

critical path schedule and disposition of open action items. Additional weekly teleconferences with the

client’s lead engineers discussed drawing/document review status, comments, and technical issues.

Biweekly 3-D model reviews were conducted via the Internet to address engineering and design issues

and constructability reviews. Constructability reviews were also held during monthly site meetings with

all interested plant personnel attending. A site-initiated request for information (RFI) system, requiring

responses within 24 hours of receiving an RFI, and a project execution plan to formalize and standardize

common processes and procedures helped the team meet critical workflow milestone targets.

Schedule Milestones

In order to accomplish the Unit 1 FGD system tie-in within a two-week outage starting in November 2005,

modifications to the existing balance-of plant-systems, such as the air and water systems, were made

during a six-week turbine outage that started September 18, 2004. Replacement of the unit auxiliary and

start-up transformers were completed during this outage.

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The Unit 2 FGD and SCR systems were tied into the existing plant during a six-week turbine outage

starting April 29, 2006. Due to the balanced draft conversion of the boiler, the critical path activity

included stiffening of the existing electrostatic precipitator. All Unit 2 commissioning activities were

completed 36 hours ahead of schedule.

The chimney and the FGD absorber towers had to be constructed within the same time period. This was

accomplished by starting the chimney work a few weeks earlier than the first absorber tower. To safely

allow for parallel construction, a certified safety barrier was placed over the scaffolding of the absorber

tower. With the chimney crew finishing their work earlier than the absorber tower crew, the absorber

tower safety barrier was raised in time to support the next day’s chimney and absorber tower

construction activities.

The FGD building was offset to the west of the coal pile and required long flue gas duct runs to the inlet

of the absorber towers. To facilitate the construction schedule and minimize construction costs, the

ductwork was designed to maximize shop fabrication while meeting truck shipping limits.

Special permitting and escorts were required by the trucking companies to transport several sections of

the oversized ductwork sections from Alabama to the plant in North Carolina. The shop fabrication and

extra shipping costs were more than offset by savings in field installation costs.

Due to the increased draft needs for the FGD and SCR systems, the induced draft fans for Unit 1 had to

be replaced. Because Unit 2 was converted to balanced draft, new induced draft fans were installed. To

minimize outage time, the fan foundations, fans and motors, and interconnecting ductwork were

procured, engineered, installed, and commissioned as pre-outage activities.

Engineering and Design Considerations

A process selection study comparing wet with dry FGD systems was completed in 2003. Results of the

study showed marginal but positive benefits to using a wet limestone forced-oxidation process.

Two key factors that contributed to Progress Energy Carolinas’ decision to select the wet FGD system were

cost savings and efficiencies in construction that will carry over to the other coal-fired plants targeted to

have wet FGD systems installed. In addition, the gypsum by-product of a wet FGD process can be sold for

commercial use, thus lowering disposal costs. In contrast, a dry FGD system’s by-product is unusable and

must be disposed of in a landfill.

Other benefits to selecting a common, wet FGD system — from engineering, operation, and maintenance

standpoints — included:
The opportunity to apply lessons learned during engineering and construction of the early units to

subsequent units.

Better fuel flexibility, equipment and spare part cost savings, and enhancements in the operation

and maintenance of the FGD systems because they’ll be the same for all Progress Energy Carolinas’

plants.

To facilitate FGD system operation and maintenance, a facility arrangement was developed that colocated all 1 and 2 units and common systems into a single FGD system area.

Engineering and design of the foundation for the new chimney and its specification required the

vendors to furnish not-to-exceed loads in their proposals. The design was based on the successful

chimney vendor’s loading. For the major FGD system equipment, including the absorber tower, the notto-exceed loads were supplied by the tower vendor and Babcock & Wilcox.

To maintain the entering flue gas temperature to the SCR reactor within the limits required by the SCR

catalyst supplier, a portion of the Unit 1 economizer tubes was removed. The remaining tubes were

jumpered to raise the boiler exit gas temperature. Due to the boiler configuration and available space, it

was not possible to use economizer bypass dampers. Because Unit 2 had a different boiler design than

Unit 1, it was possible to regulate the flue gas temperature going to the reactor economizer by installing

bypass dampers.

Project Details

Phase 1 of the project began in early 2003 and consisted of securing the location of the FGD and SCR

systems and the limestone- and gypsum-handling systems. At the same time, preparation of preliminary

general arrangements, piping and instrument drawings and electrical one-line diagrams, major

equipment sizing, conceptual engineering and construction scheduling, estimated bulk material

quantities, and estimated project cost were completed. Phase 2 began in September 2003 with detailed

engineering and design, procurement, construction, and commissioning of the FGD, SCR, and balanceof-plant systems.

Given the location of the plant in the far western portion of North Carolina and its contribution to the

local electrical grid, maintaining at least one of the units in service at all times was critical. Minimizing

single-source failures was a primary consideration in systems engineering and equipment redundancy.

Even though one absorber tower could have been used for both units, each unit has its own absorber

tower and associated support systems.
The original chimneys for Units 1 and 2 were abandoned and will be demolished in the future. Because

of the high moisture droplet content of the flue gas exiting the absorber towers, the chimneys cannot be

used with a wet FGD system.

Because the plant is located near a residential area, the FGD system equipment was enclosed in a

building to mitigate noise. The enclosure allowed for construction during the winter months and

eliminated the need for electrical heat tracing of piping. It also minimized low-temperature concerns

associated with FGD system rubber-lined equipment and piping during construction and operation.

Water and Compressed Air Systems

Redundant pumps were provided for all balance-of-plant water systems. Fire water and potable water

are supplied from existing fire water and potable water systems; make-up water is pumped from on-site

Lake Julian. The lake is also the source of the plant’s cooling water. Service and instrument air is provided

by two new 100% capacity air compressors, and the FGD compressed air system is cross-tied to the

existing plant service air system.

Limestone and Gypsum Handling

Limestone is delivered by truck to the limestone storage pile. The limestone-handling system is a singletrain system moving limestone from the storage pile to a crusher and then to the limestone day bins. A

single-train system was specified because the limestone day bins were sized to provide 48 hours of

inventory, thereby maintaining limestone feed to the process while conveying system maintenance is

performed.

A backup procedure uses crushed limestone delivered by a pressure differential truck and discharged

directly into the limestone day bins. Motor and belt repair can be done within the storage time of the

redundant limestone day bins. Due to long delivery times for the limestone, spare gear boxes were

purchased.

Gypsum handling is accomplished via a single-train system, which moves gypsum from the four

dewatering centrifuges to the storage dome. As with the limestone-handling system, to ensure

availability of the gypsum-handling system, spare gear boxes were purchased. Motor and belt repair can

be done within the storage time of the process tanks.

If the gypsum conveyor is out of service the gypsum can be moved directly to the gypsum storage dome.

The dome was installed over the gypsum pile to avoid excessive moisture from rainfall. It has a concrete

floor to facilitate removal of the gypsum by a front end loader into trucks.
A truck scale was installed to weigh incoming trucks delivering coal and limestone, and outgoing trucks

removing gypsum. A truck wash station was installed to wash the truck bed after a coal delivery to

minimize carbon contamination of the gypsum. Because the trucks travel through a neighboring

residential area, a truck’s tires are washed before the truck leaves the plant.

Auxiliary Power Distribution Systems

The existing unit auxiliary transformers and the common start-up transformer were replaced with largercapacity three-winding transformers. This was necessary due to the increase in plant electrical load from

the FGD, SCR, and balance-of-plant system’s equipment and new induced draft fans for each unit. New

6.9-kV and 480-volt distribution systems were provided for the FGD, SCR, and balance-of-plant systems’

equipment. The existing plant’s 4.16-kV system is now fed from the new transformers.

An existing Honeywell distributed control system was upgraded and expanded to accommodate the I/O

for the FGD, SCR, and balance-of-plant systems. In addition, the control room was expanded for the

additional HMI (human-machine interface) screens and new control console.

Wastewater Treatment

The primary wastewater treatment system consists of a clarifier for solids removal, redundant filter

presses, and pH control using acid and caustic metering systems. All of the absorber tower blowdown is

mixed with the dilution water. This lowers the chlorides concentration and temperature to a level

acceptable to the secondary treatment system. The primary wastewater treatment system is enclosed in

a building for the same reasons that the FGD system equipment is: mitigating noise and minimizing heat

tracing.

A unique aspect of the wastewater treatment system is the use of a constructed wetlands treatment

system (CWTS) based on a pilot plant implemented at Clemson University in March 2003. Funding for the

pilot plant was shared by Progress Energy Carolinas and Duke Energy. The CWTS is a secondary

wastewater treatment system configured to remove selenium and mercury from the FGD system

blowdown. It is essential for ensuring that the plant achieves effluent limitations established under the

National Pollutant Discharge Elimination System, the Clean Water Act, and in accordance with North

Carolina State wastewater discharge limits.

In order to have the waste treatment facilities on-line by November 2005, the waste treatment building

was ordered prefabricated, and the equipment support steel was designed as free-standing structures

internal to the building. The elimination of interfaces with the prefabricated building supplier minimized

the prefabricated building supplier’s fabrication time and maximized site equipment installation time.
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The primary wastewater treatment system, previously described, has a clarifier to remove suspended

solids, a chemical feed systems to adjust pH, and mixing facilities to dilute the treated flow with service

water. Dilution is required to cool the treated flow to 104F – 105F and to lower the chloride concentration

to 6,000 ppm levels acceptable to the CWTS plants.

The CWTS was designed to treat approximately 0.54 million gallons/day at the average projected FGD

wastewater flow of 375 gallons/minute (75 gallons/minute FGD blowdown and 300 gallons/minute

dilution water). Effluent from the primary treatment system initially enters two equalization basins for

cooling, mixing, concentration equalization, and secondary settling of solids.

Water from the equalization basins is split into two equal flows, each entering a treatment train. The

treatment trains consist of two 0.83-acre bulrush wetland cells, a 0.14-acre rock filter, and a 1.11-acre

cattail wetland cell. Total treatment area is 6.5 acres with a hydraulic retention time of eight days based

on the average projected flow. Design of the CWTS will achieve the treatment discharge objectives for

mercury (0.00063 mg/L) and selenium (0.263 mg/L). The oxidation-reduction (redox) potential of the cells

is monitored to ensure that the needed biological, chemical, and physical processes are taking place.

Progress Energy Carolinas and WorleyParsons, together with their project team members, successfully

met the required in-service dates for the FGD and SCR systems. Effective communication, aggressive

scheduling, and lessons learned from engineering and construction have allowed the plant to achieve its

sulfur dioxide and nitrogen oxide reduction targets. Safety was a priority, and because of this the project

was finished with zero lost time accidents and a recordable incident rate of 0.46.

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