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CFB Repowering, SCR Retrofit and Distributed Generation Projects Tabbed as Projects of the Year

Issue 12 and Volume 106.

By: Douglas J. Smith IEng, Senior Editor

Three outstanding projects, chosen by the editors of Power Engineering magazine, have been recognized as Projects of the Year 2002. The owners of the three projects—NEO California Power LLC, JEA, and Allegheny Energy Supply Co. LLC and Monongahela Power Company—received their awards in Orlando, Florida on Tuesday December 10, 2002 during the keynote session at Power-Gen International.


California Red Bluff distributed generation plant. Photo courtesy Encorp, Inc.
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NEO California Power LLC’s Chowchilla II and Red Bluff power plants, JEA’s Northside Repowering Project and the Harrison SCR project owned by Allegheny Energy Supply Co., LLC and Monongahela Power Company, have all demonstrated outstanding economical, social and environmental befits not only to the owners but also to their customers.

Two projects—the Frederickson Power combined-cycle plant owned by EPCOR Utilities Inc., and Dominion Generation’s Mount Storm Flue Gas Desulfurization Projects—received Honorable Mention awards.

Meeting California’s Energy Needs

Because of the looming California energy crisis in the summer of 2001, NEO Corporation, an independent power producer and subsidiary of NRG Energy, Inc., decided to build two distributed generation plants: Red Bluff and Chowchilla II. According to the plant’s owners, the two plants were constructed as part of


Red Bluff’s 2.9 MW Wartsila natural gas fired reciprocating engine. Photo courtesy Encorp, Inc.
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California Independent System Operator’s (Cal ISO) Summer Reliability Program that featured natural gas reciprocating engines.

In only five months, the project team of NEO, Stewart & Stevenson Distributed Energy Solutions and Encorp, designed, constructed and put the central California Chowchilla II plant into commercial operation. According to NEO, the 81,000 sq-ft plant can be operated as a peaking, intermediate or base loaded facility. All of the power, 49 MW, is generated by 16 x 3.125 MW Deutz natural gas reciprocating engines.

Less than two months after Chowchilla II went into commercial operation, the 74,000 sq-ft northern California Red Bluff plant was commissioned and put into service. Red Bluff has 16 x 2.9 MW Wartsila natural gas reciprocating engines.

A major reason the plants were designed, constructed and put into commercial operation in such a short time was the performance agreement that NEO entered into with Stewart & Stevenson. Stewart & Stevenson completely engineered the two plants and procured all of the equipment, enabling them to optimize design, construction and startup. To meet the very tight schedule the company used a Russian Antonov cargo plane to deliver the last Deutz generator from Europe to the Chowchilla II plant.

Real-time Monitoring and Dispatch

Chowchilla II and Red Bluff have a combined 100 MW available for capacity and energy transactions. Although the plants are hundreds of miles apart, the output of the two plants is aggregated. Commodity traders at NRG Energy’s Minneapolis-based trading floor regularly sell energy from the two plants into the California power grid.

Using Encorp’s Virtual Maintenance Monitor and Virtual Power Plant software packages, the Minneapolis operators can instantaneously turn on one or all 32 Chowchilla II and Red

Bluff generators. The traders are also able to push electricity into the grid and promptly let Cal ISO know that the plants are available. Because Cal ISO is provided with real-time reports on the operations and dispatching of the two plants they are also able to better manage the California grid.

World’s Largest CFB Plant in Operation

What is reported to be the world’s largest CFB plant is now in preliminary operation in Jacksonville, Florida. As part of the U.S. Department of Energy’s (DOE) Clean Coal Technology (CCT) demonstration program, JEA has repowered Unit 2 at their Northside generating station with a Foster Wheeler circulating fluidized bed (CFB) boiler, Figure 1.

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As part of the CCT program, DOE provided 24 percent, $74.7 million, toward the cost of the project. The remaining 76 percent of the project’s cost was provided by JEA. Unit 1 has also been repowered with an identical CFB; however, this was funded entirely by JEA.

Under the contract with JEA, Foster Wheeler was responsible for the extended island scope of the project. Besides designing, supplying and installing the CFB boiler, Foster Wheeler was responsible for providing engineering, procurement and construction management services for the supply and installation of the air pollution control system, chimney, limestone preparation system and ash handling system.


California Chowchilla distributed generation plant. Photo courtesy Encorp, Inc.
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JEA’s staff, supplemented by Black & Veatch through an existing alliance with JEA, was responsible for implementing the remaining portions of the project. This included upgrading the existing steam turbine island equipment, constructing the receiving and handling facilities for the fuel and reagent, and upgrading the electric switchyard and ash management system.

The Northside CFB boilers are designed to burn 100 percent bituminous coal and 100 percent high sulfur petroleum coke. In operation, the boilers typically can remove 98 percent of the SO2 without flue gas cleanup. However, to improve the overall economics and environmental performance of the unit, a polishing scrubber has been installed. This scrubber minimizes reagent consumption when firing petroleum coke, which can contain up to eight percent sulfur.

After evaluating several types of polishing scrubbers, JEA and Foster Wheeler selected a combination spray dryer and pulse jet baghouse. The spray dryer utilizes a dual fluid nozzle atomized by air. Operating together, the CFB boiler and SO2 scrubber allows the plant to capture more than 98 percent of SO2 emissions and meet the permit limits of 0.15 lb/MMBtu.


Chowchilla’s 3.125 MW Deutz natural gas reciprocating engines. Photo courtesy Encorp, Inc.
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Similarly, the relatively low furnace temperature of the CFB boiler, 1,600 F, results in appreciably lower emissions of nitrogen oxide (NOx) compared to a conventional coal-fired boiler. Nevertheless, the unit includes a new selective non-catalytic reduction (SNCR) system to further reduce NOx emissions. The permitted limit for NOx emissions is 0.09 lb/MMBtu. The new baghouse removes more than 99.8 percent of the unit’s particulate emissions.

Technical Characteristics

Enclosure walls, division walls and six wing walls provide the evaporative surfaces within the furnace. Water-cooled partial division walls divide the furnace into three zones, thus allowing for even distribution of the gas and solids to the unit’s three steam cooled cyclone separators. However, there is no superheat or reheat surface installed in the furnace.


Repowered 300 MW Northside CFB plant. Photo courtesy of Foster Wheeler.
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A CFB integrated recycle heat exchanger (INTREX), with intermediate and finishing superheater surface, receives ash from the three steam cooled cyclones. This furnace arrangement, and the heat exchanger, gives uniform heat removal and minimizes temperature variations. The furnace temperature is controlled by changing the solids loading in the furnace, by varying the primary to secondary airflow, and by changing the solids flow over the heat exchanger superheater surface.

Each steam-cooled cyclone is lined with one-inch thick refractory. To protect against erosion the refractory is held by metal studs. The density of the metal studs is higher in areas of the cyclone subjected to higher solid flows. According to Foster Wheeler, this type of refractory design is virtually maintenance free. When the cyclone separator is operated at optimum efficiency it ensures good bed quality, correct bed temperature, a low temperature drop in the furnace, and low carbon loss and emissions.

A bottom ash cooler maintains the desired furnace inventory of fuel and sorbents. It also cools the ash to a temperature where it can be handled by the bottom ash system. JEA’s CFB boiler uses a Foster Wheeler patented stripper/cooler for cooling the bottom ash. Material drained from the CFB bed is fluidized in the stripper (classifying) zone at a velocity sufficient to strip the required amount of fines from the stream. After the fines are removed they are re-injected into the furnace. The balance of the material is further cooled before being transferred to an ash drain in the floor of the last cooling zone.

These cooling zones are cooled by air from the air heater and the primary fan. Additional cooling in these zones is provided by the water-cooled heat exchangers that in turn are cooled by condensate from the discharge of the condensate pumps. According to Foster Wheeler, the stripper/cooler raises the boiler efficiency significantly by recovering the heat from the bottom ash.

The plant’s fuel system is designed to accommodate positive pressure conditions with the furnace balance point set at the cyclone inlets. The primary air fans supply seal air for the belt feeders and the air swept fuel distributors. In operation the air swept fuel distributors add horizontal momentum to the fuel to assist in injecting it into the boiler.

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Although Unit 2 is now in preliminary operation, it is still being operated as a DOE large scale CFB demonstration project. The schedule calls for the project to complete its final report to DOE by May 2004. Unit 1 is also in preliminary operation. Table 1 shows the performance data of Units 1 and 2 at 100 percent MCR when firing 100 percent petroleum coke, 100 percent coal and 70/30 percent petroleum coke and coal.


Mount Storm FGD project. Photo courtesy Lockwood Greene
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According to DOE the Northside repowering project will provide a domestic benchmark against which the U.S. utility, independent power and financing industries can assess the application of CFB technology at the 300 MW scale. It will also demonstrate the economies of scale as well as the maintainability, availability and reliability issues related to utility scale CFBs.

Harrison Station Unit 1 SCR Project

Compared to the majority of today’s coal-fired SCR retrofits, the 640 MW Harrison Station Unit 1 SCR project is atypical. The Harrison project involved the cooperation and the resources of three primary parties:

  • Allegheny Energy the plant owner, which served as the overall project manager.
  • Parsons E&C, which served as the traditional engineer/construction project manager with responsibility for project management, engineering, design, procurement support, schedule and cost control, construction management and startup support.
  • Haldor Topsoe, which provided the SCR catalyst, the process technology and the process performance guarantees.

According to Parsons E&C, this approach allowed Allegheny Energy to achieve a facility configuration that is fully responsive to the operational requirements of the plant and Allegheny’s long-term generation objectives.

Design Features

At Harrison the SCR system has been designed to operate with bituminous coal with a sulfur content up to 3.8 percent by weight. It has also been designed to achieve greater than 92 percent NOx removal with no more than 2 ppm ammonia slip. This project is reported to be the first SCR installation in a U.S coal-fired plant to utilize a Haldor Topsoe catalyst. The corrugated honeycomb arrangement of the catalyst, with fiber reinforcing, is lightweight and resistant to thermal shock.


Harrison Station Unit 1 SCR retrofit. Photo courtesy of Parsons E&C
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Parsons E&C designed the SCR reactor with the ability to accommodate catalysts from most of the major manufacturers. In addition, more catalyst surface can be added to the SCR reactor if required. The catalyst can be in the form of deeper catalyst modules and/or an additional catalyst layer.

The inlet duct to the reactor has been designed for optimal conditioning of the flue gas. To accomplish this the inlet NOx and temperature profiles, particulate matter removal, ammonia mixing and uniform flow into the top of the catalyst bed were all homogenized. Haldor Topsoe conducted flow model tests to ensure proper mixing and minimize pressure losses through the SCR system.

To avoid the risks and regulatory burden associated with the storage of large quantities of anhydrous ammonia, the plant is producing its own ammonia. A system that generates ammonia from urea now allows the plant to minimize the amount of ammonia stored on-site. According to Parsons E&C, the urea-to-ammonia facility is the first of its size to be installed in the U.S. The plant has three reactor vessels each capable of producing 1,800 lb/hr of ammonia.

Construction Challenges

Retrofitting the SCR on Unit 1 at Harrison presented many challenges, including spatial constraints and a mandate for the plant to begin earning NOx credits for the 2002 ozone season. Planning the outages to very tight schedules was also very challenging.

Because of limited space behind the boiler house, the project team constructed a platform above the existing flue gas ducts and FD fan rooms. Drilling for the platform’s foundations was also complicated as the platform was located over an area that had originally been used as a landfill during the plant’s construction. The area was also confined by a SO2 scrubber. As a result the subsurface was full of unknown obstructions. The deck is 70 ft high by 750 ft long and spans the full length of the three-unit boiler house.


Frederickson Power’s Tacoma combined-cycle power plant. Photo courtesy Black & Veatch.
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During a regular scheduled outage the two ID fan rotors and motors were replaced and major structural modifications were made to the existing boiler house. These modifications were necessary to take into account the higher pressure drop and horsepower of the new system. The structural modifications were required before the SCR’s dampers and inlet and outlet dampers could be installed.

Through the application of new technologies, innovative design and construction techniques, the Harrison SCR Unit 1 project was constructed, commissioned and successfully put into commercial operation for the 2002 ozone season. This not only was a benefit to the plant’s owner, it also benefited the community. During the 2002 ozone season the SCR achieved it performance goals of 92 percent NOx removal with less than 2 ppm ammonia slip.

Honorable Mentions

Frederickson Power’s 249 MW combined-cycle power plant in Tacoma, Washington, received an honorable mention because of the project’s unique design requirements. Originally the plant was scheduled for completion in December 1996 but work was stopped in 1995.

When work was stopped on the plant, 80 percent of the design had been completed and 40 percent of the plant had been constructed. As a result, the new joint venture project team of Black & Veatch and Kiewit Industrial Company (KBV) faced many design and construction challenges. One of KBV’s first tasks involved analyzing the design and procurement of plant systems to accommodate the combustion and steam turbines being used for the restarted project. Another important task was to review the need for any new permit and/or code requirements and implement the necessary changes.

The natural gas-fired one-on-one combined cycle plant has a General Electric 7FA gas turbine generator and a General Electric reheat, single low-pressure steam admission condensing, axial exhaust steam turbine generator. A Nooter Eriksen three-pressure, heat recovery steam generator (HRSG) supplies steam to the steam turbine.

Even though KBV added a number of upgrades to the plant’s original design the project team was able to complete the project 19 days ahead of schedule. Design improvements included modifications to the HRSG reheat coils to accommodate increased output of the gas turbine and adapting the bypass design, steam systems and condenser to eliminate steam injection for NOx control. KVB also added an evaporative cooler.

These upgrades have enabled the plant to achieve an overall three percent efficiency improvement over that of the original plant’s design. The Frederickson combined-cycle power plant, with a capacity of 249 MW, was completed and put into commercial operation in July 2002. According to Kerry Erington, project manager, Black & Veatch, the project has met or exceeded the project’s performance, output and efficiency goals.

Mount Storm FGD Project

Dominion has been awarded an honorable mention for Mount Storm’s installation of a flue gas desulfurization (FGD) system on two 530 MW units. Originally the plan was to construct two duplicate FGD systems, one on each unit. In addition to Dominion, which was responsible for the stack modifications, primary power supply systems and relocating of facility services, Marsulux Environmental Technologies and Jones LG, a subsidiary of Lockwood Greene, were also major participants.

Marsulux Environmental Technologies supplied the FGD process related equipment and was also responsible for the conceptual design, startup and testing. Jones LG carried out the detailed design, procured the balance-of-plant equipment and performed the construction.

A substantial cost savings, and a reduction in the schedule, was achieved by replacing the original alloy lined carbon steel of the scrubber vessels with a concrete shell covered with ceramic tile liner. The scrubber dome material was also changed from alloy lined carbon steel to fiber reinforced plastic on a steel superstructure. Total capital cost of the project was $121 million. This included $91 million for the engineering, procurement and construction portion of the contract.

The total FGD project cost is reported to be the lowest cost scrubbing system per MW installed in the U.S. Construction of the project started in March 1999 and it was put into commercial operation in February 2002.