By Douglas J. Smith, IEng.
- Delesto 2 Cogeneration Project, Delfzijl, The Netherlands.
- Associated Electric Cooperative’s New Madrid Unit 2 SCR retrofit, Missouri.
- Consumers Energy’s “Decommissioning Power System” at Big Point Nuclear Power plant, Michigan.
Largest Cogeneration Plant in the Netherlands
The Delesto 2 cogeneration plant is reported to be the largest cogeneration plant in the Netherlands and also one of the largest in Europe. According to Marcel Bartelink, plant manager of Delesto, the plant has operated at 97.2 percent availability during the first year of its operation. During that time, there was only one forced outage, caused by a faulty solenoid valve.
Delesto 2 cogeneration plant, Delfzijl, The Netherlands. Photograph courtesy of Akzo Nobel. Click here to enlarge image
Delesto 2, a 360 MW cogeneration plant, supplies electricity and process steam to Akzo Nobel’s chemical complex and its surrounding facilities. The balance of electric power is exported to the Dutch grid. The plant, located in Delfziji in the Netherlands, is owned by Delsto B.V., a joint venture of Akzo Nobel, one of Hollands’ largest conglomerates, and ESSENT, a Dutch multi utility company.
General Electric (GE) reports that the Delesto 2 project is their first turnkey cogeneration project in Western Europe built under severe specification guidance and Six Sigma Quality requirements. It is also the first cogeneration project to use GE’s 9FA gas turbine. The Delesto 2 cogeneration plant consists of a MS9001FA gas turbine with Dry Low NOx (DLN) combustion system and a 120 MW steam turbine generator. The 50 Hz gas turbine has an ISO rating of 226 MW.
Process steam, and steam for electric generation, is produced by a natural circulation, three drum, heat recovery steam generator (HRSG). Standard Fasel Lentjes B.V., a Dutch company, designed, manufactured and erected the HRSG.
Besides having to meet very stringent environmental emission standards, Delesto 2 was also required to meet acoustic levels of 80 dBA one meter from any equipment or pipeline. “It’s one of the quietest plants of its size in the world,” says Ronald Boardman, senior project manager for GE Power Systems.
Operation of Delesto 2 has been fully integrated with three existing GE MS6001B gas turbines. With the integration of the two plants, Delesto is now able to produce 530 MW of electric power and 1.56 million lb/hr of process steam. This integration substantially improves the total operational flexibility of the plant.
Prior to their installation at Delesto 2, GE’s 9FA gas turbines were required to be taken out of service after 8,000 hours of operation for inspection. However, at Delesto 2, the gas turbines operated for 12,000 hours before their first routine inspection. When the gas turbine was shut down, the subsequent inspection of the combustion section revealed no problems.
” The facility is achieving new levels of availability, and noise emissions, and is a showcase for advanced congeneration technology in Europe,” says Bartelink. Under a voluntary agreement with the Dutch government, Akzo Nobel had agreed to reduce its energy consumption. With Delesto 2’s high level of fuel efficiency, Akzo Nobel is now far exceeding its voluntary goals.
Besides high availability and reliability, the following results were also achieved:
- Improved energy efficiency.
- Less fuel consumption.
- Less CO2 emissions.
- Substantial NOx reduction.
“With these results, Delesto has proven that cogeneration is the most cost effective way to generate power and heat, substantially meeting actual global environmental and energy policies,” says Bartelink.
SCR retrofit underway at New Madrid power plant. Photograph courtesy of Black & Veatch. Click here to enlarge image
Associated Electric Cooperative, Inc. (AECI) has retrofitted a selective catalytic reduction (SCR) system to Unit 2 of its New Madrid power plant. According to AECI, the project constitutes the world’s first application of SCR to a 100 percent Powder River Basin (PRB) coal-fired boiler.
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The New Madrid power plant is located in southeastern Missouri on the Mississippi River, south of the town of New Madrid. New Madrid has two identical 600 MW units with Brown Boveri steam turbines and Babcock & Wilcox cyclone boilers. Originally, the boilers were designed to burn Illinois coal, but in 1994 they were converted to burn 100 percent low sulfur PRB coal.
In order to comply with the requirements for NOx reductions of Title IV, Phase 2 of the 1990 Clean Air Act Amendments, AECI hired Sargent & Lundy to help in evaluating different scenarios for reducing NOx emissions at the New Madrid plant. The following options were evaluated by AECI and Sargent & Lundy:
- Overfire air.
- Low NOxburners.
- Selective non-catalytic reduction (SNCR).
- Selective catalytic reduction (SCR).
- Hybrid SNCR/SCR.
- Coal reburning.
- Natural gas reburning.
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After reviewing the different options it was determined that adding an SCR to Unit 2 would be the most economical compliance method. This does not imply, however, that SCR retrofits are less costly than other methods for all applications. According to Sargent & Lundy, because of the quantities of NOx removal required at the New Madrid site, it was more economical to use SCR technology.
Consumers Energy installed a new substation to bring in off-site power. Photograph courtesy of Sargent & Lundy LLC. Click here to enlarge image
The turnkey specification for the SCR Unit 2 retrofit was prepared in late 1997. Although AECI did not dictate any specific equipment arrangement, it did require the equipment vendors to supply data on draft pressure losses, auxiliary power requirements, exit gas temperatures and air heater leakage for their equipment. This information was essential for AECI to fully evaluate the different proposals submitted.
In order to optimize overall unit performance while achieving aggressive NOx emission reductions, AECI’s specification gave the bidders the flexibility to offer different configurations as long as it met the performance criteria. The only constraints set by AECI were the use of anhydrous ammonia and the minimum pitch for the catalyst. AECI did not specify the type of catalyst.
After evaluating the six proposals submitted for the SCR retrofit, AECI awarded the contract to a joint venture of Black & Veatch Construction, Inc. (BVCI) and J. S. Alberici Construction Company (JSA). AECI retained Sargent & Lundy as the owner’s engineer.
The joint venture of BVCI and JSA replaced the plant’s existing tubular air heater with a single, SCR ready, regenerative Ljungstrom air heater. With the old air heater the outlet flue gas temperature was 350-360 F. With the new air heater, however, the outlet temperature has been reduced to 280 F.
In addition to reducing the flue gas outlet temperature, the regenerative air heater minimized system losses. As a result, forced draft fan upgrades or booster fan additions were not required. Because the regenerative air heater was designed and manufactured ready for the installation of a SCR, the potential for air heater fouling was greatly reduced. Figure 1 shows the path of the flue gas as it passes through the unit. The system has been designed for 100 percent bypass during startup and for periods when the SCR is out of service.
The homogeneous ceramic honeycomb catalyst, manufactured by Cormetech, has a pitch of 9.2 mm and an open area of 80 percent. As a result, the pressure drop and ash buildup in the catalyst is minimized. The ammonia injection grid, with 60 controllable zones, assures excellent coverage and tuning of the SCR. It is possible to make adjustments and fine tune the system while the unit is in operation.
To simplify tuning of the ammonia injection grid (AIG ) and to assure good coverage and mixing of the ammonia and the flue gas, the velocity profile at the entrance to the AIG is controlled at ±10 percent across the entire flue. A low pressure loss flow distribution device controls the velocity.
Ammonia Control and Supply
The anhydrous ammonia plant, supplied by Peerless Manufacturing Company, is designed for a maximum ammonia flow of 3,560 lb/hr (Figure 2). Ammonia for the facility is delivered either by truck or rail, and is stored at the site in three 80,000 gallon ammonia storage tanks, which is sufficient for 14 days of SCR operation.
Ammonia injection is controlled by two dedicated NOx analyzers, one at the SCR inlet and the other at the SCR outlet. Multiple samples of the flue gas at inlet and outlet are averaged. A NOx monitor also monitors the flue gas in the bypass ducts.
When first put into operation in February 2000, it took approximately 40 minutes for the catalyst to reach operating temperature. On reaching its operating temperature, the ammonia was introduced into the reactor. However, because of the vapor pressure in the ammonia storage tanks, there was no need to pump the ammonia. Startup of the ammonia system occurred over a three day period.
Because of inadequate glycol flow to the vaporizers, there was an initial problem in obtaining steady ammonia flow. The problem-a plugged strainer-was rectified by utilizing the plant’s existing coarser strainer.
AECI also determined that continued operation using only the vapor pressure in the ammonia storage tanks at atmospheric pressure was inadequate for effectively controlling the ammonia control valve. This was resolved when one of the ammonia transfer pumps returned to service.
During the startup period, there were several trips of the excess ammonia flow valves. Primarily this occurred when filling the liquid line from the ammonia tanks to the vaporizing skid. An evaluation of the problem determined that the problem could be resolved by opening multiple ammonia storage tanks.
Since returning to commercial operation in early 2000, New Madrid’s Unit 2 has achieved NOx reductions of up to 93 percent. The unit’s heat rate has also improved. A recent inspection of the catalyst and the air heater revealed no accumulation of ash on the catalyst and no evidence of air heater fouling by ammonium bisulfate deposits.
Big Rock Decommissioning
Decommissioning of Big Rock Point Nuclear Power plant, the U.S’s oldest and longest running nuclear plant, started in September 1997 and is scheduled to be completed by 2004. In 1991, The American Nuclear Society designated the plant a Nuclear Historical Landmark.
Although the plant’s operating license was not due to expire until the year 2000, Consumers Energy, the plant’s owners, made the decision to remove the plant from service on its 35th anniversary in August 1997, and start decommissioning.
Safety is a priority in the decommissioning and dismantling of a nuclear power plant and one of the critical issues is to ensure that all equipment and electric cables are de-energized before any work begins. To eliminate this risk, the project team decided to install a “Decommissioning Power System (DPS)” before commencing any work on the plant or its equipment. Further safety measures included designating the DPS as “the yellow system” where all of the live systems and their components are coded yellow.
Design and Construction of the DPS
According to Consumers Energy and Sargent & Lundy LLC’s project team, because of limited industrial experience in designing and installing a DPS, the Big Rock Point project has set an effective precedent for future nuclear decommissioning.
Because decommissioning could not progress without the DPS, its design and construction was a priority. Time was of the essence. However, many of the new systems for supporting the decommissioning tasks still needed defining when the unit was removed from service. Therefore, an extremely aggressive schedule was developed for the DPS by the project team.
The DPS was installed in two phases. Phase I included installation of the outdoor equipment while phase II included the indoor installation. Phase II was further subdivided into three priorities. Priority 1 encompassed the reactor building’s essential loads and a new diesel backup system, priority 2 encompassed the turbine and service buildings and priority 3 covered the re-powering of the balance of plant equipment needed for decommissioning.
To speed up the schedule and reduce the costs of phase I, the project team decided to use equipment already in storage at Consumers Energy’s facilities. With winter approaching, priority was given to the installation of most of the outside equipment. This included the installation of a new 46 kV to 8.32 kV substation and 8.32 kV switchgear. The conduit and cable for five new 8.32 kV, 480 V transformers was also installed.
According to the project team, the major challenge they faced was the expeditious and accurate identification of loads for repowering. The team also implemented conservative engineering decisions by over-sizing the equipment’s design. This would minimize re-engineering and rework should unforeseen additional loads be identified in the future.
In addition to over sizing all of the transformers and feeders, spare 15 kV fusible switches were also installed. The DPS was designed as a radial feed system with two 100 percent redundant 8320 V feeders from the 46 kV substation to the distribution switchgear.
As an additional safety precaution, all 8320 V distribution equipment and connecting conduit was located outside of the building. The 480 V service conductors from the pad mounted transformers to the 480 V distribution panels, located inside of the building, were routed in rigid steel conduit to provide additional protection from damage.
Finally, as an added safety measure, all of the lighting was re-powered so that the concrete structures, which contained the original embedded conduit and cable, could be demolished without the chance of encountering any energized cables.
According to Greg Withrow, Consumers Energy’s engineering manager for the Big Rock Point project, it would have been better if the design and procurement of the DPS had started earlier. Costs would have been reduced. Still, under the circumstances, the DPS project went well, said Withrow.
Besides the three award winning projects, the editors of Power Engineering magazine have given “Honorable Mention” awards to five projects:
- Quezon Power Project, Philippines.
- Mauritius Renewable Fuels Cogeneration Plant, Mauritius.
- ECKG Kladno Project, Kladno, The Czech Republic.
- Sidi Krir 1&2 Power Plant, Alexandria, Egypt.
- Hines Energy Project, St. Petersburg, Florida.
First BOO Philippine Power Plant
Quezon power project, Quezon Province, Lazon Island, Philipppines. Photograph courtesy of Bechtel. Click here to enlarge image
The Quezon Power Project, located on the east coast of Quezon Province, Lazon Island, in the Philippines, is reported to be the first Philippine build-own-operate (BOO) independent power plant (IPP). In addition, it is the first IPP project financed with neither government guarantees nor sovereign support.
Quezon Power (Philippines) Limited Co. (QPPL), the project’s owner, is a partnership of four companies: The International Generating Co (a joint venture of Shell Generating Ltd. and Bechtel Enterprises Holdings, Inc.); Global Power Investments; Ogden Energy Group, Inc.; and PMR Limited, Co.
The 440 MW pulverized coal-fired unit was constructed under a lump sum turnkey project by Overseas Bechtel Inc. and Bechtel Overseas Corp. Because of the plant’s remote location, the project’s developers faced many challenges, from poor transportation infrastructure to typhoons and personnel security.
To protect the plant from storm surges, approximately 1.2 million cubic meters of excavation and backfill was used to raise the plant’s site 10 meters. Even with the many challenges faced by the project’s developers, the plant was completed within the guaranteed 36-month schedule and on budget. The Quezon plant went into commercial operation on May 30, 2000.
Bagasse-fired Cogeneration Plant
Mauritius renewable fuels cogeneration plant. Photo courtesy of Duke Enegineering & Services. Click here to enlarge image
In 1998, Duke Engineering & Services (DE&S), Charlotte, N.C., was awarded a $74 million turnkey contract to design and construct a two unit renewable energy cogeneration plant on the island of Mauritius. Mauritius, located in the Indian Ocean, is approximately 2,000 miles northeast of South Africa. Baggasse, the fuel used in the plant, is a by-product from the processing of sugar cane.
The 70 MW cogeneration plant is owned by Compagnie Thermique de Belle Vue Limited, a partnership of Harel Freres Ltd., Mauritius, SIDEC, France and the Sugar Investment Trust of Mauritius, a sugar cane growers benevolent association.
Constructed on the grounds of a private sugar estate, the plant is the largest renewable energy plant in Mauritius. From June through December, when the sugar cane is harvested, the plant’s fuel is bagasse. In the off season, January through May, the plant burns coal.
In commercial operation since May 2000, the plant supplies 10 MW of electricity to the local sugar mill. The remainder of the electric power is dispatched into the local electric grid. Not only is the plant helping to satisfy the electric requirements of Mauritius, it also provides economic and environmental benefits to the island and the local sugar cane producers.
Eastern Europe’s Largest IPP
ECKG Kladno project, Kladno, Czech Republic. Photograph courtesy of ALSTOM Power. Click here to enlarge image
The ECKG Kladno project is located in the city of Kladno, not far from Prague, in the Czech Republic. According to the plant’s developers, the project is central and eastern Europe’s largest independent power project (IPP) and is the second largest power plant constructed in the Czech Rebulic since 1989.
NRG Energy Inc. partnered with El Paso Energy International, Nations Energy Corp., Teco Power Services Corp., Mosbacher Power Partners, L.P. and STE to upgrade, refurbish and expand the existing Kladno power plant. The project’s focus was on maintaining thermal efficiency of the plant while meeting new Czech government environmental emissions standards.
Besides supplying electricity to a nearby industrial complex and a local distribution company, the plant also supplies steam and hot water to the city of Kladno’s district heating system and thermal energy to an industrial complex.
Refurbishment of the plant involved the complete overhaul and upgrading of the old power plant and its equipment. A new baghouse and automatic “deNOx” system was installed for environmental control. ALSTOM Power, Windsor, Conn., supplied the plant’s two new circulating fluidized bed boilers (CFB). The boilers burn locally mined hard and brown coals.
ALSTOM Power also supplied two Stall VAX steam turbines, a GT8C gas turbine, heat recovery steam generator, electric generators and the plant’s control system. The expansion added 271 MW of coal-fired generation, 67 MW of gas-fired peak generation and seven MW from the back pressure steam turbine. Natural gas is the primary fuel but light oil can be used as a back-up fuel.
Completed in January 2000, the $401 million ECKG project was the fifth largest infrastructure investment in the Czech Republic’s history and is the first major power plant to be project financed in Eastern Europe.
Sidi Krir: Egyptian Power
Sidi Krir 1&2 power plant, Alexandria, Egypt. Photograph courtesy of Bechtel. Click here to enlarge image
The Sidi Krir 1&2 power plant is located on the Mediterranean Sea approximately 30 km west of the city of Alexandria, Egypt. In addition to the power plant, the project also includes a housing complex for the plant’s employees, various shops, a mosque, a nursery school, entertainment, a post office and municipal facilities.
Power Generation Engineering and Services Company (PGESCo), a joint stock company incorporated in Egypt in 1993, was awarded the Sidi Krir 1&2 power plant contract by the Egyptian Electricity Authority (EEA). Under the contract PGESCo was responsible for design, procurement, construction and project management.
In order to duplicate the same power block for future power projects, the Sidi Krir project used a modular design. The turbine generator, boiler, control system, water treatment and 220 kV switch yard are constructed as modules. However, there is only one centrally located control room for the two units. Each Sidi Krir unit includes a 320 MW condensing steam turbine generator and a duel fuel, natural gas or No. 6 oil, pressurized boiler. A single stack serves both units. Unit 1 went into commercial operation on October 12, 1999 and Unit 2 on February 28, 2000.
Input from Environmental Advisory Group
Hines 520 MW combined-cycle power plant, Bartow, Florida. Photograph courtesy of Siemens Westinghouse. Click here to enlarge image
Hines Energy Project, a 520 MW combined-cycle power plant, is located in Bartow, Florida. The plant, owned by Florida Power Corporation (FPC), started construction in 1997 and went into commercial operation on April 23, 1999.
Overland Construction Inc. and Black & Veatch provided project management and general construction services. Siemens Westinghouse supplied the plant’s two 160 MW, W501F gas turbines, the 200 MW steam turbine and the two triple heat, natural circulation, unfired heat recovery steam generators. Natural gas is the main fuel. However, the plant can use light oil as backup. The Hines plant has been designed for future conversion to coal gasification.
Unique to the Hines project was the use of an Environmental Advisory Group (EAG). FPC and the EAG worked closely in evaluating potential sites and in the selection of the Bartow, Polk County site. The EAG, consisting of eight people, represented environmentalists, educators and community leaders from throughout the state.
The power plant site is home to many species of wildlife including alligators, bobcats, turtles and birds. The 8,000-acre site is licensed for 3,000 MW. According to Florida Power, the Hines plant is the cleanest and most efficient plant on their system. Environmental controls supplied by Siemens Westinghouse limit NOx emissions to 12 ppm. The plant is also a zero discharge plant, using treated effluent provided by the city of Bartow for its cooling systems.