This year’s winning projects range from a small 25 MW offshore wind farm to a mid-sized 570 MW combined-cycle power plant in the desert to a large 1,500 MW nuclear power plant restart.
This year’s Projects-of-the-Year award winners represent a variety of technologies and projects. The projects range from small, a 25-MW offshore wind farm, to mid-sized, a 570 MW combined-cycle power plant in the desert, to large, a 1,500 MW nuclear power plant restart. While the projects’ technologies are all quite different, they all have some important similarities: they were managed well and innovative processes and procedures were employed to complete the projects within the allotted time and budget.
There were many viable candidates for the awards, but Power Engineering magazine’s editorial team selected these three projects, which they felt stood above the rest:
• Pinnacle West Energy’s Silverhawk Power Station, Southern Nevada.
•Bruce Power’s Bruce A Nuclear Generating Station Units 3 and 4 Restart, Tiverton, Ontario, Canada
•GE Energy’s and Airtricity of Ireland’s Arklow Bank Offshore Wind Plant, Arklow, Ireland
In addition to the three winning entries, Power Engineering is also recognizing two other projects with honorable mentions:
(Above) Pinnacle West Energy’s and Southern Nevada Water Authority’s Siverhawk Power Station. Photo by Jim Swainson, Lockwood Greene.
Silverhawk Power Station at night. Photo by Jim Swainson, Lockwood Greene.
•Iskenderun Enerji Üretim ve Ticaret A.S.’s (Isken’s) Iskenderun 1,210 MW Coal-fired Power Plant, Southern Turkey
•Sweeny Cogeneration Limited Partnership’s SCR Project, Old Ocean, Texas
The owners of the winning Projects-of-the-Year were presented with their awards during the keynote session at POWER-GEN International on November 30, 2004 in Orlando, Fla.
One of the country’s fastest growing population centers is located in the greater Las Vegas area, making it a prime location for the first out-of-state power generation project for Pinnacle West Energy (PWE), an Arizona-based generation affiliate of Arizona Public Service (APS). Owned by PWE and the Southern Nevada Water Authority (SNWA), and located in Clark County 20 miles north of Las Vegas, the Silverhawk Generating Station is a 570 MW combined-cycle power plant that is ideally situated to help meet the area’s rapidly growing energy demands.
Construction of the $400 million unit began in summer 2002 and was completed 21 months later, ahead of schedule and under budget. The project team was led by PWE and supported by Lockwood Greene, the balance-of-plant engineer, procure and construct (EPC) contractor. Several factors allowed the project team to successfully complete the project, including project management and cost control tools that integrated engineering, procurement, construction and start-up.
The Silverhawk project received priority designation from the Governor of Nevada, giving it preference for water, air and land use permits. This priority status stipulated that PWE would keep 25% of the plant’s output in Nevada and use dry cooling technology, a technology that consumes 90% less cooling water than traditional combined-cycle wet cooling technology. PWE’s partnership with SNWA fulfilled its obligation to keep 25% of the electricity in the state, while improving SNWA’s reliability by providing a power source for the authority’s water treatment facilities and pumping stations.
To minimize SNWA’s risk during construction and satisfy PWE’s desire to have a fast track project, the partnership was structured so that SNWA became a 25% owner of Silverhawk on the day the facility began commercial operation. SNWA’s ownership agreement also carried the stipulation that the project would conclude under budget and ahead of schedule. These stipulations were met when Silverhawk began commercial operation on May 17, 2004-two weeks before the planned June 1, 2004 start date-at a cost well under the amount that was agreed upon at the beginning of the contract.
The State of Nevada and Clark County have strict environmental compliance requirements. The cooperative nature of the relationship with regulators and the SNWA resulted in Silverhawk receiving permits on an accelerated basis. By working closely with Clark County air quality personnel, it was possible to have the emissions compliance test reviewed and accepted in less than a week. This can normally take up to 30 days. Silverhawk meets the most stringent air quality and water use requirements in Nevada. Its NOx emission limit is capped at 2.5 ppm for all operating conditions including firing of duct burners. Silverhawk also was constructed with the best available control technology for carbon monoxide, limiting CO emissions to 4 ppm along with continuous monitoring for ammonia slip of no more than 10 ppm.
The Siverhawk facility is equipped with two Siemens Westinghouse 501F combustion turbine generators (CTGs); two Alstom heat recovery steam generators (HRSGs), each triple pressure and equipped for supplemental duct firing; one GE D-11 reheat condensing steam turbine generator (STG); and one Hamon 40 cell air-cooled condenser (ACC). The project also includes a zero liquid discharge system (ZLD) to meet Nevada Department of Environmental Quality wastewater discharge requirements. The ZLD uses waste concentration systems and evaporation ponds to eliminate any water discharge including the high brine concentration waste resulting from the cooling and evaporation of wastewater.
The steam turbine bypass system is designed to improve overall plant reliability by functioning completely without operator intervention. Independent bypass systems are provided for each CTG/HRSG pair. The bypass systems are designed for full load steam turbine bypass. Multistage control valves, with the pressure controllers and feedback devices mounted off the valve, provide reliable operation for the valve and the electro-pneumatic controls. For steam turbine trips where the normal pressure control loop tuning is too slow, the bypass valves are placed in a calculated feed-forward position based on steam flow and steam properties, thus minimizing pressure and drum level upsets. The bypass valves regulate pressure to a continuously calculated set point that is slightly above the operating pressure at any steam flow. Any throttling of a steam turbine valve causes the bypass to open and hold steady pressure in the system. Increasing system pressure that results from additional steam flow is reflected in the continuous set point calculation, keeping the bypass closed.
Lockwood Greene’s responsibilities included engineering, procurement and delivery of all balance-of-plant equipment, construction, startup, testing and training operations including initial operation of the facility. When site mobilization began in August 2002, the construction team faced a number of challenges. The threat of terrorism increased when the United States went to war with Iraq, causing delivery delays of foreign equipment and materials arriving at U.S. ports. Another challenge was securing adequate skilled labor with power plant construction experience.
The fast track nature of the project was an added challenge. Lockwood Greene overcame this challenge by optimizing the design to achieve the highest level of constructability. “For example, during the construction phase, discipline engineers worked at the jobsite to maximize the integration between engineering, construction and start-up and commissioning,” said Don Zabilansky, one of Lockwood Greene’s senior vice presidents.
Modularized components were used to the maximum extent possible to reduce the construction hours required in the field, which improved the schedule. “Due to the up-front cost-benefits analysis, this project was accelerated at the beginning, which improved the schedule by three months, thus resulting in significant savings,” Zabilansky added.
“Use of a 3-D design model to include all piping, electrical and structrual elements played a significant role in minimizing interferences and allowed construction to proceed with little rework,” said David Foster, PWE’s project manager.
Other challenges included managing peak craft workforce levels, particularly during a six month period of the project when the gas turbines, the steam turbine and the HRSGs were all being erected simultaneously. To minimize craft congestion, the project team developed a plan to install large quantities of piping and conduit underground. This allowed a significant amount of piping and electrical work to be completed early in the project, and helped spread out the craft needs. It also resulted in reduced labor requirements and increased productivity. Extreme temperatures, including peak summer temperatures as high as 118 F, also challenged the project.
Silverhawk employed a creative contracting method. PWE held separate contracts for the combustion turbines, the steam turbine, the HRSGs, the dry cooling tower, and switchyard and interconnecting transmission equipment. Engineering, procurement, construction of the balance-of-plant and installation of all equipment were performed by Lockwood Greene. Its contract was based on a fixed price for engineering, construction management and the procurement of engineered equipment, along with a target price and schedule for construction, commissioning, and bulk commodities procurement. The contract had a liability cap and bonus/penalty arrangement for meeting cost and schedule targets.
In the spirit of cooperation and for PWE to maintain total financial control of the project, all the contractor’s and subcontractors’/sub-suppliers’ invoices were transparent to the owner and all project invoices were directly paid from a bank account controlled by the owner. This approach helped build an integrated project team of all parties. In only 21 months, the plant went from the permitting stage to full commercial operation. “Pinnacle West had a superb lessons-learned program from three previous projects,” said Ajoy Banerjee, PWE’s construction and operation vice president. “This led to excellent design, construction and commissioning of Silverhawk; the ultimate proof of which is that the plant has operated with an availability of more than 99% since commercial operation began. The project has met all its objectives because there has been excellent teamwork and creativity in dealing with all the parties from the inception to the end.”
Bruce A Nuclear
Generating Station Units 3 and 4
As the newest player in an electricity market short of supply but long on promise, Bruce Power saw the Bruce A generating station as a mine of untapped potential back in the summer of 2001.
A few months earlier, the fledgling company had assumed control of North America’s largest nuclear facility and began studying the massive Bruce A complex that had been laid up for more than three years. Though challenging, Bruce Power knew there were some strong incentives for contemplating a restart of two of the station’s four idled units.
The plant in the foreground is Bruce A Nuclear. Bruce A Units 3 and 4 are pictured on the front left of this photo. Photo courtesy of ASLF.
For the first time in more than a century, Ontario’s electricity market had recently opened to competition and private companies were being asked to help offset a pending supply shortage. Nationally, the Canadian government had committed itself to the Kyoto Protocol, and restarting Units 3 and 4 represented 1,500 MW of emissions-free electricity.
Against this backdrop, the company conducted the most comprehensive assessment ever performed on a CANDU station. It decided a restart would be technically and economically viable as long as the two units could be brought back online in compliance with the latest safety and industrial standards.
Bruce Power knew from the outset that such a complex project would pose several challenges. Not only did it have to restart the two nuclear units in less than two-and-a-half years, it had to simultaneously improve production at the four other units it operated at its Bruce B station.
The company felt strongly that to successfully restart the 750 MW (each) units-originally commissioned in 1978 and 1979 and removed from service in 1998 by their previous operators-it had to assemble the right team. Such a team had to be composed of companies with complementary expertise and restart experience. The team members also had to share a commitment to accomplish what had never been done before-restart two laid-up nuclear units back-to-back. The players on the team consisted of Acres International, Oakville, Ontario; Sargent & Lundy LLC, Chicago, Ill.; and E.S. Fox Ltd., Niagara Falls, Ontario, collectively called the ASLF team. RCM Technologies also played a key role on the restart team, with responsibility for all the environmental qualification modifications.
The work scope included engineering, procurement and construction of more than 45 different modification projects. The projects ranged from maintenance overhauls of existing equipment to installation of a new qualified power system (QPS) and a new secondary control area (SCA). Safety, fire and seismic systems were all upgraded to meet or exceed current regulatory standards. The team completed approximately 300 design change notices per unit, installed 37 miles of new cable and made 200,000 electrical connections. The project scope grew when all Canadian nuclear facilities underwent major mandated enhancements to improve security. By the project’s completion, more than five million work hours had been expended.
Innovative technical approaches to the SCA and QPS, the two key safety systems, enabled the project to proceed and meet the restart schedule. The QPS involved the provision of two 2-MW emergency power diesel generators and the associated distribution and control systems to power this backup safety system.
Bruce A Nuclear’s temporary qualified power supply (QPS). Photo courtesy of ASLF.
The SCA design called for the provision of a secondary control room and the necessary controls and monitoring equipment to allow the plant to be safely shut down, cooled and contained in the event that the main control rooms were rendered uninhabitable. The SCA project was initiated after some of the other restart work had begun. Its completion required an aggressive effort to ensure it remained off the critical path. Because specific operability criteria limited the number of suitable locations for the SCA room, significant engineering work went into locating the room in the plant. Each option entailed extensive renovations to the existing plant. The other concern was response time of the SCA. Cabling used in the SCA had to be sized to ensure that electronic signals from the SCA resulted in rapid shutdown responses.
ASLF was responsible for the engineering, procurement and installation of most of the modification projects, including SCA and QPS. ASLF also provided support for the commissioning activities. To provide additional reassurance that the designs were adequate and environmentally compatible, Bruce Power assembled a team of experts to perform third-party reviews on a wide range of project activities from the design of critical control systems to routine building services calculations.
The team successfully overcame every obstacle. Unit 4 was restarted on Oct. 7, 2003, and Unit 3 on Jan. 8, 2004. Results to date have shown that Units 3 and 4 are very reliable. With the addition of 1,500 MW of nuclear generating capacity, Bruce Power now has six of its eight units operational and generates enough emission-free energy to supply about 20% of Ontario’s electricity needs.
“Few people outside our community will ever truly understand how massive and complex our restart project has been,” said Duncan Hawthrone, Bruce Power’s CEO.
The project established an integrated approach of a single team consisting of the owner-Bruce Power-and multiple contractors, including ASLF. This approach serves as a model for future restarts, or other large multifaceted projects, that require the complementary teaming of individual firms to effectively accomplish work.
Arklow Offshore Wind Power Plant
The global wind power industry has been steadily increasing the size of wind turbines to achieve the economies of scale needed to assure the economic feasibility of offshore wind projects. The Arklow Offshore Wind Power Plant, located in the Irish Sea, is designed to be a global showcase for large-scale offshore wind energy projects. The project has also received strong support from the local community and was cited by Frank Fahey, Ireland’s Marine and Natural Resources Minister, as a major step toward Ireland’s commitment to the Kyoto Protocol on limiting greenhouse gas emissions. He called the project “the dawning of a new age of clean energy, harvested from two plentiful resources, the sea and the wind.”
The Arklow project is the world’s first offshore project to deploy wind turbines in excess of 3 MW. Constructed by GE Energy as a demonstration platform for its 3.6 MW wind turbines, the plant is the industry’s first large-scale manufacturer-owned facility built and operated as a proving ground for GE Energy’s future offshore technologies.
The 25 MW offshore wind power plant consists of seven GE Energy 3.6 MW turbines sited on a sand bar about six miles from the shore. It is the largest wind power plant ever built at sea and was erected in only nine weeks. Each giant turbine’s three-blade rotor tip-to-tip dimension exceeds the size of a soccer field and each one stands approximately 32 stories tall. Power from the wind plant is transmitted via undersea cable to an electrical substation in Arklow Harbor. The project is fully operational and feeding 25 MW to the Irish electricity grid, enough electricity to serve approximately 16,000 Irish households.
Airtricity of Ireland, a renewable energy company that is co-developing the project, introduced the plant as Phase I of a 520 MW offshore project that it plans to develop in the next few years. “Ireland is 90 percent dependent on energy imports,” said Eddie O’Connor, chief executive of Airtricity. “We are working with GE to demonstrate that the Arklow Bank project, even in this first phase, can already make a viable contribution to future energy self-sufficiency for this country.”
The Arklow Bank is a sandbank located approximately 5.5 miles off the coast of Arklow, a town 40 miles south of Dublin. Years of meteorological testing revealed that Arklow possesses some of the strongest and most reliable winds in all of Europe. In addition to the presence of strong winds, it was selected as the site for Ireland’s first offshore wind farm because Arklow Bank’s shallow waters enabled the wind turbine foundations to be installed at reasonable costs.
Each GE Energy 3.6 MW turbine stands approximately as tall as a 32-story building. Photo courtesy of GE Energy, ©General Electric Company.
The site does pose some challenges, however, due to the tidal conditions that traditionally have caused ships to avoid the area, and it represents a far harsher environment than experienced at any previous offshore wind sites. Thus, new safety and operational procedures are being pioneered at Arklow to benefit Arklow and future offshore wind plants throughout the world.
“We were looking for a highly challenging site that would provide trials and opportunities for learning,” said Steve Zwolinski, CEO of GE Energy’s wind segment. “The Arklow Bank, with its changing climatic conditions and waves that reach 30 feet in height, provides a great proving ground for our technology as well as the development of best operating practices for offshore wind. At the same time, we have enlisted the help of GE’s worldwide R&D engineering team to assist in testing, evaluation, best practices implementation, and validation of technology, systems and procedures.”
The wind turbine erection process began with the project’s seven monopile foundations, which were driven into the seabed by a hydraulic hammer-the same process used in bridge building. A transition piece that provides access for cables and maintenance workers was fitted over each monopile. Two tower sections were added to the top of each transition piece and bolted into place. Each nacelle, which holds the main working components, was lifted to the top of each structure.
Finally, each rotor assembly was lifted from its horizontal shipping position to the vertical fixing position, and attached to the nacelle. All major components were staged and assembled at Rosslare Harbor in Ireland and transported to the project site, approximately 50 miles away, as they were needed for erection.
Based on GE Energy’s 1.5 MW wind turbine series, the 3.6 MW machine is specifically configured for high-wind sites. It incorporates several innovations to keep overall turbine cost of energy down, including an advanced blade design, an improved gearbox concept and adjustments to the structure to enhance load absorption and optimize assembly, transport and service logistics. The new machine incorporates the company’s unique power electronics technology, a variable speed rotor, and an internal crane for ease of maintenance. GE’s voltage control technology facilitates grid integration by improving grid voltage stability and overall system reliability.
GE Energy plans to operate the project until the demonstration is complete, which it estimates to be about two years from first operation. After that time, under the terms of the project’s co-development agreement, Zeusford, a company owned 50% by Airtricity and EHN of Spain, holds an option to purchase the plant.
Iskenderun Coal-fired Power Plant
At the official opening of the 1,210 MW Iskenderun coal-fired power plant, Turkish Prime Minister Recep Tayyip Erdogan said that a secure energy supply is the basis for dynamic economic growth. The $1.5 billion power plant will help Turkey achieve that economic growth by providing nearly 8% of the country’s electricity demand, while still preserving the environment through the use of some of the most modern environmental technology available.
The plant, made up of two 605 MW (net output) coal-fired units, is located in Southeast Turkey on the eastern shores of the Mediterranean Sea. It was built and is owned and operated by Enerji Üretim ve Ticaret A.S. (Isken), a subsidiary of Germany-based STEAG that was created especially for this project.
Iskenderun Coal-fired Power Plant. Photo courtesy of Siemens Power Generation.
On June 30, 2000, Isken awarded a fixed price turnkey engineering, procurement and construction (EPC) contract to an international consortium led by Siemens Power Generation (PG). Construction was completed 39 months later and the plant began commercial operation on November 22, 2003.
In addition to Siemens PG, the EPC consortium included Babcock Borsig Power and the Gama-Tekfen Joint Venture. Siemens PG was responsible for the overall plant design, turbo generators, balance-of-plant, flue gas desulfurization, coal and ash handling, electrical equipment, and instrumentation and control. Babcock Borsig Power supplied the Benson steam generator, which was manufactured under Siemens’ license.
Steam enters the high-pressure turbine at 2,566 psi and 1,000 F and reheated steam enters the intermediate turbine at 710 psi and 1,000 F. Iskenderun’s design heat rate is 8,483 Btu/kWh. The plant complies not only with the environmental limits set forth by Turkey, but also with those set by the World Bank. Its EPC contract guarantees particulate emissions will not exceed 50 mg/Nm3, SO2 emissions will not exceed 400 mg/Nm3 and NOx emissions will not exceed 650 mg/Nm3.
Isken has a 20-year energy sales agreement (ESA) with TEIAS, the government-owned Turkish utility, and a coal supply-and-transport agreement for up to 3.5 million metric tons annually with two German-based coal suppliers for the duration of the ESA. The bituminous coal is procured from the world market and most of it comes from Columbia and South Africa.
Barge unloading at the jetty of the Iskenderun power plant. Photo courtesy of Siemens Power Generation.
Not only is the plant itself considered high-tech, but its coal off-loading technology is also world renowned. Because the Bay of Iskenderun is very shallow in front of the power plant, a special high-tech facility for unloading the seagoing coal vessels had to be designed and built. The so-called transshipper is the largest floating unloading crane in existence for hard coal and offshore transfers. It unloads up to 30,000 tons of coal each day from large ocean-going vessels, which cannot anchor in the shallow bay, to smaller transport units that then discharge the coal to onshore conveyor belts.
Manpower peaks during construction caused challenges during plant construction. At times during construction, more than 4,000 people were on-site. A total of 600,000 engineering hours were channeled into the Iskenderun plant. The project plan comprised 10,000 individual activities and 15 subprojects had to be managed.
Sweeny Cogen SCR Project
The southeastern portion of Texas is a heavily industrialized area that demands large amounts of electricity and industrial steam. To complicate matters, the Houston-Galveston-Port Author region is very near the EPA Ozone Level Non-Attainment Classification of “severe.” Therefore, supplying the region with needed energy while complying with EPA regulations is an ongoing challenge. For the Sweeny Cogeneration Limited Partnership (SCLP), bringing its 480 MW, gas turbine Sweeny Cogeneration Facility up to Texas SIP regulations was an environmentally prudent undertaking. It was also necessary because the facility is vital to local industry: the Sweeny Cogen facility sells 480 MW of electricity to the grid and delivers 3.5 million lbs/hr of steam to Phillips Petroleum.
SCLP set out to reduce the NOx emissions from its four Siemens-Westinghouse 501D5A turbine generators/Nooter-Eriksen heat recovery steam generator (HRSG) power trains by at least 90%. SCLP achieved this goal using best available technology.
At the time the company began work to reduce its NOx emissions, American Electric Power Co.’s (AEP’s) subsidiary Industrial Energy Associates (IEA) was selected as the owner’s engineer. SCLP is a 50-50 partnership between AEP’s subsidiary CSW Sweeny GP/LP II and GE Capital Credit’s subsidiary Structured Finance Group Q Inc.
SCLP selected Peerless Mfg. Co. to provide the selective catalytic reduction system, which included system design and performance analysis, engineering fabrication and project management of the SCR-related equipment.
Because AEP had planned for the future during initial plant construction, the Sweeny Cogen facility was ahead of the game when this retrofit became eminent. Many important facets within the plant were already in place or available for use. For example, the HRSG units included spool pieces to accept the addition of future SCR systems. Careful preplanning by Peerless ensured installation of each of the SCR systems during scheduled maintenance or turnarounds and avoided undue interruptions to the Phillips process plant. “All four units are almost identical,” said Morris Dunham, Peerless’ project management director. “That saved us both design and installation time because of duplication.”
The SCR systems require vaporized, anhydrous ammonia to be distributed through each of four ammonia injection grids (AIG). A single ammonia storage and unloading skid feeds four ammonia flow control units, which in turn supply ammonia to an AIG. After computational fluid dynamics confirmation, the AIG array was installed in front of the catalyst within the HRSG spool pieces, which were installed when the units were originally constructed (three units in 1997 and the fourth in 2000). Such forethought contributed greatly toward minimizing installation of equipment or the need to move exhaust stacks, ducts and other equipment during this retrofit.
Bringing its 480 MW, gas turbine driven Sweeny Cogeneration Facility up to Texas SIP regulations was an environmentally prudent undertaking for Sweeny Cogeneration Limited Partnership. Photo courtesy of Peerless Mfg. Co.
A unique catalyst arrangement allows the operations group to dramatically increase or decrease the surface area of the catalyst allowing the plant to produce more or fewer NOx credits, or to meet future regulations. Unlike all other combined-cycle and simple-cycle plants that use a single catalyst module, these plants are unique because they use two specially designed, 50% initial catalyst layers. This configuration allows the NOx reduction capacity to be changed depending on process and/or regulatory needs. The capability to add a third 50% section if desired is designed into the SCR system.
A single ammonia storage and unloading skid feed four ammonia flow control units at the Sweeny Cogen facility. Photo courtesy of Peerless Mfg. Co.
In early 2004, performance testing confirmed that operational parameters were better than designed. The data indicates achievable NOx reduction levels of more than 90% (Table).
Being able to operate with NOx levels below EPA and Texas SIP regulations will contribute to cleaner air. Additionally, the sale or use of credits toward another facility is further justification that the retrofit was a good business decision.
Projects of the Year 2004 Major Vendors
Silverhawk Power Station
- Lockwood Greene
- Siemens Westinghouse Power Corp.
Bruce A Nuclear Units 3 and 4 Restart
- Acres International
- Sargent & Lundy LLC
- E.S. Fox Ltd
- RCM Technologies
Arklow Offshore Wind Power Plant
- GE Energy (Developer, owner and operator)
Iskenderun Coal-fired Power Plant
- Siemens Power Generation
- Babcock Borsig Power
- Gama-Tekfen Joint Venture
Sweeny Cogen SCR Project
- Peerless Mfg. Co.
- Industrial Energy Associates