Nuclear power producers in the USA have squeezed the equivalent of four new nuclear plants – and hope for at least two to three more plant-equivalents – from their fleet of 103 operating plants with a series of instrumentation and equipment changes that allow additional power production. The US Nuclear Regulatory Commission (NRC) has approved more than 100 nuclear power plant uprates under its operating reactor regulations. The uprates can be divided into three categories:
• Measurement uncertainty recapture uprates add less than a 2% power increase. They are achieved by implementing enhanced techniques for calculating reactor power by using state-of-the-art feedwater flow measurement devices to reduce the degree of uncertainty associated with these measurements. This, in turn, provides for more accurate power calculations.
• Stretch power uprates typically add power increases of 2-7% and stay within the plant’s existing design capacity. The actual percentage power increase is plant-specific, and depends on operating margins included in the plant design. Stretch uprates usually involve instrumentation setpoint changes, but do not involve major plant modifications.
• Extended power uprates add power increases between 7% and 20%, and require significant modification to major balance-of-plant equipment such as the high-pressure turbines, condensate pumps and motors, main generators and/or transformers.
Each level of uprate not only produces a higher percentage power increase, but also becomes more expensive. Measurement uncertainty recapture generally costs around $1 million, but an extended uprate that goes for the full 20% can cost in excess of $100 million, depending on the equipment that must be modified, said Michael Coyle, vice president for operations at the Nuclear Energy Institute, the US nuclear industry trade association.
Coyle told Nuclear Engineering International that he was not aware of any upcoming future technology developments that would allow a plant to go beyond a 20% increase. “That seems to be the limit,” he said.
Representatives from several nuclear service vendors were more optimistic. “We don’t know if NRC has an upper limit” on uprates it will approve, said John Atwell from Bechtel. From a physical standpoint, potential uprates depend on what can be put into the core, the condition of the steam generators, and the condition and replacement cost of secondary-side equipment. Each plant must be examined individually to determine how much excess capacity it has, and what equipment must be replaced to tap that capacity. He also cautioned that there is a cascade effect: changing one piece of equipment can require other equipment replacements to assure compatibility.
Tom Weir, Framatome ANP senior vice president for engineering, suggested that there are many factors that must be considered for power uprates, such as fuel burnup, secondary side equipment limitations, and the remaining licensed plant life. Many utilities are getting extensions to 60 years, which does not have to be the limit, Weir told NEI. “Maximum plant life is unknown and the industry will operate the units as long as they remain safe and economically viable,” Weir said. “The industry has demonstrated that an
additional 20 years is very viable.” He pointed out that when he started in the nuclear business, no one would have even considered steam generator replacements – now they are done routinely. Both technology and construction techniques have changed significantly.
Longer plant life also makes uprates more attractive financially, Weir said. Uprate costs range from about $750 to $900 per installed kilowatt, compared to new plant costs of $1500 to $1800 per installed kilowatt. These costs become very attractive economically if they can be capitalised over an additional operating period of 20 years or more.
Build uprate experience
Several major nuclear vendors, including Bechtel, Framatome ANP, GE Energy and Westinghouse, have developed business units that specialise in plant-specific feasibility studies and analyses of uprate potential. These studies typically look at a range of plant parameters, such as fuel design and improved fuel options, as well as secondary side improvements such as steam heaters
and turbine upgrades. Some vendors offer full-service contract management through completion of the uprate.
Last November, GE Energy launched a new service to help utilities evaluate and enhance plant reliability, performance and safety with a view toward licence extensions and power uprates. GE uses a proprietary multi-phase programme, Performance 20, to assess the condition of plant systems, equipment and components and evaluate the need for repairs, replacement parts, upgrades and potential uprates.
Such studies routinely identify pinchpoints at each level – equipment or systems where upgrades could make a significant difference in the plant’s ability to obtain NRC approval for an increase in power generation.
Many utilities launch uprate feasibility studies when they also are looking at major plant upgrades such as turbine replacement. Every utility “probably has some sort of conceptual study for more megawatts,” Weir said, explaining that more power translates into more revenue for the power producer.
The NRC also has become very efficient at reviewing uprate applications, Weir said, noting that the regulator has developed a standardised process to evaluate licensee submittals. “Interface requirements with NRC are fairly well-defined,” and the NRC has developed ‘templates’ for licensee submittals. In general, licensees consider the regulator’s expectations to be well understood and consistent among applicants.
In recent years, applicants also have found greater predictability in the time required for the NRC to evaluate a licence application. The regulator seeks about five years advance notice of a potential application, particularly for a stretch or extended uprate application, so the agency can plan its own budget requirements. Once an application is complete, the NRC generally has a decision on measurement uncertainty recapture uprates in six to eight months, and a decision on stretch or extended uprates in 12 to 16 months.
Greater predictability has given licensees more cost certainty on the licensing portion of the uprate process.
So far, approved uprates on all US nuclear plants total about 4200MWe, or the equivalent of four new 1000MWe plants. Utilities are at various stages of regulatory application for another 1000MWe. Nuclear industry observers predict that a further 1000-2000MWe are possible given the present state of technology.
The NRC has approved 105 uprate applications since 1977. The first extended uprate, a 6.3% power increase for the Monticello plant, was approved in 1998. The NRC approved 17.8% increases for Quad Cities units 1 and 2 in 2001, and the first 20% increase – for the Clinton plant – in 2002.
NRC staff are currently reviewing 10 additional uprate applications, all for either stretch or extended uprates.
A voluntary survey conducted by NRC staff in January 2005 identified an additional 29 uprate applications expected between 2005 and 2010.
Of these, 15 are expected to be for measurement uncertainty recapture uprates, three for stretch power uprates, and 11 for extended uprates. The total power increase from these 29 anticipated applications is 1388MWe.
Waterford leads PWR uprates
So far, the majority of the uprates have been on BWRs, which had more excess capacity margin to recover. However, the NRC has seen more activity on PWRs in recent years.
On 15 April, the NRC approved Entergy’s request to uprate Waterford 3 by 8% – the largest PWR uprate approved so far. The NRC’s approval is conditional to Entergy’s submittal of an amendment accounting for ‘instrument uncertainty’, which NRC staff must review and approve. NRC staff reviewed Entergy’s evaluation that showed the plant’s design could handle the increased power level. The regulator’s safety evaluation focused on several areas, including the nuclear steam supply systems, instrumentation and control systems, electrical systems, accident evaluations, radiological consequences, operations, and technical specification changes.
The uprate at Waterford, located about 20 miles west of New Orleans, Louisiana, will add about 68MWe, increasing the plant’s operating capacity from 1075MWe to 1143MWe. The uprate involves significant modifications to plant equipment, such as the high pressure turbines, main generators, and/or transformers, which Entergy plans to make following its spring 2005 refuelling outage.
In April, Progress Energy completed a four-year power uprate at Brunswick 1 and 2 in Southport, North Carolina, adding a total of 232MWe to the output of the two-unit BWR plant. Brunswick’s two reactors operate on 24-month fuel cycles, with one unit taken out of service for refuelling and maintenance each spring. During outages, other Progress Energy generating plants provide electricity to the company’s customers.
Brunswick 1 has an approved generating capacity 938MWe after a stretch uprate in 2002 added 52MWe and an extended uprate in 2004 added 66MWe. The recently completed outage on unit 2 added 25MWe, and an earlier outage in spring 2003 added 89MWe, bringing unit 2’s approved capacity to 900MWe.
Power uprate and reliability improvements during the recently completed unit 2 outage included replacing three main power transformers and other switchyard improvements. Progress also upgraded condensate and feedwater systems to support uprated power conditions.
Problems surface
Entergy, however, which has a 20% uprate application pending with NRC for its ageing Vermont Yankee plant in Brattleboro, Vermont, has fared less well than it did with the Waterford plant. In some ways, the controversy over uprate plans for the 510MWe BWR provide a cautionary tale of issues still remaining on power uprates, particularly the high power increases of some of the extended uprates.
Entergy originally submitted its uprate application in September 2003, and expected to have NRC approval by January 2005. However, after meeting with Entergy officials this May, the NRC has said that it needs additional information from Entergy and cannot say when the review will be completed.
In recent years, four other GE BWRs have experienced significant uprate-related problems following high-increase extended uprates. Both Quad Cities units (17.8% uprates per unit, approved in 2001) experienced steam dryer failure from the increased feedwater flow from the uprate. Dresden 2 and 3 (17% uprate per unit, approved in 2001) experienced steam dryer cracking and feedwater sampling probe failures.
Other plants have experienced failures in pipe support and internal structures as a result of flow-induced vibration from uprates.
The Institute of Nuclear Plant Operators (INPO) is examining these failures and has issued lessons learned reviews on uprates for plant operators.
Flow induced vibration is one of the “more difficult and challenging issues” facing plant uprates, said Tom Franch, Framatome ANP vice president for balance of plant engineering. The NRC also is looking at these issues and wants to be assured that companies seeking high power increases have addressed them and can verify that plant components will not operate outside of accepted parameters.
The steam dryer issue also has not been completely resolved. In BWRs, the steam dryer is positioned above
the reactor to allow separation of entrained water droplets that could get into reactor steam lines, said Charles Tally, Framatome ANP vice president for nuclear steam supply systems. The steam velocities are high enough that there are opportunities for the structure to vibrate excessively, potentially inducing fatigue failures in the dryer components. When power production increases by a significant percentage, steam velocity goes up, increasing the possibility of fatigue failures.
The NRC wants to make sure that the mechanisms of these failures are understood to a high-level of assurance that will allow utilities to prevent recurrences after future uprates.
Vermont Yankee is the oldest plant that has sought an uprate – and Entergy is seeking the maximum possible uprate. The application is further complicated because inspectors found some 40 hairline cracks in the plant’s steam dryer in April 2004. Plant officials have publicly stated that the cracks are a result of stress corrosion, which has since been repaired, and that they will not lead to failure of the steam dryer following an uprate. The NRC is requiring more proof and analysis than the company has provided so far.
Understanding of these failures appears to be improving, Coyle said, adding that he was not aware of any significant failures since 2002. However, since most of the new applications are for extended uprates, both utilities and the NRC will be factoring these potential failures into their analyses. In some cases, power producers could have to replace questionable plant components before they reach conditions that could lead to failure.
Related ArticlesWestinghouse to supply Monticello steam dryer Entergy hopes simulation will lead to savings at Waterford 3 outage this autumnTablesApproved power uprate applications
