With the nuclear fleet performing so well, owners are pursuing projects to get even more power from their assets.
By Teresa Hansen, Associate Editor
In this decade, rising fossil fuel prices and a focus on reducing greenhouse gases have made nuclear power more valuable than ever. “When you look at the economics of existing nuclear units versus coal and gas units, it’s easy to see why every megawatt from nuclear power is valuable,” said Andy White, president and CEO of GE Energy’s nuclear operations. “For that reason, owners are trying to get the most from their nuclear units.”
The 103 commercial nuclear reactors currently operating in the United States generate about 20 percent of the nation’s electricity. Since 1994, however, these reactors have increased electric generation by approximately 20 percent, according to Nuclear Regulatory Commission (NRC) data. This increase was accomplished with increased reliability, higher capacity factors, improved operating and maintenance procedures, higher fuel enrichment and power uprates.
Power uprates are largely a recent strategy, with most project kicked off after the mid-1990s. However, some nuclear power plant owners began performing power uprates as early as the 1970s to increase their plants’ power output. The NRC approved the first power uprate in September 1977, allowing Baltimore Gas and Electric’s Calvert Cliffs Unit 1 to increase its output by 5.5 percent. The NRC approved the same-sized increase for Calvert Cliffs Unit 2 less than two months later. Since then (through July 2006), the NRC has approved more than 110 power uprates for a total gross electrical generation increase of 4,845 MWe.
“In the late ‘70s into the ‘80s it became economically advantageous for utilities to add capacity to their generating fleet, and increasing power output at nuclear power plants was often favorable to building new generation,” said Joe Ruggiero, Washington Group International’s director of nuclear engineering.
Power plant owners have performed power uprates to increase output from as little as 0.4 percent to as much as 20 percent. Uprates can be as simple as adjusting operating parameters or as complicated as changing out major components, such as steam turbines, moisture separators/reheaters, main generators and transformers.
The NRC classifies power uprates into three types:
Measurement Uncertainty Recapture (MUR) Power Uprates. These uprates achieve less than 2 percent additional output and involve implementing enhanced/advanced techniques for calculating reactor power. MURs use state-of-the-art flow measurement devices to more precisely measure feedwater flow, which is used to calculate reactor power. More precise measurements reduce the degree of uncertainty in the power level, which is used by analysts to predict the reactor’s ability to be safely shut down under postulated accident conditions.
“Simply put, measurement uncertainty uprates involve refinement of feedwater and steam bypass operating parameters-usually allowable because of better monitoring techniques,” said Mike Phillips, Invensys’ nuclear program director.
When most of today’s operating plants were designed and built, conventional venturi devices existed to measure flow rate, so designers had to leave some margin due to uncertainties, said Basant Dilodare, Bechtel’s Nuclear Operating Plant Services’ (NOPS) project manager. “Today’s state-of-the-art, more advanced feedwater flow meters can better and more accurately measure flow.”
As an example, Dilodare explained that when built and designed, a plant’s feedwater flow might have been measured to ±2 percent accuracy. Today, better instruments may be able to measure the flow to ±0.5 percent, giving the plant another 1.5 percent increase in feedwater flow and a corresponding power increase.
The NRC has approved 35 MUR power uprates, most between 2001 to 2004 (Table 1). Click here to download a PDF of Table 1.
Stretch Power Uprates. These uprates typically yield up to 7 percent additional power and are usually within the plant’s original design capacity. The actual power percentage increase a plant can achieve while staying within the stretch power uprate category is plant-specific and depends on each plant’s design operating margins.
Stretch power uprates generally do not involve significant plant modifications, but instead involve changes to operating procedures, technical specifications and set points. Occasionally, a stretch power uprate does require relativelyy minor changes to plant components such as valves and pump impellers.
Stretch power uprates are the most common-the NRC has approved 60 since 1977. In fact, the first 42 NRC approved power uprates of any kind were stretch uprates. The power increases range from 0.9 percent to 6 percent (Table 1).
Extended Power Uprates. These uprates are much more involved and have been approved for increases as high as 20 percent. They require significant modifications to major balance-of-plant (BOP) equipment such as the high pressure turbines, condensate pumps and motors, main generators and transformers. They also typically require changing out numerous pumps and valves.
Extended power uprates are most often performed on boiling water reactors (BWRs). That’s because BWRs had more margin built in than pressurized water reactors (PWRs) when they were initially designed and built, said Nandu Patankar, Washington Group International’s manager of mechanical engineering. “Most BWRs have margins that allow an extended power uprate up to 120 percent of original licensed thermal power with plant modifications,” he said.
NRC data show that 13 of 17 extended power uprates have been for GE BWRs. (GE is the original designer and manufacturer of all BWRs operating in the United States.) The data also show that many of these power uprates resulted in increases ranging from 15 percent to 20 percent of the plants’ original capacities. The remaining four extended power uprates involved PWRs and resulted in roughly 8 percent power output increases for each plant (Table 1).
White said GE’s BWRs had extra margin designed in for safety reasons. “When these plants were being designed and built, the NRC and the utility customers needed a certain comfort level,” he said. “Both wanted additional safety margin.”
In addition to significant BOP changes, fuel designs that eliminate “early burnout” have been developed to support extended power uprates. GE’s BWR fuel has evolved into a higher-powered fuel that increases plant reliability and is better suited for uprates. The fuel enables the reactor to increase energy output, which, with suitable equipment, allows for the power increase.
GE has provided its advanced GE-14 fuel to nuclear power plants for several years. Recently, Global Nuclear Fuel (GNF), a joint-venture of GE, Hitachi and Toshiba, announced a multi-million-dollar, 10-year contract to supply fuel fabrication and reload-engineering services for Entergy Corp.’s five BWRs. The Entergy contract marks the commercial launch of GNF’s latest BWR fuel design, GNF2 Advantage. The fuel is designed to increase overall BWR fuel performance by increasing energy output while reducing total uranium requirements.
White said that although advanced fuel is often included in uprates, it can also be used in plants that are not undergoing power uprates. “Existing plants can use higher powered fuel to increase reliability and benefit from reductions in total uranium requirements without performing an uprate,” he said.
NRC Approval Required
Because the NRC controls any change to a nuclear plant license or technical specification, an owner may only change these documents after the NRC approves the licensee’s application for change. Therefore, no matter how small, all nuclear plant power uprates must be approved by the NRC.
The plant owner, usually through a contract with an architect/engineering (A/E) company, works with the original equipment manufacturer (OEM) to analyze existing plant systems to determine if they can accommodate the proposed uprate. The OEM, which holds all design records, must look at the analyses and compare them to the original design and code requirements and concur with the utility’s analyses and findings.
It usually takes the utilities, working with the A/E and/or OEM, about a year to complete the upfront work for a stretch license application. It then takes the NRC about a year to approve the application. “Early on, stretch licensing took longer than it does today,” says Washington Group’s Ruggiero. Over time, the NRC has seen and approved more stretch licensing applications and has made it clearer to the utilities what is needed in the licensing applications. “This has streamlined the process,” he said.
A new upgraded moisture seperator reheater at Fermi 2 is moved inside the turbine building. Photo courtesy of Dave Mitchell, DTE Energy Photographic Services, and Washington Group International.
Because they are more extensive in scope, involve substantial component changeouts and are relatively few in number, the licensing application preparation and approval for extended power uprates takes longer. “All systems touched by an extended power uprate must be analyzed before a license application is submitted to the NRC,” said Ruggiero. It typically takes the owner, A/E and/or OEM about a year to prepare the application, but it takes the NRC about two years to approve an extended power uprate application.
Some standardization of extended power uprate licensing exists, said White. For example, certain designs are common to all BWRs while other design characteristics apply to a specific family or model of GE BWR. Licensing standards can be applied to the areas with the most similarities. Each plant, however, contains many unique design characteristics that are specific only to it and requires individual evaluation; therefore, complete standardization will likely never be possible.
Is an Uprate Worth It?
Many nuclear plant owners thought it economically worthwhile to perform stretch uprates. Several also have opted to perform MUR uprates. However, relatively few extended power uprates have been performed (Table 1).
It is often during the licensing preparation analyses that the utility performs a cost benefit analysis, called a “pinch point” analysis. Here the utility determines if the uprate investment will be returned with more efficient operation and if and when to expect the return on investment, said Ruggiero.
White agreed that “each plant must look at how much it will cost to make various modifications and to determine the amount of uprate needed, especially when considering the full 20 percent uprate.” This thinking is reflected in the NRC’s data, which show that only two of the 17 plants approved for extended power uprates-Clinton and Vermont Yankee-requested the full 20 percent capacity uprate on one extended power uprate licensing application (Table 1).
“It is common for plants to spread out the costs and use a stepped approach” said White. For example, a plant might decide to initially increase its output to 102 percent of original licensed power, then uprate to 105 percent later. A few years after that, the operators may uprate to 110 percent of original power and then finally uprate to 120 percent.
Xcel Energy is the latest company to announce plans to uprate one of its nuclear plants by a full 20 percent. According to White, Xcel Energy’s Monticello is the largest GE extended power uprate contract to date, where GE will provide licensing, turbine-generator upgrades and BOP equipment and engineering. The plant, which began operation in June 1971, is rated at 613 MW. Xcel plans to apply for the license amendment with the NRC during the fourth quarter of this year. Upon completion of the extended power uprate, Monticello will be rated 684 MW. The uprate, which will be multi-phased, is scheduled for completion in the spring of 2011. Xcel estimates the uprate will cost $129 million, which equates to an installed cost of about $1,815/kW capacity.
To realize the full benefit of an uprate, plant systems and components must be healthy and the plant must be performing efficiently and reliably. As an example, Washington Group’s Patankar said that if feedwater heaters’ tubes are extensively plugged, it is probably not a good idea to perform an uprate because the plant won’t get the maximum benefit from it. “The feedwater heaters, condenser, pumps and all other system components should be operating at maximum efficiency before an uprate is considered,” he said.
Bechtel’s Dilodare agreed that the plant must be healthy. “If a system is already having problems, it is not prudent to spend money on an uprate because the full benefits will not be recognized until all problems are resolved.” He said it is “absolutely necessary” that a plant have a good operating record “with no problems in any systems before management even considers spending money on an uprate.”
Dilodare stressed that the plant’s operations and maintenance history should be checked thoroughly to ensure it has been operating reliably and has no existing chronic maintenance issues.
North American nuclear power plants are leading the world in performance and reliability, making them prime for nuclear plant uprates. In addition to the 4,845 MWe of approved uprates through mid-2006, the NRC is reviewing pending applications for another 1,057 MWe to be added by early 2008. In addition, based on a September 2006 survey, the NRC expects 25 additional uprate applications from 2007 to 2011 that will increase output by another 4,150 MWe.
North America is not alone, however. European power plants are also uprating, said White. “Asia is not there yet,” he said, “but it is the next logical market for uprates.”
White said that the Japan Atomic Power Company (JAPC) is currently studying uprates for its nuclear plant fleet. “Japan’s operating regime (regulators and utilities) is conservative so uprates haven’t been seriously considered in the past.” He said Japanese plants operate on one-year cycles and their outages are typically long compared to North American outages. Due to the country’s limited natural resources and shrinking capacity margins, however, the Japanese must find ways to increase electricity production. White said nuclear plant uprates “are looking like a good solution.”
In addition, White said GE plans to put as much margin as possible into its latest plant design, the Economic Simplified Boiling Water Reactor (ESBWR). The margin won’t be put into place for additional safety margin as was the case when North America’s current BWR fleet was built. Instead, White said, it will be for economical reasons. Extra margin can lower a plant’s initial capital cost and provide a way for plant owners to increase power once the plant has paid for itself. “There is,” White said, “a fine balance between initial cost and margin.”