By Brian Schimmoller, Contributing Editor
The Fukushima Daiichi nuclear plant accident in Japan is widely expected to slow new plant development efforts in a number of countries. The events also may impact existing plants, either via temporary or permanent shutdowns of some aging units or via design and procedure modifications to enhance plant safety.
One area that could end up in some sort of no-man’s land is nuclear power uprates. Many such uprate projects are already in the works. The U.S. Nuclear Regulatory Commission has 14 uprate projects under review, representing 4,704 MW (thermal) and 1,568 MW (electric). Another 35 uprate applications are expected, representing 5,564 MW (thermal) and 1,854 MW (electric). While it’s too soon to tell how Fukushima will impact uprate projects, at least some degree of additional technical review and analysis is likely for most.
Entergy is one of the utilities with significant power uprate experience across its fleet, including seven measurement uncertainty uprates, four stretch power uprates and three extended power uprates to date. The Grand Gulf plant in Mississippi is next in line for Entergy, pursuing an extended power uprate that will raise its capacity to 4,408 MW (thermal), making it the largest nuclear plant in the country. The majority of the plant modifications at Grand Gulf are scheduled for its 2012 outage. Modifications include a new steam dryer, generator replacement (via re-wind of the plant’s spare rotor), nine new feedwater heaters, high-pressure turbine replacement, main plant transformer upgrade and an expanded auxiliary cooling tower.
At the Nuclear Power Uprate Conference this past June, Jeff Richardson, director of Entergy’s uprate program, shared lessons learned from his fleet’s uprate experience. Richardson’s main message was that, as substantial engineering undertakings, uprate projects must be given the appropriate resources and attention to succeed. In Entergy’s case, the company recognized it needed to separate project management and engineering into two distinct management chains to provide the proper focus on executing such large projects.
Richardson cautioned the vendor community not to expect speedy action when it comes to power uprate projects. Uprate timelines can extend 44 to 60 months on average and vendors are often surprised by how far along utilities have to get in the planning process before making a decision to proceed. Entergy recognizes six major project elements along the uprate timeline: feasibility study, 3 to 5 months; operational risk assessment, 1 month; focused studies, 2 to 3 months; uprate key decisions, 2 to 3 months; uprate design, 18 to 24 months; and uprate implementation, 18 to 24 months. The durations provided represent average timespans. Richardson noted that 3 to 5 months is pretty aggressive for the initial feasibility study; 6 to 9 months is more common.
The “focused studies” portion of the uprate timeline targets technical issues that can trip up a project. They are conducted to remove uncertainty and avoid impacts on schedule, budget and performance. Focused studies may tackle systems such as the steam dryer, auxiliary power and transmission. On a similar front, answering a number of boundary questions can smooth project execution. Richardson touched on some of the more obvious ones—such as regional energy demand, capital and production costs and risk tolerance—but also examined a few less obvious questions.
For example, consider waste management impacts. Richardson said it can be easy to discount waste disposal costs of major components replaced during an uprate. Such an oversight can have significant impacts on planning, security and radiation protection coverage. Similarly, with respect to operations and maintenance, it’s important to think downstream; for example, how will the uprate affect plant chemistry two to three cycles ahead?
Based on its own uprate projects and familiarity with other industry uprate projects, Entergy has developed a fairly predictable budget breakdown of uprate projects by category: balance of plant, 40 percent; nuclear steam supply system, 20 percent; internal project management and staff augmentation, 20 percent; turbine generator, 10 percent; and transmission, 10 percent. These are certainly not hard-and-fast values, but Richardson noted that if a given project is coming in with turbine generator budget estimates at 1 to 2 percent, the project owner may want to take a closer look.
Entergy has identified a number of budget “gotchas”—project issues that resulted in unexpected or additional engineering to resolve—resulting in extra costs. First was the condenser. Evaluating how the power uprate may impact condenser performance and what condenser modifications may be necessary to accommodate the power uprate is critical. Richardson cautioned nuclear plant owners not to count their megawatt chickens before they’re hatched. Megawatt gains you expect due to efficiency gains from turbine rotor replacements or moisture separator reheater modifications, for example, may not pan out because of mismatched heat balance analyses.
In a reflection of the stagnant state of the nuclear power industry in the U.S. over the past few decades, Richardson noted that there are fewer suppliers of highly engineered products for power uprate projects. For a number of components at the Grand Gulf uprate project, Entergy sent out requests for proposals and received only one bid. Follow-up analysis indicated that the reasons for the lack of vendor interest included no time to prepare a bid, minimal interest in the specific opportunity and a shift to other markets.
Finally, as with all complex engineering projects, effective communications is essential. Letting problems fester and linger without tackling them head-on is asking for trouble. As Richardson put it, “Never be the highest paid guy in the room to know about a problem.” Elevate concerns to ensure that the risks are fully understood and that appropriate actions can be taken.
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