Diablo Canyon nuclear power plant. Courtesy PG&E
By Brian Wheeler, Associate Editor
With a new draft for rules related to water intake and fish impingement expected in October from the Environmental Protection Agency, nuclear power plants in the U.S. are looking at options to meet compliance.
The rules, commonly known as 316(b) of the Clean Water Act, require that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing environmental impact.
“In very simple terms 316(b) involves building cooling towers,” said Richard Myers, Nuclear Energy Institute vice president of policy development.
But if a plant was not originally designed for closed-cycle cooling, there can be problems. “The plant is designed around the cooling system and performance can be affected,” said Greg Howick, senior Aquatic Ecologist for Burns & McDonnell. Therein lies the challenge for many operators of the U.S. civilian nuclear power fleet.
Of the 104 nuclear power reactors in the U.S., 60 use once-through cooling technology while 35 use wet cooling towers. EPA’s concern is that intake systems pull a large number of fish, shellfish and their eggs into the plant’s cooling system causing them to be killed or injured (entrainment). Larger species can be caught against intake screens and die (impingement).
What Are Plants Doing?
The oldest nuclear power plant in the country is not exempt. The Exelon-owned Oyster Creek generating facility faces opposition against once-through cooling technology. The New Jersey Department of Environmental Protection wants the 636 MW power plant to build one or more closed-cycle cooling towers. “We don’t believe cooling towers are a necessity here at Oyster creek,” said David Benson, spokesman. “Science and economics are going to show cooling towers are unnecessary not only for the plant, but that they may also cause environmental problem at Barnegat Bay.”
Exelon has made investments over a number of years to reduce the plant’s impact on the bay. According to Benson, “As DEP has pointed out, we are at as good as they (screens) can get.” He said the company continues to work with the state on the issue.
Benson said he believes other contributors exist to the bay’s decline and the draft water permit that was given to Oyster Creek doesn’t consider other problems at Barnegat Bay, such as increased development. Myers said one of the few places where the bay isn’t dead is around the power plant whose once-through cooling system creates turbulence in the water.
“If you put in cooling towers, you would in the process destroy the last remaining habitat in the bay” where aquatic life can thrive and prosper, said Myers.
Exelon received an estimate in 2006 that it would cost $700 to $800 million for the 40-year old plant to install cooling towers. Because every nuclear plant is unique, cooling towers aren’t an off-the–shelf item, but must be designed specifically for each plant. The retrofit estimate is “more than the plant is worth,” Benson said. “If we were forced to put up cooling towers, we would have to close the plant.”
A couple of hours’ drive north of Oyster Creek sits the Indian Point Energy Center on the Hudson River in New York State. The Entergy-owned IPEC is home to two pressurized water reactors, Indian Point 2 and 3. Indian Point 2 and 3 are 1,032 MW and 1,051 MW in capacity and both use 840,000 gallons of water per minute pulled from the Hudson River.
In April, the New York Department of Environmental Conservation denied Entergy’s request for a water quality certificate for the Indian Point nuclear power plant. The DEC said the plant “will not comply” with the states water quality standards and that the plant’s water intake systems and its release of water back into the Hudson River are killing two species of fish.
|Oyster Creek began operations in 1969. Courtesy Exelon Corp.|
The water quality certificate is necessary for Entergy to request a 20-year license extension for Units 2 and 3, which are currently due to expire in 2013 and 2015. Exelon is waiting to hear on an appeal it filed.
In a “Letter to the Editor” of the New York Times, Fred Dacimo, Entergy vice president said “Entergy is prepared to invest $100 million in new technology to protect aquatic life. But cooling towers would do more environmental harm than good.” Dacimo wrote that towers would emit 100 tons of particulate matter annually in an area declared by the federal government as exceeding health standards for particulate matter.
As an alternative, Entergy spokesperson Jerry Nappi said Indian Point is looking into wedge wire screens. IPEC has noted that smaller plants that draw water from the Hudson also use wedge wire technology.
Nappi said that to build cooling towers at the site the company would have to blast 2 million cubic-yards of rock to get space for towers he described as “the size of Yankee Stadium.” Entergy said that conversions to the plant could cost up to $1.1 billion and would take 15 years. Installing wedge wire screens would cost $100 million and could be completed in 3 to 5 years.
“We could start protecting even greater numbers of fish much sooner than if we had to build cooling towers,” said Nappi. The technology for wedge wire screens at IPEC is available and is used at plants roughly the same size, such as the J.H. Campbell and Oak Creek power plants. Indian Point is currently undergoing feasibility studies to make sure the technology will work. Nappi said there was no reason to believe it would not.
The Electric Power Research Institute has studied cylindrical wedge wire technology and has found that the technology, although expensive, can be successful. “Our analyses indicate fairly good performance in terms of the reduction in entrainment of fish eggs and larvae,” said Doug Dixon, technical executive at EPRI. “We are seeing reductions in impingement and entrainment of greater than 50 percent, even up to 80 percent and higher, depending on location, species and screen slot size.”
Out west, the 2,240 MW Diablo Canyon station north of Los Angeles and the 2, 150 MW San Onofre station near San Diego are involved in a three-year-long study that will look at issues pertaining to cost, permitting, feasibility and technologies—including screening technology—that might be available to reduce impingement and entrainment at the power plants, which sit next to the Pacific Ocean.
|Indian Point Energy Center on the east bank of the Hudson River. Courtesy Entergy Corp.|
“At this point there is no requirement to retrofit to closed-cycle cooling or shut down by a certain date,” said Bryan Cunningham, supervisor of environmental operations at Diablo Canyon.
Cunningham said a policy set in place by California water quality regulators on May 4 to restrict once-through cooling at many of the state’s power plants provides a number of options for nuclear operators.
“We don’t necessarily agree that once-through cooling is radically detrimental to the environment, but we do agree with and can support a move of the industry away from that and California away from that in an orderly fashion,” he said.
After an engineering and construction assessment of the Diablo Canyon site, PG&E has determined that it would require $2.7 billion in capital and a 17-month outage to prepare the site. Counting the cost of replacement power for such an outage and capital expense for installation, PG&E estimates it would cost $4.5 billion to retrofit the facility for closed-cycle cooling. That’s if the company were to win approval for such a project. The estimated cost to retrofit the Southern California Edison-owned San Onofre could be around $3 billion.
One reason nuclear and fossil facilities were built to use closed-cycle cooling is site configuration. The plants have access to large fresh water resources, flat land and open space, Cunningham said. Sitting on a small coastal bench with mountains rising immediately behind, Diablo Canyon may be among the most topographically constrained nuclear facility in the U.S.
“In the case of Diablo Canyon on the California coast, they would have to carve an enormous chunk out of the cliff side and possibly destroy all types of sensitive habitat to get cooling towers in,” said Myers.
PG&E concluded that accommodating potential cooling towers would require excavating about 2.1 million cubic-yards of earth. Beyond that, because of site constraints and the fact that PG&E would be required to use only salt water makeup, towers installed so close to the operating plant could cause problems of its own.
“Bottom line is that even if it could be done and even if there was a desire to install cooling towers here it would be radically more difficult at this facility than probably just about any other in the U.S.,” said Cunningham.
When talking about a retrofit, one of the big problems is where structures are going to be sited, said David Bailey, senior project manager for EPRI. Adding cooling towers is expensive due to a number of factors, including concrete, piping and excavating and potentially relocating other pipes that run through the plant. The downtime at a nuclear power plant can add up quickly. Unlike other generating units, nuclear plants almost are all base-loaded with capacity factors on the order of 85 to 95 percent. To complete a retrofit, a facility could be down anywhere from 6 to 18 months.
San Onofre Nuclear Generating Station. Courtesy Southern California Edison
“Basically to convert a plant from once-through cooling to cooling towers, the whole system needs to be revamped,” said Kit Ng, geotechnical and hydraulic engineer for Bechtel Power Corp.
For example, piping would need to be change because closed-cycle systems use different sizes of piping as well as different materials. The same condenser may be used when retrofitted. But that, too, is site-specific. The existing condenser may not be sufficient because pressure in the cooling tower is much higher than in a once-through cooling system.
Because Diablo Canyon, for example, is positioned on the side of a hill slope and cooling towers could be placed above the level of the plant, it would create a lot pressure. “Your existing piping may not be designed to handle that,” Bailey said. Instead, plant operators may need to replace piping to handle the pressures that are going to involve pumping the water from the condenser to a higher elevation simply to go through the cooling tower.
EPRI has developed a model to estimate the cost and complexity of a cooling tower retrofit. The model, based on about 75 site-specific cost estimates, can be used to estimate retrofit costs for some 446 once-through cooling facilities, including 41 once-through nuclear units. There are 11 major factors that can make retrofits difficult, ranging from plume and noise abatement to the type of soil present to support the tower.
One big issue involved in a cooling tower retrofit is its location. Ideally, the cooling tower should be in close proximity to the condenser to reduce pressure losses, pumping requirements and the extra capital requirements needed to move water over longer distances.
“Existing facilities often have a lot of infrastructure that would need to be relocated in order to accommodate the new cooling towers,” said Bailey. “This can add costs, increase the complexity of the project, and impact the length of the outage.”
Cooling tower retrofits also result in lower plant efficiency and output compared to plants operating with once-through cooling systems. Heat rate penalties typically amount to up to 1.5 percent of annual generation and the additional electricity requirements associated with operating the pumps and fans tack on another 1.5 percent reduction in annual generation, according to Bailey. To offset these losses, some plants, especially nuclear units, consider upgrading the condenser when conducting a cooling tower retrofit. While this recaptures some of the heat rate penalty, it can also potentially extend the outage, by up to a year or more, depending on the design of the plant.
Are Cooling Towers the Answer?
“We tend to think a simple flat mandate to install cooling towers across the board is incredibly unwise from a policy point of view and that you must do a project-by-project and case-by-case analysis for each site and look at technically capability,” said Myers.
A 2008 assessment by the North American Electric Reliability Corp. found 50,000 MW of shutdown or lost capacity that could not make the transition to cooling towers and would cut capacity 4 plus percent nationally, according to Myers. When the EPA first proposed 316(b) Phase II in 1995, the original language recognized site-specific analysis.
Because the issue surrounding 316(b) is so complex from an engineering and technology perspective “it is a mistake to mandate a one-size fits all type of solution,” he said.
PG&E continues to assess its Diablo Canyon plant and said it will be supportive of the industry moving away from once-through cooling.
“We are confident that over time, working with the state and through this assessment process they put together for the nuclear facilities, we will end up with a reasonable outcome,” said Cunningham.