Category Archives: reactor designs

Responding to System Demand II: Extreme Scenarios

by Will Davis

Gravelines Units 1 through 6, France.  Image courtesy AREVA USA.

Gravelines Units 1 through 6, France. Image courtesy AREVA USA.

The continued introduction of renewables onto the electric grid in the United States is ensuring that discussion of whether or not these assets can be integrated with existing or expected designs of other sources continues. In this discussion, nuclear energy is often wrongly described as “on or off”—but in fact, nuclear plants can and do load follow (respond to changing system demands) although it’s a matter of both design and owner utilization—with a focus on economics–that determines if or when any actually do.

Historically, most nations using nuclear power have experienced growth at rates that have allowed assets other than nuclear to ramp power up and down to meet demand variance—meaning that nuclear has operated in the “base load” mode, or steady state full power below the maximum demand. To learn about this (steady state full power as opposed to just baseload) taken to the extreme, and to learn about the polar opposite in an environment where nuclear actually dominates, we can compare the experiences and some plans of the former Soviet Union and France against each other.

Soviet Union – All up, all the time

In the former Soviet Union—that is to say as things were there prior to collapse—the state plan was that nuclear plants would never load follow and in fact it was desired that they run at full power all the time, no matter what the demand actually was. (This was partly because of poor load following characteristics of the dominant RBMK-1000 design.) To that end, the USSR recognized that it would have excess power over demand; it decided to devise ways to store it.

One scheme was fairly predictable: Giant reservoirs would be built, holding millions of gallons of water, which could be pumped up with water when the nuclear plants were providing more power than needed. When demand was high, the flow out of these reservoirs would be used as hydr0-electric power. This is called “pumped hydro storage,” and is a leading concept even today to help stabilize electric power against intermittent supply. A pumped storage plant was built roughly simultaneously with the giant Ignalina nuclear plant in Lithuania, which incorporated the only four RBMK-1500 nuclear units ever built and had power vastly beyond local demands.

The other scheme was more complex, and involved stored heat. Nuclear plants would heat up storage reservoirs of energy (water, organic liquids, and phase change solids were evaluated) when providing excess power over demand. Later, these reservoirs’ heat would be tapped to generate steam above and beyond that produced by the nuclear plant, so that the output of the turbine generator could be increased (requiring, of course, excess turbine capacity above that the nuclear plant could drive). The reservoirs were also planned to provide the reheat for water being fed into the steam generators of the plant, which with all things considered could increase the total output by 15 or 16 percent.

France:  High nuclear fraction forces advanced load following

France developed a national system in one way like the former USSR’s—standardized plants were built everywhere. However, France aimed for a far higher percentage of nuclear power than any other nation, and as plants were completed and the percentage of nuclear on the grid increased and increased, the French were forced to move from baseload operation to load following on all nuclear plants. This complicated task was performed in stages.

France’s first major build was what are called the CP0 and CP1 series plants, rated 900 MWe and based on Westinghouse’s three loop pressurized water reactor. These plants as initially designed could only load follow a small bit at the start of core life, and not at all at the end. Their power control scheme mostly relying on boron concentration was called “Mode A,” and was not adequate for a nation that intended to eventually have 80 percent of its power come from nuclear. (The Gravelines units shown at the opening of this article are of this type.)

St. Alban Nuclear Power Plant, 1300 MWe (two units.)  ©AREVA / Geoffray Yann

St. Alban Nuclear Power Plant, 1300 MWe (two units.) ©AREVA / Geoffray Yann

In 1975, the French (reactor vendor Framatome, later part of AREVA, and the operator Electricite de France or EDF) began to develop an advanced mode of control called “Mode G,” which used a mix of control rod types in the core. Some of the rods, called “gray rods,” were deliberately made less absorptive to neutrons, and by motion of these rods through wider ranges the reactor’s power could be adjusted smoothly and fairly rapidly throughout the life of the core.

Testing of this modified equipment (later to be amended with control equipment called RAMP, or Reactor Advanced Maneuverability Package) began in 1981 on 900-MWe plants, and was successful. In 1983 it was decided that the remaining eight 900-MWe units not yet completed would be started up with the new Mode G; the earlier 20 units would be backfitted when possible. The backfit required 53 instead of 48 rods, but could be done during any refueling outage; it allowed the 900-MWe plants to load follow from 100-percent power to 30-percent power.

The next range of plants, the P4 and P’4 series (represented above in illustration by St. Alban), were all built incorporating Mode G. The first eight 1300-MWe units, the P4 type, were already built and on the grid by 1987 when load following testing on this new, large type began. Eventually all of these and all 12 P’4 units had Mode G and RAMP, and could undertake radical load following maneuvers almost completely through core life. Mode X, slightly improved on Mode G, was fitted to the final design of the early build out—the powerful N4 plant, a 1450-MWe design of which only four were ever completed (see below).

Civaux Nuclear Power Plant, 1450 MWe X2, France.  ©AREVA / Pauquet Claude

Civaux Nuclear Power Plant, 1450 MWe X2, France. ©AREVA / Pauquet Claude

Completion of these programs gave the French a vast, versatile, and responsive fleet of nuclear plants that could operate realistically on the daily load cycle while still providing almost three quarters of the total electric generating capacity. In fact, many operators may not choose (and have not chosen) to do this because nuclear plants make the most money at 100-percent power; however, the French national choice to prioritize nuclear after the oil crisis in the early 1970s made the inclusion of load following on their nuclear plants an absolute necessity.

The results

What do we find when we compare the above examples, keeping in mind an insight on the discussion of energy in today’s world? Well, for starters, we see with the Soviet example a proof-of-concept of what amounts to grid level storage, which is a concept that renewables advocates are continually promising as the field leveler for wind and solar. Clearly, such storage is more than capable of helping nuclear plants—and may be better at helping them than helping renewables, since the renewables’ output is intermittent and the nuclear plants’ output is continuous. In fact, any generating plant could theoretically take advantage of grid level storage—even coal fired plants.

We see, though, that large amounts of inflexible generating power—power that we call “non-dispatchable” because it can’t be ordered or dispatched when needed, which essentially demands storage—leads to a large amount of expensive and complicated infrastructure or else new design concepts. No matter the desire, whether it’s for large-scale renewables OR large-scale full-power-all-the-time nuclear designs, the complexity and cost of infrastructure not directly related to the generating source but required for such a scheme is, nevertheless, considerable.

On the other hand, the French example shows us that a very high percentage of nuclear on the grid is manageable, and that nuclear plants can “play along” with either system demand or, if need be, other generating sources. Readers should note again just how many years ago these designs and concepts were proven out—these developments are not at all new.

In the next installment, we’ll look at nuclear plant designs available and being built right now, today, and examine their ability to respond to system demand.

• For more information: Responding to System Demand (original post)


Sources: Nuclear Engineering International Magazine—October 1984, January 1985, December 1988, February 1986

“Soviet Nuclear Power Plants—Reactor Types, Water and Chemical Control Systems, Turbines.” David Katsman, Delphi Associates 1986

Information also provided by AREVA USA; special thanks to Curtis Roberts of AREVA for his assistance with illustrations and plant historical data.


SavannahWillinControlRoomWill Davis is the Communications Director for the N/S Savannah Association, Inc. where he also serves as historian, newsletter editor and member of the board of directors. Davis has recently been engaged by the Global America Business Institute as a consultant. He is also a consultant to, and writer for, the American Nuclear Society; an active ANS member, he is serving on the ANS Communications Committee 2013–2016. In addition, he is a contributing author for Fuel Cycle Week, and writes his own popular blog Atomic Power Review. Davis is a former US Navy reactor operator, qualified on S8G and S5W plants.

BWXT will return in mid 2015

On November 5, the day before a scheduled quarterly conference call with investors and analysts, Babcock & Wilcox (NYSE:BWC) announced that it was splitting into two separate publicly traded companies.

One of the companies will retain the Babcock and Wilcox (B&W) brand and will include the business segment known as the Power Generation Group.

That company will continue to manufacture large heat exchangers and specialty pollution control components for combustion steam plants heated by coal, waste, biomass, and gas turbine exhaust. B&W will have a projected 2015 revenue of approximately $1.7 billion. Jim Ferland, who came to B&W in April 2012 after a two-day stint as chief executive officer of Westinghouse, will continue to run that substantially smaller company.

According to statements made during the November 6 quarterly conference call, B&W will be focusing on the international market for most of its new projects. It will continue earning about 50 percent of its revenue in the aftermarket servicing existing installations, much of which is in the United States.

Ferland described how the new company expected to be able to increase its operating margins by making more of its products and performing more of its engineering via Thermax Babcock & Wilcox Energy Solutions, a joint venture that opened a new fabrication plant in India last January. He emphasized that the company sees growth opportunities but will not chase low margin contracts just to increase revenue.

Though no layoffs have been announced for U.S. facilities, Ferland also mentioned that the company intended to maintain a relatively constant employee count of approximately 6,300 people. As work shifts to the new facility in India, its employee count will grow. There is only one way to keep the total constant: the number of U.S. employees will have to decrease.

Pure play nuclear

The second company will include all of B&W’s nuclear-focused business units and will revive a familiar name, BWX Technologies (BWXT). BWXT will establish its headquarters in Lynchburg, Va., home to facilities and offices that employ more than half of the company’s 4,700 employees.

Company spokeswoman Aimee Mills said that selecting a specific headquarters location will be part of the six-month planning process.

John Fees, who is the current non-executive chairman of B&W and has worked for the company since before it was acquired by McDermott in 1978, will become the chairman of BWXT. Peyton (Sandy) Baker, also a long-time employee and current head of the government and nuclear operations group, will be the company CEO.

From the outside, this new alignment looks a little like a divorce of a long-established marriage due to growing mutual incompatibilities.

The activist investors who began taking large positions in B&W stock about a year ago have apparently determined that the company will be worth more by having two focused management teams working in areas of the energy industry that have some similar engineering needs—but function in entirely different regulatory environments and appeal to different types of investors.

It should free up the BWXT marketing department to emphasize the clean energy advantages of atomic fission—both publicly and politically—without worrying about offending or disadvantaging a sister division that is still tied to coal.

Each new company should appeal to investors with different goals for particular financial performance and product offerings. For example, an investor who believes that clean energy has better potential for growth than coal or biomass can now choose a pure play in nuclear instead of a mixed coal and nuclear company.

Custody of mPower

During the conference call, there were several questions about the fate of the mPower small modular reactor project. Company leaders stated that they were still interested in the project, and that they were diligently working on a design certification application within the constraints of the current $15 million per year project budget.

They are still working with the Department of Energy to determine how the matching funds it awarded to assist with the engineering and design certification effort will be best used and whether there will be additional funds provided.

Only a portion of the initial award has actually been appropriated and distributed to the company.

The mPower project will still be able to take advantage of the synergies provided by the existing manufacturing facilities and engineering skills associated with producing the specialized components required in nuclear power plants. All of those units of B&W are going to be a part of BWXT.

The Nuclear Fuel Services subsidiary, as well as the various subsidiaries, joint ventures and limited liability companies created for Department of Energy cleanup work, will be housed within the new BWXT, too.

Acquisition bait?

Though Fees and Ferland repeatedly stated that neither company is for sale, it is apparent that each of the two new companies could be an attractive target for a certain type of conglomerate.

BWXT might appeal to a major defense contractor seeking some commercial diversification and the growth potential of the mPower project if design certification can be completed, while B&W operates in the same market as Foster-Wheeler and Alstom, both of which are currently being acquired.

Knowledgeable sources are optimistic about the prospects for BWXT to flourish under its new, focused management. The selected leaders are familiar and respected. Fees and Baker have deep expertise in creating and leading teams that provide the expected quality and level of service to both government and commercial nuclear customers.

They recognize the future potential for the mPower project and for continued growth in providing nuclear-related technical services and exceptionally high-quality fuel and other components. They know that they are in a business that cannot succeed with a cost-reduction, outsource-to-India mindset. Unfortunately for the current employees of the mPower project, the cost-cutter mindset appears to have at least another six months of dominance.

The road to success for BWXT will be growing revenue by meeting customer expectations and by providing differentiated products that can demand higher margins because they are more productive than the competition.

Of course, like any divorce, there will be costs associated with the process of splitting.

The lawyers will get their share, the auditors will get their share, and the branding companies that produce signs, sales literature, and stationary will get theirs. The company estimates that there will be a one time cost of $45 million–$55 million associated with the split.

It also recognizes that there will be an ongoing cost associated with having two separate management teams, two separate auditors, a different kind of insurance program, and two separate headquarters.

This split should be fairly equitable and non-contentious. There are few physical assets that are currently shared between groups that will end up in “the other” part of the company, and there already appears to be a mutual understanding of who will take care of each of the children.

The market’s reaction to the announcement has been cautiously positive.

Note: A version of the above first appeared in the November 13, 2014, edition of Fuel Cycle Week. It is reprinted here with permission.

Root cause of Vogtle and VC Summer delays

This column was initially published in the October 16, 2014, issue of Fuel Cycle Week and is republished here with permission.

by Rod Adams

Within a few months of receiving its combined operating license in February 2012 the Vogtle-3 & -4 nuclear power plant project became the subject of reports that it was significantly behind schedule and over budget.

Radio station WABE, Atlanta’s NPR affiliate station, is closely tracking the project and its publicly released reports. WABE has compiled its story segments into a useful print and audio chronology. There are similar stories about the closely aligned Summer-2 & -3 project.

On September 24, I had the opportunity to tour the Vogtle site and learn first-hand how the project is faring. The wrong people are getting blamed. The resulting misperceptions about the projects have the potential to contribute to another lengthy hiatus in nuclear power plant construction in the United States.

The most important thing I learned during my Vogtle visit was that the construction project is moving as rapidly as predicted, that the people on site and in supporting roles are doing a good job, that the workforce hiring challenges are within the predicted boundaries, and that the regulators overseeing the project are performing as expected.

As is demonstrated by the progress being made on the second units at each site, lessons-learned programs are robust and effective.

I also saw a growing inventory of large components that was being stored in an expanding number of temporary structures designed to protect the components from the Georgia red clay and frequently inclement weather.

The second most important thing I learned was that the cost increase and ultimate schedule delay could and should have been predicted on the day that amendment 19 of the AP1000 design certification document was approved in December 2011.

The schedulers could have restarted a clock that should have been put on pause when the U.S. Nuclear Regulatory Commission changed the rules two-and-a-half years earlier with the Aircraft Impact Assessment rule.

Regulatory delays cost time and money

The 36-page Federal Register notice issued in July 2009 acknowledged that the Aircraft Impact Assessment rule was not necessary to provide “adequate protection” and it acknowledged that applying the rule to a project that was already under construction would impose an undue financial burden:

“In making these additions, the NRC is making it clear that the requirements are not meant to apply to current or future operating license applications for which construction permits were issued before the effective date of this final rule. This is because existing construction permits are likely to involve designs which are essentially complete and may involve sites where construction has already taken place. Applying the final rule to operating license applications for which there are existing construction permits could result in an unwarranted financial burden to change a design for a plant that is partially constructed. Such a financial burden is not justifiable in light of the fact that the NRC considers the events to which the aircraft impact rule is directed to be beyond-design-basis events and compliance with the rule is not needed for adequate protection to public health and safety or common defense and security.

What that concession did not admit was the enormous financial and schedule impact of applying the rule to two existing projects for which designs were already certified, firm EPC (engineering, procurement, and construction) contracts were already signed, certified cost and schedule estimates were already submitted to state-level rate regulators, and long lead-time components were already being manufactured.

Instead of moving forward as planned, the Vogtle-3 & -4 and Summer-2 & -3 projects were halted while the engineers began the unpredictable process of designing a compliant shield building using modern, but not-yet-tested construction techniques.

From the moment the redesign effort started, all of the meticulously created schedules and cost estimates became obsolete. As they would say in my previous profession, they were OBE (overcome by events.)

Of course, neither the vendors, Westinghouse and Chicago Bridge & Iron (neé Shaw), nor the utility customers, Southern and SCANA, stopped moving or spending money; there was too much at stake already.

Even though all parties knew that they could not finalize the requirements for the plant’s foundations until the shield building redesign was invented, tested, completed, and approved by the regulator, they could not halt site preparation or component manufacturing.

They could not stop the accumulation of ongoing interest payments on borrowed money. They could not stop construction of the training facilities or the hiring and prequalification training for future operators.

Why not correct the record?

I’ve spent much of the time since my visit trying to understand why no involved party has made a noticeable public effort to correct the record and explain that the delays were outside their control.

The answer I have discovered is completely unsatisfying. I asked some hard questions. Here is an example of the verbal and written replies:

“The issues raised in your questions are subjects of disputes that are currently in litigation. It is not appropriate to comment outside of the litigation process. The parties’ respective pleadings in the litigation set forth their positions.”

Apparently, the vendor team and the owners group would rather litigate and point fingers at each other rather than to tell a truthful story that identifies the real culprit.

Several industry experts have suggested that nuclear plant licensees are extremely reluctant to blame the regulators that still control their destiny.

It is beyond the scope of this commentary to open up the question of whether or not the Aircraft Impact Assessment rule was a reasonable response to the irrational fear induced by the events of 9/11.

It is not even my intention to question the reasonableness of applying the rule that is not required for adequate protection to projects that were already underway.

The mission of this commentary is to explain that the root cause of the schedule delays and cost increases for both the Vogtle-3 & -4 and Summer-2 & -3 projects was a national-level decision to force a substantial redesign after major project decisions had been made.

As long as the regulations do not change again, there now exist several designs that meet the new requirements. Customers that order those designs now should be able to avoid the impact of a midstream design change.

It would be in the best interests of the industry and the projects that are currently underway to make it clear that the Vogtle and Summer projects were the subject of a one-time decision.

They should not be seen as indications that the nuclear industry is incapable of achieving predictable cost and schedule performance.


Adams1Rod Adams is a nuclear advocate with extensive small nuclear plant operating experience. Adams is a former engineer officer, USS Von Steuben. He is the host and producer of The Atomic Show Podcast. Adams has been an ANS member since 2005. He writes about nuclear technology at his own blog, Atomic Insights.


Small Modular Reactors—US Capabilities and the Global Market

By Rod Adams

On March 31–April 1, Nuclear Energy Insider held its 4th Annual Small Modular Reactor (SMR) conference in Charlotte, NC (following on the 2nd ANS SMR Conference in November 2013—for notes and report from that embedded topical meeting, see here).

You can find a report of the first day of talks, presentations, and hallway conversations at SMRs—Why Not Now? Then When? That first day was focused almost exclusively on the US domestic market—the second day included some talks about US capabilities, but it was mainly focused on information useful to people interested in developing non-US markets.

Before I describe the specifics, I want to take the opportunity to compliment Nuclear Energy Insider for its well-organized meeting. Siobhan O’Meara did an admirable job putting together an informative agenda with capable speakers and keeping the event on schedule.

westinghouse smr 200x336

Westinghouse SMR

Robin Rickman, director of the SMR Project Office for Westinghouse Electric Company, provided a brief update on his company’s SMR effort and the status of its development. He then focused much of his talk on describing the mutual challenges faced by the SMR industry and the incredible array of commercial opportunities that he sees developing if the industry successfully addresses the challenges together.In early February, Danny Roderick, chief executive officer of Westinghouse, announced that his company was shifting engineering and licensing resources away from SMR development toward providing enhanced support for efforts to refine and complete the eight AP1000 construction projects in progress around the world.

Rickman explained this decision and its overall impact on SMR development. He told us that Westinghouse remains committed to the SMR industry and to resolving the mutual challenges that currently inhibit SMR development. His project office has retained a core group of licensing experts and design engineers and is fully supporting all industry efforts. The SMR design is at a stage of completion that enables the company to continue to engage with both customers and regulators based on a mature conceptual design.

The company, however, does not want to get ahead of potential customers and invest hundreds of millions of dollars into completing a design certification if there are no committed customers. Rickman didn’t say it, but Westinghouse has a corporate memory from the AP600 project of completing the process of getting a design certification in January 1999 without ever building a single unit. It’s not an experience that they have any desire to repeat.

Westinghouse determined that its resources could be best invested in making sure that the AP1000 is successful and enables others to succeed in attracting financing and additional interest in nuclear energy.

For SMRs, Westinghouse has a business model that indicates a need for a minimum order book of 30–50 units before it would make financial sense to invest in the detailed design and the modular manufacturing infrastructure required to build a competitive product. Rickman emphasized that all of the plant modules must be assembled in a factory and delivered to the site ready to be joined together in order to achieve the capital cost and delivery schedule needed to make SMRs competitive.

That model requires a substantial investment in the factories that will produce the components and the various modules that make up the completed plant. He told us that the state of Missouri is already investing in creating such an infrastructure with the support of all of its major universities, every electricity supplier, a large contingent of qualified manufacturing enterprises, both political parties, and the governor’s office.

He told the audience that Missouri’s efforts are not limited to supporting a single reactor vendor; it is building an infrastructure that will be able to support all of the proposed light water reactor designs including NuScale, mPower, and Holtec.

Rickman included a heartfelt plea for everyone to recognize the importance of creating a new clean energy alternative in a world where billions of people do not have access to light at the flip of a switch or clean water by opening a simple tap.

In what was a surprise to most attendees, the FBI had a table in the expo hall and gave a talk about its interest in the safety and security of nuclear materials. I will reveal my own skepticism about the notion that nuclear power plants are especially vulnerable or attractive targets for people with nefarious intent. It is hard to imagine anyone making off with nuclear fuel assemblies or being able to do anything especially dangerous with them in the highly unlikely event that they did manage to figure out how to get them out of a facility.

Bryan Hernadez, a refreshingly young engineer, gave an excellent presentation about the super heavy forging capabilities available in the United States at Lehigh Heavy Forge in Bethlehem, Pa. That facility is a legacy of what formerly was the Bethlehem Steel Corporation’s massive integrated steel mill. It has the capacity to forge essentially every component that would be required to produce any of the proposed light water SMR designs.

The presentation included a number of photos that must have warmed the heart of anyone in the audience who likes learning about massive equipment designed to produce high quality goods with tight tolerances that weigh several hundred tons.

In a presentation that would have pleased several of my former bosses, Dr. Ben Amaba, a worldwide sales executive from IBM, talked about the importance of approaching complex designs with a system engineering approach and modern information tools capable of managing interrelated requirements. That is especially important in a highly regulated environment with a globally integrated supply chain.

Jonathan Hinze, senior vice president of Ux Consulting, provided an overview of both national and international markets and described those places that his company believes have the most pressing interest in machines with the characteristics being designed into SMRs.

He reminded the audience that US suppliers are not the only players in the market and that they are not even the current market leaders. He noted the fact that Russia is installing two KLT-40 power plants (light water reactors derived from established icebreaker power plants) onto a barge and that those reactors should be operating in a couple of years. He pointed to the Chinese HTR-PM, which is a power plant with two helium–cooled pebble bed reactors producing 250 MW of thermal power producing steam and feeding a common 210-MWe steam turbine power plant. He also mentioned that Argentina had recently announced that it had broken ground on a 25-MWe CAREM light water reactor.

Douglass Miller, acting director of New Major Facilities Division of the Canadian Nuclear Safety Commission, described his organization’s performance-based approach to nuclear plant licensing. He noted that the commission does not have a design certification process and that each project needs to develop its safety case individually to present to the regulator. It appears that the process is not as prescribed or as time-consuming as the existing process in the United States.

Tony Irwin, technical director for SMR Nuclear Technology Pty Ltd, told us that Australia is moving ever closer to accepting the idea that nuclear energy could play a role in its energy supply system. Currently, the only reactor operating in Australia is a research and isotope production reactor built by INVAP of Argentina. He described the large power requirements for mining operations in places not served by the grid and the fact that his country has widely distributed settlements that are not well-integrated in a large power grid. He believes that SMRs are well suited to meeting Australia’s needs.

Unfortunately, I had to get on the road to avoid traffic and get home at a reasonable hour, so I missed the last two presentations of the day. I probably should have stayed to hear about the cost benefits of advanced, non-light water reactors and about Sweden’s efforts to develop a 3-MWe lead–cooled fast reactor for deployment to Canadian arctic communities.

As I was finalizing this post, I noted that Marv Fertel has just published a guest post at NEI Nuclear Notes titled Why DOE Should Back SMR Development. I recommend that anyone interested in SMRs go and read Fertel’s thoughts on the important role that SMRs can play in meeting future energy needs.

SMR on trailer courtesy NuScale Power

SMR on trailer – courtesy NuScale Power




Rod Adams is a nuclear advocate with extensive small nuclear plant operating experience. Adams is a former engineer officer, USS Von Steuben. He is the host and producer of The Atomic Show Podcast. Adams has been an ANS member since 2005. He writes about nuclear technology at his own blog, Atomic Insights.

Nuclear Matinée: Journey of the Flamanville Reactor Pressure Vessel

Today’s ANS Nuclear Cafe Matinée takes faithful viewers through the beautiful waterways and countryside of France, following the route of the massive reactor pressure vessel being delivered to the new 1,650 MWe European Pressurized Reactor under construction at the Flamanville Nuclear Power Plant.

A caveat: Users must supply their own sound track, as these are silent movies.  Hmm… The Pointer Sisters’ Neutron Dance is quite upbeat, but not bucolic.  George Clinton’s Atomic Dog doesn’t quite capture the moment.  Perhaps something French?  La Marseillaise?

At any rate, enjoy the journey!

Thanks to Salle de Presse Youtube for posting these fine videos, and thanks to the Nuclear Street News Team who posted these videos earlier.

flamanville epr rpv 355x201 

Fighting for the Next Inch

By Peter Shaw

I had an interesting conversation with some colleagues last night. We were talking about our jobs, and it turned out that some of them were considering moving on to new prospects outside of the nuclear industry. After digging in to the reasons why, the sentiment seemed to come down to “It feels like we’re running as hard as we can only to gain inches every day.”

There is a constant fight for nuclear’s progress in public perception, regulatory oversight, and demands for perfection. The stagnation of progress was what was so frustrating to them.

Here at the Vogtle nuclear power plant in Georgia, where construction of two new reactors is occurring, people are working on systems right now and comprehensively understanding their behaviors under normal plant operations, while the components themselves are only ink on paper. We are testing, retesting, and scrutinizing every last detail of every piece that is going into the nuclear island. We look at diameter, radius, flow rate, material certification, and thickness. We document the construction, the fabrication, any deviations, the corrections, the exchange of our corrections, the meetings that approve the corrections—and if we missed any of those steps, we have another corrective action to document that.

Why this level of seeming absurdity? Well, it is our duty to make sure that we never lose ground, that we document things to this level, that we perform beyond what we think our limit is. It is our duty to always be better. Every document that we sign, every peer or family member that finally comes around, every congressman we persuade, every argument in which we triumph, that is an inch that does not slip.

How do we ensure that? Through our culture. Our nuclear safety culture is the only thing that can breed the trust that we deserve to be a viable energy solution for the future.

Nuclear culture is all about asking questions, and its most underutilized component is corrective actions. I have seen companies pull off their corrective actions brilliantly. It isn’t easy but it is possible; you need to staff up and dedicate your company to identify and correct any problems that come up. Improvements need to be funneled and optimized to run projects better. As a person, you can never afford to see corrective actions as a negative, even when you have the weight of an angry manager breathing down your neck.

If someone calls into question the quality of our construction—this is when I laugh. I do so because this is how we run our industry, through scrutiny and questioning attitudes. Because of this, nuclear fosters a different kind of thinking; there are those of us who are in it because it is a prestigious stepping stone, others who are interested in a career—and there are some of us for whom this is a passion. Some of us are vehement in our will to succeed because, to us, there is no other option.

I mean that in a literal sense. There is in my mind no better energy option than having a nuclear fleet, augmented with passive energy collection, that supports an infrastructure of homes and businesses with all the electric power they could need.

I am an idealist; I believe that what I do every day is injecting some good into the world. Everyone deserves to have energy; every person on this planet has the right to survive despite the sweltering heat of summer, or have the ability to turn on a computer that will link them with the rest of the world. There is one thing that every human needs on this planet along with food, water, and shelter, and that is electric power. There are only inches gained, but those inches are precious.

I don’t begrudge anyone who wants to leave the nuclear industry—it’s a tough call to action, and I can understand how it could wear you out. Every day we come in and stand up to more scrutiny than any other industry in the world. While we complete this Vogtle project, elsewhere four or five natural gas facilities will have been built, more coal plants go up in the world, and more windmills too. In the end, though, nuclear isn’t about fast action, it’s about longevity.

When natural gas spikes again and the generators go quiet, we’ll keep chugging along. When coal gets a carbon cap put on it and stops spewing pollution into the atmosphere that we all share, we’ll still be churning through our own fuel. When the windmills stop turning because the wind is blowing the wrong direction, we’ll be running through our +97 percent uptime.

And I’ll be coming in to work that day, fighting for the next inch.

vogtle deaerator 300x200


peter shaw bio 100x150Peter Shaw is a senior licensing engineer at Westinghouse Electric Company for the Vogtle project. He is very involved in North American Young Generation in Nuclear and the American Nuclear Society, and is a member of the ANS Young Members Group and Operations & Power Division.

Nuclear Matinee: Taylor Wilson’s radical plan for small nuclear fission reactors

A video was uploaded recently at TED Talks that has caused a bit of a stir around the internet. Nuclear scientist Taylor Wilson, 19 years of age, enthusiastically sets out to solve the problem that underlies all others: Energy.

In this video, Wilson announces his variation of a Molten Salt Small Modular Reactor, and explains some of the anticipated advantages of this version of “factory-produced” nuclear power—such as an ability to burn up stockpiles of nuclear weapons materials, less leftover waste, and a sealed system requiring no refueling. The system would feature inherent, passive safety due to operation at atmospheric pressure—and such a reactor could provide a compact source of enormous power that would revolutionize space exploration.

The general ideas presented are not entirely new. In fact, the first molten salt reactor was built at Oak Ridge National Laboratory decades ago, and several entities around the world are currently researching and developing molten salt reactors (for example, Transatomic Power, Flibe Energy, Terrestrial Energy). We shall see what the future holds—in the meantime, enjoy this inspiring and engaging presentation:

Elizabeth Palermo with the story at TechNewsDaily Teenager Designs Safer Nuclear Power Plants.

Thanks to TED Talks


Inherent and engineered safety: Did Weinberg predict today’s reactors a quarter century ago?

By Will Davis

Following the Three Mile Island (TMI) accident on March 28, 1979, it seemed to many as if a slowing nuclear energy industry in the United States had been dealt a death blow. It had not, but the public’s confidence was shaken, and this blow to public opinion built upon a decade’s worth of intensive, focused anti-nuclear effort on the part of a number of large well-funded special interest groups.



Once the causes of the TMI accident were well understood, the task was taken up to predict what would be desirable for increased public support for new reactor construction. Alvin M. Weinberg headed a group that performed such a study under a 1981 request by the Institute for Energy Analysis; the published result was the book The Second Nuclear Era—A New Start for Nuclear Power (1985).

The conclusions reached were numerous in terms of specific recommendations, and the determination as to reactor technology was clear: Contemporary light water reactor (LWR) plants at the time, given their previous safety record, were acceptable to the public—and future designs should be improved and be either inherently or passively safe, certainly in terms of cooling, and perhaps even in terms of shutdown. The group believed that the future of nuclear energy in the United States would initially be based on proven technologies, either already in wide use (LWR plants, specifically pressurized water reactors/PWRs), or already developed to the point of commercial application (high temperature gas-cooled reactor (HTGR) plants, such as Peach Bottom-1 and Fort St. Vrain.)

Contemporary designs (1980s) and development

The earliest nuclear reactor plants were designed with basic water injection systems intended mostly to handle “makeup”—because of the early emphasis in design basis accident analysis for rapid-loss-of-coolant accidents, most had some way to rapidly make up water should a large primary coolant pipe break. This essentially covers most designs through the mid-1960s.

In the middle of 1966, ongoing work by the Atomic Energy Commission (AEC) and the Advisory Committee on Reactor Safeguards, in the processing of applications for comparatively very large reactor plants, began to “force the issue” of increased emergency core cooling systems (ECCS) to the forefront of discussion. The radioactive release possible with larger cores had not been considered in previous standardized siting criteria, or accident analysis. Dr. William E. Ergen was appointed by the AEC’s director of regulation to form a task force to study this problem; the major result was the determination that a relatively much larger, newer core, if uncooled, could cause melt-through of the reactor vessel (because larger power output plants did not have proportionately larger total area for heat dissipation, without added forced dynamic cooling; whereas earlier reactor cores could survive being uncooled.)

Indian Point 1

Indian Point-1

The Ergen Report made it clear that greatly enhanced ECCS capability would be needed to continue to prove safety, and AEC ordered that plants had to fit or backfit new, higher-capacity equipment meeting revised ECCS requirements by 1974. Plants that were unable to comply had to be shut down; Indian Point-1 shut down permanently in 1974 for this reason.

This improvement in ECCS focus led indirectly to the ability to build nuclear plants in locations previously not considered possible by then-used siting criteria. A letter from the ACRS to the chairman of the AEC in 1964, when early consideration of improved safeguards was underway, stated in part:

“It is the opinion of the Advisory Committee on Reactor Safeguards that the including of properly engineered safeguards in reactor plants can permit the reduction of distances required for protection of the public and that engineered safeguards of selected type should make feasible the siting of power reactors at many locations not otherwise considered as suitable.”

Post-TMI:  Cancellations and public opinion

The causes of the TMI accident were many, varied, and in many ways intertwined. The complexity of the problems facing the industry became clearer as months of reviews and rulemaking dragged into years, and many nuclear plants under construction began to experience incredible delays—first, when all licensing was held up; and then, when plant owners and operators attempted to determine how to backfit or modify existing designs to bring new, but not-yet-started, reactors up to the present specification (which was itself a moving target). For example, in 1983, Detroit Edison stated that costs for its yet-to-start Fermi-2 had skyrocketed due to, among other things, $138 million in TMI-related backfits and modifications.

earth day 1970 150x150The effect of TMI on public opinion is commonly stated today in the press as something of a “death blow,” but this is inaccurate. First, public opinion about nuclear energy was starting to move since about 1970, with the first Earth Day and the passage of the National Environmental Policy Act (which later would be used to force nuclear plants to consider environmental impact as a stand-alone topic, which was not done originally). According to a compilation of public opinion research and analysis entitled Public Opinion and Nuclear Energy (1983), public opinion in the United States was already shifting in the mid-1970s away from mostly supporting nuclear power, and public beliefs about reactor safety “changed somewhat from 1975 through 1980.” Public opinion was beginning to change before TMI happened.

Also, public discourse over cost, delays, and cancellations of nuclear plants was increasing. Over 30 nuclear plants had been cancelled, and a number of plants under construction had been pushed back, prior to TMI. This trend increased after TMI.

However, according to this study, opinions on nuclear energy in the United States still did not swing wholly anti-nuclear by any means as a result of the TMI accident. In this study’s summary of post-TMI surveys, it is concluded that

“Although a majority of the general public and most leadership groups believed that there is no guarantee against a catastrophic nuclear accident and that fundamental regulatory changes are necessary to keep risks within tolerable limits, a majority of the public and leadership groups favored the continued use and expansion of nuclear power.”

Weinberg and the direction to a second nuclear era

We have covered a “snapshot” of the development of the nuclear industry in terms of safety engineering (by no means complete; a detailed study would require a career or two) and a “snapshot” of public opinion when Weinberg and his group were tasked to imagine a “way out” for the nuclear industry and nuclear power. As it turns out, Weinberg’s general predictions (detailed earlier) were exactly correct; however, a shortcoming in the study’s conclusion was a dependence on either wholly new plant designs or the use of already-sidelined designs in pursuit of the stated goals.

pius 150x181

PIUS – click to enlarge

Weinberg and his cohorts did in fact admit that contemporary LWR designs (Westinghouse SNUPPS/Sizewell B, GE ABWR, Combustion Engineering System 80) were safe enough for public acceptance, but stressed a look forward to two other designs—the Process Inherent Ultimate Safety (PIUS) reactor, and a form of HTGR. The PIUS was a radically different type of light-water-cooled reactor, developed conceptually by ASEA-ATOM (Sweden), that used a gigantic prestressed concrete vessel, no control rods (reactivity control by boron and temperature only), and was said to have a “hands off” time of  one week, in which no operator action was required after any potentially damaging failure. The core would remain covered and cooled at all times in this unusual, and never-built, design. The other design that Weinberg’s team selected was a General Atomics HTGR, helium cooled and graphite moderated, with inherent safety features and guaranteed core cooling capability by virtue of basic design—also never built.

What is significant about the selected designs is their “walk away” capability, wherein no operator action was required after potentially damaging incidents (such as loss of all electrical power.) Weinberg was essentially correct in believing that this would be required to gain public acceptance on a wide scale; what he did not envision was a way to mate existing, developed reactor plant design (hardware) with his vision of inherent or “walk away” safety to arrive at a workable, licenseable, affordable, and realistic nuclear power plant. The industry had already, by that time, become wary of any design that was not a light-water-cooled reactor, either PWR or BWR, and the post-TMI licensing logjam practically guaranteed that no radically new design would be licensed in any realistic or desirable time frame (and a reduction in estimated electricity demand guaranteed that no utility would try.)

The future from the past—AP600 to AP1000

In 1992, the National Academy of Sciences (NAS) conducted a study that, among other things, developed a list of promising reactor designs for future application. While the PIUS and another gas-cooled reactor still figured in the NAS report, the bulk of the recommended designs were LWR plants grouped into two categories—”Large evolutionary LWR” plants such as the ABB- Combustion System 80, the GE ABWR, and the Westinghouse APWR (later to become the Mitsubishi APWR and eventually the US-APWR designs) and also, interestingly, “Mid-size passive LWRs” which included a GE SBWR or “Simplified Boiling Water Reactor,” and a Westinghouse design known as the AP600, for “Advanced Passive 600.”

The AP600 design was originally developed with support from the US Department of Energy and the Electric Power Research Institute as a simpler, less complicated, and less expensive proposition than large commercial nuclear stations with net outputs over 1000 MWe. At the time the AP600 was conceived, modular construction was incorporated in the design (as it is with today’s familiar AP1000) and the innovative passive cooling features seen in today’s AP1000 were also incorporated—including the core makeup tanks, accumulators, and the IRWST or in-containment refueling water storage tank. After exhaustive review, the AP600 was given design certification by the Nuclear Regulatory Commission in December, 1999.

The AP600 was not large enough to attract utilities in the United States, but a much larger 1000-MWe direct descendant—the AP1000—was; Westinghouse filed an application for design certification for this large, advanced passive-cooling plant in 2002, and the design was certified in December 2011.

©2013 Westinghouse Electric Company LLC.  All right reserved.  Image reproduced with Westinghouse’s permission.

Westinghouse AP1000
©2013 Westinghouse Electric Company LLC. All rights reserved. Image reproduced with Westinghouse permission.

In the requirements for passive safety—ECCS requirements that didn’t involve large offsite or onsite AC power supply, and didn’t require operator action—Weinberg, et al. were fully correct in their conception of what a continuous drive for safety, and thus public acceptance, demanded. Public misinformation about nuclear energy had so badly eroded realistic perceptions that, after TMI, many in the public actually believed that nuclear reactors could explode like nuclear weapons—which drove home the need for both a major shift in public perception and a major push in the industry for truly passive, and truly credible, core safety.

Weinberg and his team, however, did not anticipate that developments originally intended for intermediate-sized, less expensive plants for remote siting would be successfully applied to commercial (1000 MWe+) sized plants, giving both the safety required and the necessary dependence on the rugged engineering of decades of previous LWR experience. The selection of the recommended PIUS design, for example, was made in part because it could build on previous LWR experience; the text is quoted as saying “since PIUS is a modified PWR, much technology already in commercial use could be applied.”

What really happened was that passive features were eventually applied external to the core, and external to the containment, which along with rugged (and in some ways traditional) construction of the primary plant worked together to assure safety. There was no need for a radical departure at highest possible speed from most or all of conventional LWR technology; the best (and the ultimate) solution was to apply passive cooling principles to developed PWR design—a vision targeted not specifically by Weinberg and his team, but targeted perfectly in effect.


Bodansky, D.; Nuclear Energy – Principles, Practices and Prospects. New York.  Springer-Verlag 1986.

Detroit Edison Company; A History of Enrico Fermi Atomic Power Plant Unit 2. August 1983.

Nealey, S. M.; Melber, B. D.; Rankin, W. L.; Public Opinion and Nuclear Energy. Lexington, Mass. D. C. Heath and Company 1983.

US Atomic Energy Commission—WASH 1082, Civilian Nuclear Power—Current Status & Future Technical & Economic Potential of Light Water Reactors. March 1968.

US Atomic Energy Commission—WASH 1250, The Safety of Nuclear Power Reactors (Light Water-Cooled) and Related Facilities. July 1973.

Weinberg, A. M.; Spiewak, I.; Barkenbus, J. N.; Livingston, R. S.; Phung, Doan L.; The Second Nuclear Era—A New Start for Nuclear Power. New York. Praeger Publishers 1985.


WillDavisNewBioPicWill Davis is a consultant to, and writer for, the American Nuclear Society. In addition to this, he is a contributing author for Fuel Cycle Week, and also writes his own blog Atomic Power Review. Davis is a former US Navy Reactor Operator, qualified on S8G and S5W plants.

Update and Perspective on Small Modular Reactor Development

By Jim Hopf

The US Department of Energy has a $452 million program to share development and licensing costs for selected small modular reactor (SMR) designs. The DOE’s goal is to have an operating SMR by ~2022. Last November, the DOE awarded the first grant to the B&W mPowerTM reactor. In more recent news, the DOE has decided to issue a follow-on solicitation to enter a similar cost-sharing agreement with one or more other SMR vendors (and their SMR designs). The status of development and licensing for several SMR designs are summarized below.

mPower (B&W)

B&W mPower SMR

The mPower reactor is a 180-MW pressurized water reactor. B&W was awarded the first cost-sharing agreement under the DOE’s SMR development program in November 2012. B&W has teamed up with Bechtel and the Tennessee Valley Authority to design, license, and build a set of 2-6 mPower modules at TVA’s Clinch River site. B&W plans to submit its design certification application (DCA) to the Nuclear Regulatory Commission by the end of this year.


The NuScale reactor is an even smaller, 45-MW PWR reactor module. NuScale Power will apply for the follow-on (second round) DOE program cost-sharing award that was just announced. It has partnered with Fluor to develop and build the SMR, and is considering building its first SMR modules at the DOE Savannah River Site (SRS). It expects to submit its DCA to the NRC some time in 2015.


Holtec International, which is developing a 160-MW (light water) SMR, may also apply for the second DOE grant, and is also interested in constructing its SMR at the SRS site.


Westinghouse is developing a 225-MW PWR that shares many design features of its larger AP1000 plant. It is partnering with Burns & McDonnell, Electric Boat, and the Ameren utility to design, license, and build its first SMR plant at Ameren’s existing Callaway plant site in Missouri. It is expected to also apply for the second round of cost-sharing grants under the DOE’s SMR program. Westinghouse is expected to submit its DCA to the NRC in 2014.


The most advanced non-light water SMR project is the Gen4 Energy’s lead-bismuth-cooled 25-MW reactor module (formerly Hyperion). Given the DOE’s focus on near-term SMR deployment, however, and the NRC’s indication that licensing a non-LWR will take a much longer amount of time, it is unclear whether non-light water SMRs have much prospect for winning a cost-sharing award under the DOE’s current SMR development program. Gen4 Energy withdrew its application for the initial round of DOE grants and it is not clear if it will apply for the second round.

Key desirable SMR features

My personal view is that SMRs should (ideally) have the following three features, entirely or to the extent possible:

  • The entire nuclear steam supply system (NSSS) can be factory built and rail-shipped to site.
  • The reactor can go indefinitely without offsite power or forced (pumped) cooling.
  • No on-site construction subject to NQA-1 requirements.

In a recent ANS post, I discussed issues such as the basemat rebar (and other) problems at Vogtle, as an example of the problems that are likely to occur when there are a large number of construction activities that are subject to NQA-1 and NRC oversight being performed on site, often by local suppliers or craft labor that do not have extensive experience with nuclear-related construction. Processes are much more controlled in a factory setting, where one is simply making a large number of copies of the exact same product (reactor design). Also, the factory would have dedicated staff that is highly experienced in making copies of that one product, and is very experienced with the applicable nuclear-grade fabrication and quality assurance requirements (e.g., NQA-1). The result is much higher levels of quality and consistency, with much less in the way of cost overruns or schedule delays.

For these reasons, it is imperative to have as much of the safety/nuclear-related construction as possible be done at the factory, and to minimize assembly and construction activities at the plant site. Thus, it is very preferable to have the entire NSSS (reactor and steam supply system, e.g., steam generators) sealed inside a container that can be shipped by rail to the plant site, without any at-site assembly required. Ideally, all components necessary for safety would be inside the “box” that arrives on the rail car, resulting in only non-nuclear grade construction activities at the site.

In that recent ANS post, I suggested that due to spiraling nuclear plant construction costs, a bottoms-up review is in order, in which all regulations and requirements are put on the table and objectively evaluated (using detailed probabilistic risk analyses, etc.) in terms of how much “bang for the buck” we’re getting in terms of overall safety. I made the suggestion (provocative to many, I’m sure) that NQA-1, i.e., a unique and extremely strict set of fabrication/QA requirements that only applies to the nuclear industry, most likely does not produce much safety benefit relative to its associated cost. I suggested that more typical QA standards and procedures that are used in most other large construction projects (bridges, dams, etc.) be used instead.

Well, with SMRs a “compromise” may be possible. Based on recent experience with Areva’s EPR (at Olkiluoko) and now at Vogtle, I had come to doubt that it was possible or practical to comply with those NRC and NQA-1 requirements, with on-site plant construction anyway. It seemed to be too difficult to comply with such strict requirements under field conditions, especially given the use of local labor and suppliers that do not have extensive experience with those requirements. The factory assembly line setting, however, is one setting where I can imagine it being practical to comply with strict NRC/NQA-1 requirements (with highly experienced staff, a controlled process, and NRC inspectors permanently present at the factory site).

Thus, with SMRs, almost all important-to-safety fabrication is performed at the factory site, and it could still be held to NQA-1 standards. Onsite activities at the nuclear plant that are subject to NQA-1 requirements can be greatly reduced or perhaps (as part of a “compromise”) eliminated. In my view, not having onsite construction activities be subject to (nuclear-unique) NQA-1 requirements, and instead letting the local construction entities use more typical QA requirements that they are familiar with, would greatly reduce costs and the risks of schedule delays, rework, and cost overruns. On the other hand, having NQA-1 standards apply at the reactor module factory would deliver virtually all of NQA-1’s safety benefit, without significantly increasing costs.

Finally, it would be highly desirable for the plant to have the attribute of always remaining sufficiently cool to avoid meltdown for an indefinite period without any outside power or active cooling (pumps, etc.). Post-Fukushima, such a feature may greatly increase political and public support for the reactor design. Also, such a feature would greatly reduce the plausible conditions under which meltdown and release could possibly occur. This, in turn, could greatly reduce the number of components or systems that must be classified as “safety related”, which would result in significant cost reductions (as well as reductions in actual accident/release probability).

Features of SMR candidates

The main SMR candidates that meet the goals listed above are as follows, based on their publicly presented information:

The mPower and NuScale vendors state that their entire NSSS will be fabricated at the factory and shipped (whole) to the plant site. Westinghouse is less clear, referring to “rail shippable scale” (which could refer to the entire NSSS, or a small number of NSSS component modules, which would require a limited amount of on-site assembly).

Hauling the NuScale reactor

NuScale very clearly states that its SMR is entirely passively cooled, and can go indefinitely without outside power and active (pumped) cooling. B&W (mPower) is less clear on this point, stating that no AC power is required for design basis safety functions, that they have three-day batteries to support DC-powered accident mitigation, and that the station can go up to 14 days (under loss of power conditions) without outside intervention. Gen4 Energy also states that its (lead-bismuth) reactor can go 14 days without power. I could not find a statement from Westinghouse concerning how long its SMR can go without any external power. Westinghouse does make reference to the operator having to add water (to a large tank) after seven days.

As expected, none of the SMR vendors discuss fabrication QA requirements for at-plant-site construction and components, or how many such components would be classified as safety related. Some have, however, performed some PRA analyses and do discuss the very low probability of core damage and significant release for their reactors. B&W (mPower) and NuScale state that their core damage frequencies (CDFs) are 10-8 and 10-7 per reactor year, respectively. By comparison, currently operating plants generally have CDFs of ~10-4 per reactor year and more recent large plants (e.g., AP1000) have CDFs under 10-6.

Cost and safety tradeoffs

Due to their smaller size and lower power densities, SMRs offer inherent safety advantages, largely because smaller reactors are easier to keep cool. As shown above, their chances of core damage are far lower than those of large reactors. In addition to a lower probability of core damage, their much smaller fuel inventory greatly reduces the maximum possible release. In fact, since these reactors probably can’t get nearly as hot, even in a core damage scenario, I’m guessing that their maximum core inventory release fractions (e.g., for cesium) under even worst-case meltdown conditions are also significantly smaller than those that apply for larger reactors. Thus, the maximum possible release is probably even less than the ratio of reactor powers (MW) would imply.

In order to get these advantages (along with the advantages of assembly line construction), they have to give up on economy of scale and power density, which will tend to increase costs. Some SMR vendors claim that groups of their modules will produce less expensive power than large reactors (e.g., the AP1000), but this remains to be seen. It is also unclear whether these modular reactors will be less expensive than fossil fuels (particularly gas). As I’ve often stated, these reactors cannot provide any health, environmental, or global warming benefits if they are not deployed. Thus, some actions may need to be taken to reduce costs.

This leads me to ask what SMRs will “get in return” for what they are giving up in terms of scale, power density, and increased fundamental safety. We may have to ask if there are any measures that could be taken that would reduce costs but result in a release probability that is closer to that of, say, the AP1000, as opposed to being orders of magnitude lower. In these evaluations, the much lower potential release from these reactors should also be fully considered. I believe that thorough evaluations of all potential cost-saving measures, supported by detailed PRA evaluations, should be performed.

One idea I discussed earlier is to use ordinary construction QA requirements for all on-site construction activities (i.e., for everything outside the NSSS that arrives by rail car). Given the much lower likelihood of core damage/release, the much smaller potential releases, and the fact that components outside the NSSS have a relatively small impact on overall safety (especially for these reactors), such an approach would be justified. In evaluating such an approach, we need to make reasonable determinations of both the probability and possible nature of failures of non-nuclear-qualified components. For example, the NuScale reactors lay in a large pool of water inside a concrete-walled underground pit. We have to ask ourselves: Is there any way the concrete could fail that would result in the water disappearing (especially given that the pool is underground)?

Other issues are operator and security staffing levels. The simplicity and inherently better safety of these designs should reduce the number of required operators and staff (and some SMR vendors are claiming just that). Security costs could be greatly reduced (in my view) if SMRs are placed on existing sites where large reactors already exist. Little extra security should be required, since the site is already protected.

Also, as discussed in my earlier post, licensing review should be fairly limited if one is placing a certified SMR design on a site that already has reactors. Almost like spent fuel dry storage casks, a simple review of the existing site evaluations, to verify that external parameters such as maximum ground accelerations and other environmental factors are bounded by the SMR’s generic safety evaluations, should be sufficient. An evaluation of some bounding number of reactor modules would then be done to address any impacts of the reactors on the site (e.g., a site boundary dose evaluation). After that is done, modules could be added without further licensing activity.

The NRC’s general philosophies, however, as well as some of its recent actions, leads me to believe that any kind of compromise may be too much to expect. In response to Fukushima, the NRC is increasing nuclear regulations even further. While we all agree that some specific improvements can and should be made as a result of lessons learned from Fukushima, there has been absolutely no discussion at all about whether any requirements should be pared back. This, despite the fact that Fukushima showed that the consequences of a severe (almost worst-case) meltdown are FAR smaller than what we had thought (and far smaller than the assumed accident consequences that many if not most of those requirements were based upon). For this reason, I’m inclined to believe that the NRC will take all the benefits of SMRs (i.e., the great reduction in release probability due to fundamental features) and give absolutely nothing back. That, despite the fact that some economic sacrifices (on economy of scale) had to be made in order to get those fundamental increases in safety.

If SMRs are to be viable, and provide safety, health, environmental, and global warming benefits, the NRC is going to have to make some compromises. If they do, SMRs may be able to provide an option that is not only economically competitive (allowing it to displace harmful fossil fuels), but is also far safer than current US nuclear plants, and as safe or safer than new large plants such as the AP1000.



Jim Hopf is a senior nuclear engineer with more than 20 years of experience in shielding and criticality analysis and design for spent fuel dry storage and transportation systems. He has been involved in nuclear advocacy for 10+ years, and is a member of the ANS Public Information Committee. He is a regular contributor to the ANS Nuclear Cafe.

Fukushima Two Years Later

by Will Davis

At about a quarter to three in the afternoon on March 11, 2011, a gigantic and unprecedented earthquake struck just over 110 miles off the coast of Fukushima Prefecture in Japan. The quake was followed, just over 40 minutes later, by the first of several rounds of tsunami, which inundated enormous areas and eradicated entire towns and villages. Over 19,000 people were killed or are still missing, and over 6,000 survivors were injured.

Central to most narratives on this cataclysmic natural disaster has been the story of the Fukushima Daiichi nuclear accident. While no deaths have been attributed to the nuclear accident itself, or to radioactive contamination released from the plant, and while deaths at the Fukushima Daiichi nuclear site proper have been very few (three persons were killed on the day of the earthquake and tsunami—one by falling from a crane, two by drowning), the story of the nuclear accident continues to dominate press worldwide.

As we approach the two-year anniversary of these events, it’s important to look back and ask some honest and direct questions about the nuclear accident and how it relates to us here in the United States. What do we know now that we didn’t in the early days? Can we say for sure what was happening, both on a large and on a minute scale? Could the accident have been prevented? What are we doing to ensure something similar never happens again? What about the radiation exposure to the public? We will try to answer these and other important questions as we look back at two years’ worth of study and analysis, recovery and cleanup, and planning and preparing.

(Above, Fukushima Daiichi nuclear power station under construction in 1971. To the left of the photo, Units 1 and 2 can be seen complete while Unit 3 is under construction; Unit 4 has not yet been started. Nearer the camera is the construction site for Units 5 and 6. Photo courtesy Will Davis collection.)

The Great Tohoku Earthquake and Tsunami … and what we now know

As already described, the earthquake struck at 2:46 PM local time, and at that moment the three operating reactors at Fukushima Daiichi—Units 1, 2, and 3—detected the earthquake and were immediately shut down on a seismic scram signal. (The other units—4, 5, and 6—were shut down for maintenance.) Simultaneous with this event was a LOOP (loss of offsite power), caused by the electric distribution system outside the plant being damaged by the earthquake. At the Fukushima Daiichi station, the emergency diesel generators started as designed, and provided power to begin cooling down the three reactors that had been operating.

There has been speculation in some quarters that the earthquake caused damage to the plants and that this helped lead to the accident. In fact, all indications are that plant operations were nominal from the point of the seismic shutdown, LOOP event, and commencement of shutdown cooling at the three operating plants. As late as last November, presentations by the Tokyo Electric Power Company at the American Nuclear Society Winter Meeting revealed no suspicion of material failures at the plants prior to the tsunami’s arrival, as corroborated by recorded plant parameters and operator statements.

Of course, the actual triggering event of the accident was the tsunami-derived inundation of the plant 40 minutes after the earthquake, which, because of the pressure of the violent inrush of water, caused more physical damage than an equivalent–depth slow flooding event. The tsunami flooded the plant because the protection was inadequate; the protection guarded against tsunami of nearly 20 feet while the actual event was almost 50 feet. It should be noted, though, that an unanticipated factor in the event was the fact that the coastline actually dropped several feet—thus negating a percentage of the tsunami protection.

The inundation of the plants meant that both the (mostly below ground) diesel generators and near-grade electric distribution equipment was rendered inoperable. This is the situation called SBO (station blackout), where no AC power is available at all. Generators were called for, and shipped from outside the plant, but the sheer damage to the site made bringing them in and moving them around exceedingly difficult. In addition, procedures for their use did not really exist. The total loss of AC power meant that only DC power, to operate some valves and instruments, was available—and even this was limited not only by the time until the batteries discharged, but also by damage as well. At that point, the plant was crippled by loss of power, serious physical damage, confusion on site due to communication problems (and continued aftershocks), and lack of solid emergency operating procedures in such events. This led to a loss of cooling for Units 1, 2, and 3 reactor cores, ultimately resulting in severe core damage. Failure of the containment function of the reactor buildings led to the release of radioactive material to the environment.

At the ANS 2012 Winter Meeting, Akira Kawano of TEPCO stated that spare seawater pumps (both portable pumps, and replacements for built-in or installed pumps destroyed by the tsunami), spare sources of electric power (of all three ranges—high voltage AC, low voltage AC, and DC—used at the plant) and spare pressure cylinders to allow operation of valves after loss of electric power would have been exceedingly helpful in the hours after the tsunami. TEPCO has gone far beyond provision of these items, though, in its plan for tsunami protection at nuclear plants in the future.

It is important to point out that Units 5 and 6 did not experience a long-term blackout because one of the above ground air-cooled diesel generators installed at that northern section of the site remained fully operable. This diesel was at Unit 6, but power was patched in from it to Unit 5 later. Air-cooled diesels did exist at the area of Units 1 through 4, but the destruction of the electric distribution network inside the plants by water coupled with the loss of fuel tanks rendered these useless. (In this case, “air cooled” means that the diesels used conventional radiators to dissipate waste heat to the air, unlike the large emergency diesel generators that required seawater systems to be operable in order to dissipate engine heat.)

Regarding this tsunami damage and its implications, TEPCO has addressed its future commitment to safety at its nuclear plants by designating three courses of action:  First, it will take what it calls “Thorough Tsunami Countermeasures,” which means large seawall protection, protection of buildings inside the seawall should the seawall be breached, and also provision of multiple backup power sources. Second of the triad is “Securing Functions by Adopting Flexible Countermeasures,” by which it is meant that many varied backup power sources and sources of site assistance will be spread among many other sites. Finally, under “Mitigation of the Impact after Reactor Core Damage,” TEPCO plans to make serious preparations to control events, even should the first two steps fail. This includes, but is not limited to, installation of hardened, filtered containment vents that can be operated remotely under even accident conditions. Click here to see a brief TEPCO synopsis of its accident analysis report that contains these three steps.

Eventually, all operators of nuclear plants in Japan will take serious measures like those described above, and more, to prepare the sites and personnel against future events like this. Some have already begun; click here to see a detailed account of preparations at two different sites in Japan. These efforts are enormous; Chubu Electric Power has stated that it will invest 140 billion yen (about US$1.47 billion)  in its Hamaoka nuclear plant upgrades.

At left, view of Fukushima Daiichi Units 1 through 4 after the accident. Photo courtesy Japanese Maritime Self Defense Force.

Two of the reactor buildings at Fukushima Daiichi were severely damaged, and another partly damaged, by explosions of hydrogen gas that was generated by the damaged fuel while in contact with steam. This hydrogen got into the reactor buildings, built up in concentration, and later (quite famously, for both explosions were filmed from a distance) caused explosions in Unit 1 and Unit 3 reactor buildings. Evidence delivered by TEPCO at the ANS 2012 Winter Meeting now shows that the probable leakage point of the hydrogen into the primary containments and into the reactor buildings (after first getting out of the damaged reactor vessels) was through the drywell head flange at Unit 1, and also possibly at Unit 3. (Other papers delivered at that meeting hinted at other possible leak points; none can be assured until the plants are decommissioned.) Unit 4 experienced a hydrogen burn event as well; this is now known to have occurred because PCV (primary containment vessel) venting at Unit 3 allowed hydrogen to enter a common exhaust stack, and flow not only out the stack but into Unit 4’s reactor building. Delayed and/or difficult venting of the containments is the key factor in this portion of the accident; venting would have prevented overpressurization of the primary containments, allowing them to retain physical integrity.

Containment vents have become a major topic of discussion after the accident. At the ANS Winter Meeting, Sang-Won Lee, a representative of Korea Hydro and Nuclear Power stated that all of its OPR1000 and APR1400 nuclear plants will have filtered containment vents installed by the year 2015 since KHNP considers  this the “final means to prevent an uncontrolled release of radionuclides to the atmosphere.” (Interestingly, all South Korean nuclear plants will fit or backfit seismic trip equipment as well.) Here in the United States, hardened vents, perhaps filtered, will eventually be fitted to all boiling water reactor plants with Mk I and Mk II containments; click here to see some detailed background on the decision-making process and on filtered vent systems at reactors in other countries. For more background on decision-making regarding filtered vents, click here.

Do we know all of the things that were going on at Fukushima Daiichi?

The answer to this question is a qualified “yes.” In the time since the accident, many reports have been developed by TEPCO (and many other bodies) to attempt to explain the accident progression. As these reports came out, each subsequent report has benefited from more and better detailed information on the actual minute-to-minute actions being taken by operators on site, and from more detailed records that have been released. As of November 2012, when TEPCO made presentations on the accident at the ANS Winter Meeting, there were no new announcements made about operator actions, equipment failures, and records—and TEPCO representatives stated on several occasions that it is thought that the full range of operator actions is as well known now as it will ever be.

In terms of what was happening mechanically, we might say, throughout the accident, the truth is less certain. The loss of most of the plant instrumentation and the inability to access parts of the reactor buildings (even today) means that the exact progression of events once serious core damage began isn’t known. It will not be known until the plants are more accessible (during defueling, years away) and not fully known until the plants are decommissioned and dismantled. It must be added that while these findings will eventually significantly add to our storehouse of knowledge, they’re not essential to setting up procedures and equipment to prevent any such accidents in the future.

For such detailed reports as mentioned above, you can click here to see the Institute of Nuclear Power Operations report on the accident; you can click here to see a massive 500 page report on the accident by TEPCO; you can also find the American Nuclear Society’s Fukushima Committee report here.

Could the Fukushima Daiichi accident have been prevented?

We could say “yes” at some, or many points along the way—for example, we might say (getting into details) that had the hydrogen explosion not occurred at Unit 1, there may not have been any serious core damage at the other units due to the site-wide problems caused by the Unit 1 hydrogen explosion. This is cherry picking, though; the best answer to the question is “yes, had the site been properly prepared for tsunami of the actual size experienced, and even if not, had it been prepared to respond both from inside the site and from outside to such a natural disaster.” I’ve provided a link earlier to show what’s being done in Japan to prevent such events; a clearly defined path for US nuclear plants to increase nuclear plant safety can be found in a document that the Nuclear Energy Institute calls “The Way Forward.”

Our first modern wake-up call in the United States to such events was 9/11, in the sense that this experience was applied to nuclear plants here; after this, what are called “B.5.b” enhancements to US nuclear power stations saw the provision of numerous pieces of equipment to help combat site emergencies that included physical damage. Since the Fukushima Daiichi accident, much more has been developed. The industry response to the accident is called FLEX, and it provides essentially the same sort of mobile backup responses that the Japanese are beginning to implement (for stations that will restart.) The FLEX response is by now well known; you can click here to see details of its implementation and progress.  There are also multiple documents available at NEI’s Safety First website, found here.

So, the answer to “could this accident have been prevented” is “yes”—which means that future occurrences can also be prevented. The important provisions are spelled out clearly in the FLEX plans, and in those fairly duplicate plans being pursued by the Japanese: prevent loss of all AC power (station blackout) and prevent loss of the ultimate heat sink (where heat from the reactors and spent fuel is ultimately deposited, be it water or even the atmosphere) and prevent core damage.

What about the radiation dose received by citizens off site?

The World Health Organization has just released a report that tells us that the dose received by persons not on the site was actually not dangerous—in fact, according to WHO, most persons in Fukushima Prefecture received no more than 10 mSv, although some received as much as 50 mSv effective dose. You can read the entire report by clicking here.

This is not to say that the trauma experienced by those evacuated from the prefecture is not real; it is. It is important to understand that prevention of future events like the Fukushima Daiichi accident will also prevent massive evacuations of people from their homes. What it does mean is that exposure received by most people is far less than what they normally receive through the course of daily living and travel in a year. Click here to calculate your dose rate where you live in order to compare it to the figures in the WHO report.

The Fukushima Daiichi accident has been given the same INES scale rating as the Chernobyl accident—a rating of 7, or “Major Accident.” This is because both accidents resulted in a release of radionuclides to the environment concurrent with reactor fuel damage. However, the release from Fukushima Daiichi was only about 10 percent that of Chernobyl; thus, the equivalent rating on the INES scale doesn’t tell quite the whole story.

Where do we go from here?

In terms of the Fukushima Daiichi site, the planned decontamination and decommissioning of the whole site might take as long as 40 years, according to TEPCO’s road map for site decommissioning. In the meantime, TEPCO will be performing a great deal of research on how to safely dismantle the nuclear plants, very likely with international cooperation.

Worldwide, each nation that either has nuclear plants or aspires to have them has made some hard decisions. In the case of a few, like Germany, the decision has been made to abandon nuclear plants entirely; Bulgaria recently decided not to build a nuclear plant, as well. In the cases of most nations, though, reviews and reports on ‘lessons learned’ from the Fukushima Daiichi accident have evolved into robust plans for action; this strategy applies to the United States, South Korea, and China as three of the foremost proponents of nuclear energy. Many other nations that did not have nuclear power prior to the accident but wished to have it are still on course to build nuclear plants; perhaps most well known of these is the effort underway in the United Arab Emirates. Many nations realize the need for electricity in order to have a more productive and safer society; in a number of cases, nuclear is the leading choice. (Also notable for entering into nuclear energy programs are Kenya, Vietnam, Turkey, and Kazakhstan.)

Indeed, it would seem that the greatly increased public dialogue and involvement after the accident on many varied aspects of nuclear energy (not just safety) has not led to widespread fear, shown by favorable poll numbers in the United States. Even as time goes on, the polls in favor of nuclear power hold up.

This has allowed the present-day general discussion about greenhouse gases and varied energy generating sources to, for the most part, include nuclear energy on an intelligent and rational basis. Much of that basis centers on the passive safety features of new nuclear plants such as the Westinghouse AP1000, which is designed to endure SBO events for 72 hours with no operator action whatsoever, and after that time and with some operator action to transfer water, can maintain core and containment cooling indefinitely. The reactor plant is also designed so that even in the event of a severe accident, the core will remain inside the reactor vessel—an important step in the prevention of release of radioactive material to the environment.

Nuclear plant operators and government regulators worldwide have responded to the Fukushima Daiichi accident with still-increasing vigilance, inspection, research, and action. It’s clear that such an accident must never be allowed to happen again—and by the actions being taken at least in the United States, it would appear that we are well on our way to ensuring that we can meet any and every challenge that future severe events might bring, for the safety of both the plant operators and the citizens they serve.


Will Davis is a consultant to, and writer for, the American Nuclear Society. In addition to this, he is a contributing author for Fuel Cycle Week, and also writes his own blog Atomic Power Review. Davis is a former US Navy Reactor Operator, qualified on S8G and S5W plants.

Responding to System Demand

by Will Davis

Significant discussions have occurred recently on various internet venues about “load following”—that is, the capability of a generating source to adjust its power output to match variable demands. There is a myth spreading that nuclear power plants cannot load follow, and today’s ever-changing discussion about low-GHG generating sources demands that this myth be dispelled.

One might immediately ask this question: “Haven’t we been saying that nuclear plants are best for base load power generation?” That’s a valid question. Baseload generation can be thought of as that degree of electric demand below which you never go. When compared to other generating sources, nuclear power plants have a relatively high construction cost—but a relatively low operating cost—and thus are often referred to as baseload generating assets. Nuclear power plants make steady power and steady income for the utility at a low and controlled fuel cost that isn’t subject to rapid market fluctuations or interruptions in supply—and they do this all day and night.

However, today’s energy world is evolving. We now have under consideration small modular reactor (SMR) nuclear plants that may be ‘off the grid’ and required to supply variable loads at all times instead of  baseload power as part of a larger distribution network. Further, as high-GHG generating assets are retired, nuclear will become a larger percentage of the generating mix (all else held constant) and load following becomes part of the energy mix discussion.

From a utility perspective, operating today’s large commercial nuclear power plants at reduced load isn’t economically sensible, since the same staff  is paid the same money whether the plant is at 30-percent power or at 100 percent. Of course, the overall impact is much larger than just what you’re paying the staff,  considering all the other operating expenses—that’s just a simple example. Since renewable energy sources—which have a highly intermittent output—are now being seriously discussed, the capability of nuclear energy facilities to integrate with renewable sources, which would require load following, is important to address.

The Shippingport Atomic Power Station (seen in the lower part of this photo as a longish, red, left-to-right building in front of the much larger Beaver Valley nuclear station built years later) was the first large-scale commercial nuclear plant in the United States.  Shippingport was designed not only for load following but for remote load dispatching while operating in its normal power range (the plant was originally rated 265 MWt/60 Mwe, and ‘normal’ power was considered anything over 20 MWt).  The plant was designed to accommodate the following thermal power changes while in automatic control mode:  1. +15 MW or -12 MW at a step change rate.  2. ±15 Mw at a rate of 3 Mw/sec.  3. ±20 Mw at a rate of 0.417 MW/sec.

While today we don’t allow remote dispatching to control the power level of reactors, it’s important to know that they can accommodate power changes as well. Let’s take a look at some other nuclear plant design data for plants presently in service in terms of allowed power change rates, and then we’ll compare that to published data about today’s new-build AP1000 nuclear plant.

Westinghouse Pressurized Water Reactor: This design of nuclear plant was advertised in the 1980s as being “able to follow repetitive load changes automatically throughout the range of 15 percent to 100 percent of rated power consistent with the cyclic nature of the utility system load demand.” The Westinghouse PWR was designed at that time to accommodate step changes of 10 percent rated power and ramp changes at 5 percent per minute. Further, the plant was designed to operate, if required, on the 12-3-6-3 daily load cycle; 12 hours at 100 percent power, then three hours to reduce power followed by six hours at 50 percent power, then another three hours to ramp back up to full power. Finally, the plants were designed to accept up to a 50 percent rated power load rejection without reactor trip and full load rejection with reactor trip but optionally could be equipped with extra steam dump capacity in order to accept full load rejection with no reactor trip. The plants adjust both primary coolant boron concentration and control rod position as required to follow load.

Combustion Engineering PWR: Data are at hand for early generation C-E plants like that at Palisades; design criteria for this plant included the ability to accept step changes of 10 percent rated power, or ramp changes at 5 percent per minute.

Babcock & Wilcox PWR:  B&W large commercial plants were advertised as able to accommodate transients of 10 percent step changes, or ramp changes of 10 percent per minute between 20 percent and 90 percent rated power; above 90 percent rated power, the ramp change permissible was 5 percent per minute. Load reduction rates were the same without steam dump; with steam dump, load reductions of 40 percent in a step could be handled. According to B&W literature, “The turbine bypass system and safety valves permit a 100% load drop without turbine trip or reactor trip.”

GE Boiling Water Reactor: Data on hand for the late-generation BWR/6 shows that the design originally accommodated up to a 25 percent change in rated power automatically by recirculation flow control change, with no control rod motion, “thus providing automatic load following capability for the BWR.”

As we can see, these plants are responsive in varied degrees to changing system loads—and system loads don’t generally swing wildly unless there are storms in the area. What about new build nuclear plants?

Westinghouse advertises their AP1000 as having the following characteristics pertaining to variable system load: “The plant is designed to accept a step-load increase or decrease of 10 percent between 25 and 100 percent power without reactor trip or steam-dump system actuation, provided that the rated power level is not exceeded. Further, the AP1000 is designed to accept a 100 percent load rejection from full power to house loads without a reactor trip or operation of the pressurizer or steam generator safety valves.”

The Westinghouse SMR site offers a thorough description of that reactor design’s load following scheme which is also applied, according to the site, to the much larger AP1000 just described.  Click here for details. 

The competitive Generation mPower SMR is also designed for load following. In an interview on Atomic Power Review about the mPower SMR, Generation mPower LLC’s Matt Miles said of the mPower: “Traditionally, nuclear power plants have been used for base load generation. Our plants are designed for more segmented or off grid applications and are capable of load following to accommodate this type of deployment.”

As we can see, light water cooled and moderated nuclear power plants, whether of PWR or BWR type, and whether large commercial plants or SMR designs, are capable of adjusting power output to match variable system demand. Many years’ worth of operation on many various demand schedules have proven out the technology. While today, for many considerations, large commercial plants aren’t used as load followers, there is nothing inherent in the technology that precludes them from doing so; further, it is expected that SMR plants will normally behave as load followers. I hope this article clears up the spreading misconception about light water cooled and moderated reactor plants, in order to help level the discussion about applicability of technologies to a new age in which renewables will play a larger role on the grid.

(Sources consulted for this article include “Shippingport Pressurized Water Reactor, US AEC / Addison-Wesley Publishing, 1958; advertising material from Combustion Engineering, Inc. and Consumers Power for Palisades Nuclear Power Station; “The Westinghouse Pressurized Water Reactor Plant,” Westinghouse Electric Corporation, 1984; “Steam / Its Generation and Use,” 38th ed. Babcock & Wilcox 1975; “General Description of a Boiling Water Reactor (BWR/6)” General Electric 1978; Westinghouse AP1000 advertising materials, Korea Hydro & Nuclear Power advertising materials.)


Will Davis is a consultant to, and writer for, the American Nuclear Society. In addition to this, Davis is on the Board of Directors of PopAtomic Studios, is a contributing author for Fuel Cycle Week, and also writes his own blog Atomic Power Review. Davis is a former US Navy Reactor Operator, qualified on S8G and S5W plants.

Bill Gates on Nuclear Energy and TerraPower

Microsoft founder and extraordinary philanthropist Bill Gates is also a nuclear energy enthusiast.

In this excellent TeD presentation, Bill Gates talks about energy and climate, and the need for “miracles” to… well, save the world. He is a prominent investor in the nuclear reactor development firm TerraPower (for more details on the “traveling wave” reactor concept the company is developing, see this post at ANS Nuclear Cafe, and this interview with TerraPower CEO John Gilleland in ANS Nuclear News magazine).

Note that in the talk, Gates focuses on the need for nuclear technology to ameliorate climate issues in the 21st century—but an equally compelling case can be made for nuclear technology as essential to combat premature mortality due to fossil fuel combustion (estimated in the tens of thousands each year), or potentially devastating ocean acidification… clean and abundant baseload energy solves a long list of problems.

Bill Gates talks with The Wall Street Journal about nuclear technology and TerraPower.


The Atlantic Generating Station

Recent announcements and news stories about a Russian project to build a floating and essentially portable nuclear power plant have been variously tabbed with the heading “new.” The idea of a floating, mobile nuclear plant (which is not self-propelled and not a ship) is indeed not new—the nuclear barge STURGIS, itself a converted Liberty Ship, served as a power source for the Panama Canal for many years, beginning back in 1967. The new Russian plants bring extra excitement because they are classed, properly, in the now-popular small modular reactor plant category, having been based on true seagoing designs. This, of course, hints at the fact that their output will not approach that of any of the large, conventional nuclear plants familiar today.

For the historian, the question might then come to mind as to what the largest nuclear plants ever seriously considered for construction to such a design were. The answer is very simply this:  Full size, commercial nuclear plants in the normal (>1000 MWe) range common today. While the plants weren’t to have been fully mobile in the same sense, they were to have been barge–mounted and would have remained floating while in operation.

In the late 1960s, Public Service Electric & Gas (New Jersey) began to invest very heavily in nuclear energy. The company bought a major investment in Philadelphia Electric’s Peach Bottom expansion, and also began to order units of its own. In 1966, PSE&G ordered Salem Unit 1, followed in 1967 by Salem Unit 2 (both from Westinghouse);  in 1969, PSE&G awarded a contract to General Electric for its Newbold Island nuclear station (two units), which eventually would be cancelled for siting reasons; however, with that cancellation, simultaneously the project was moved next to Salem to be built as Hope Creek. According to PSE&G literature of the period, because of increasing worry about the thermal effects (waste heat) of nuclear plants, it decided to make its next order for a nuclear plant a bold, radical step; it decided to contract with Westinghouse to construct nuclear plants essentially at sea, in a man-made structure and mounted on floating barges.

The site eventually chosen after some consideration and study was as shown here in an original advertising illustration from a PSE&G brochure on the project. The caption reads: “The proposed offshore site is 2.8 miles out in the ocean, off Little Egg Inlet, and approximately 12 miles north of Atlantic City.” The location chosen kept the nuclear station out of major shipping lanes.

The site itself would have been prepared (with a breakwater surrounding it) including two moored, side-by-side nuclear power plants, separate from each other but identical and which would have been mounted on gigantic rectangular barge structures. According to the PSE&G brochure, “The Atlantic Generating Station,” the construction process would have been as follows:

“The breakwater will be the largest and strongest structure ever built in the ocean. First, concrete caissons will be floated to the site, sunk, and filled with sand and gravel. Next, thousands of tons of rock will be brought by barge to create the artificial reef, within which the plants will be moored. The mound facing of the reef will consist of sand, gravel, and stones topped by an armor of interlocking pre-cast concrete units called ‘dolos.’ A typical large dolos weighs 42 tons and measures 20 by 20 feet. Approximately 70,000 of these dolosse, in various sizes, will be placed on the breakwater.” 

The structure and the plants were designed to survive 43 foot waves, sustained (continuous) hurricane winds of 156 miles per hour and tornado winds of 300 MPH.

Above, cross-section view of the installation as planned. (Our apologies for the slight imperfections in some of the illustrations, which are contained in vintage materials, are not always printed perfectly, and which are often printed across the center staple fold.) Below, an artists’  illustration of the plant, whose official name was in fact the Atlantic Generating Station, from the air.

The two plants that were to become the Atlantic Generating Station (AGS) were first announced in 1971, according to WASH 1174-71, but were not named at that time, nor was a location specified. In September 1972, according to the Atomic Industrial Forum (now the Nuclear Energy Insitute) report “Historical Profile of U.S. Nuclear Power Development,” 1985, the two plants were officially ordered from Westinghouse as Atlantic-1 and -2. (The reactor plants were to have been 1150-MWe four-loop PWRs.) The plants were to have been built at a wholly new dedicated facility in Jacksonville, Florida, as a part of a joint Westinghouse–Tenneco operation known as “Offshore Power Systems.”

PSE&G had printed, in its public relations materials of the time, that it intended to rapidly increase its nuclear generating assets. From a 1976 brochure on Hope Creek: “To prepare for the coming ‘electric economy’ when electricity will play an even greater role in our daily lives, PSE&G is relying on nuclear energy. From now until the end of this century, all new major generating units will be nuclear. It is our intention to phase out our oil and coal burning plants and eventually have approximately 50 percent or more of our electric capacity in the nuclear stations we share with other utilities. This nuclear capacity will provide approximately 75% of our energy needs by 1990.”

To that end, in November, 1973, PSE&G ordered two further nuclear units of the same type as ordered previously as Atlantic-1 and -2. While the AIF document previously mentioned does not give a plant name or site for these, a later Energy Information Administration/Department of Energy document identifies these plants as Atlantic-3 and -4.

The nuclear plants would have been mounted on barges approximately 400 feet square. The draft of the nuclear plant barge structures (that is, the depth to which they extended underwater) would have been roughly 30 feet; the breakwater/reef enclosure would have had a further 10 feet of clearance under the plants for water flow. In an interesting nod toward today’s AP1000 plant and its modular construction, PSE&G said about the AGS units that the shipyard fabrication plan “allows for assembly line production techniques, as well as standardization of design and licensing procedures—which will result in reduced costs and planning lead times.” Heavy underwater cables, instead of high tension towers, would have connected the plants to the grid. A shore base would have been built, to shuttle workers to and from the AGS and to station repair parts, consumables, and any other requirements for the nuclear station several miles out to sea.

Above:  “Artist’s conception depicts how the plant will appear on a clear day to a person standing on the nearest beach.” The illustration is meant to dispel the fears that the plant would be an eyesore.

Of course, we all know today how this overall plan played out. PSE&G did not experience nearly the expected growth in electric power demand that it had predicted. While a 1976 PSE&G brochure on Hope Creek also prominently features the Atlantic Generating Station, a 1977 brochure on Salem does not mention it at all. In 1978, PSE&G cancelled all four units ordered for its offshore nuclear power station program, and the AGS project died immediately. (Work did continue on the other plants mentioned earlier, but not even all of these were finished; work on Hope Creek-2 lagged, and that plant was finally cancelled in 1981, leaving Hope Creek-1 a single unit.)

As we can see, a large amount of challenging engineering and construction would have been required to complete the Atlantic Generating Station. One wonders if such a project could survive today’s regulatory environment—to say nothing of clearing approval by a utility’s ownership when the extra cost of constructing the artificial reef type breakwater and shore-based support infrastructure is considered. The best guess for both right off the bat is “probably not,” meaning that the Atlantic Generating Station was probably the closest we’ll ever get to a full-scale commercial nuclear plant situated well off shore.

Sources of information and illustrations: Various original PSE&G brochures—”The Atlantic Generating Station” (undated), “Hope Creek Generating Station” (8/76), “The Salem Generating Station” (4/77), “PSE&G: Nuclear Energy” (6/85).  Also, “The Nuclear Industry 1971″–WASH 1174-71, U.S. Atomic Energy Commission. “Historical Profile of U.S. Nuclear Power Development,” Atomic Industrial Forum 1985. “Nuclear Plant Cancellations:  Causes, Costs and Consequences,” US EIA/DOE 1983.  All materials in Will Davis’ library.

For more on this topic, particularly the plant construction end of the project, see Rod Adams’ article from 1996 on Atomic Insights.


Will Davis is a consultant to, and writer for, the American Nuclear Society. In addition to this, Davis is on the Board of Directors of PopAtomic Studios, is a contributing author for Fuel Cycle Week, and also writes his own blog Atomic Power Review. Davis is a former US Navy Reactor Operator, qualified on S8G and S5W plants.

ANS Nuclear Cafe Matinee: DUFF Space Nuclear Reactor Prototype

A joint Department of Energy and NASA team has demonstrated a simple, robust fission reactor prototype [note: see Comments for more accurate and complete description] intended for development for future space exploration missions. The DUFF (Demonstration Using Flattop Fissions) experiment represents the first demonstration in the United State—since 1965—of a space nuclear reactor system to produce electricity.

The uranium–powered reactor is the first use of a “heat pipe” to cool a small  nuclear reactor (measuring one foot!) and power a Stirling engine. The following short video from Los Alamos National Laboratory explains the hows and whys:

See this article from Los Alamos on the details of the DUFF experiment recently successfully conducted.  Also, see this CNN article for an excellent description.

Many future space missions will only be feasible with the use of reliable and safe nuclear energy, and this proof-of-concept is a steppingstone toward that future.


Clinch River Site will once again lead nuclear development

By Will Davis

(Above, Westinghouse artwork depicting the Clinch River Breeder Reactor plant as envisaged in November 1973.)

The Department of Energy announced recently that it would award the first of (potentially) two blocks of grant money for small modular reactor (SMR) development to Babcock & Wilcox, Bechtel Corporation, and the Tennessee Valley Authority. The funds would be used for construction of a new SMR–powered reactor plant at the former Clinch River Breeder Reactor (CRBR) site in Oak Ridge, Tennessee—a site that once shined as the future of nuclear energy in the United States.

Decades ago, the Liquid Metal Fast Breeder Reactor (LMFBR) program, originally begun by the Atomic Energy Commission, turned into a real-world project in 1972 when the AEC signed the first Memorandum of Understanding with TVA, Project Management Corporation, Commonwealth Edison, and Breeder Reactor Corporation — to build what would become known as the CRBR plant. Work quickly advanced to include a number of reactor vendors (Westinghouse as lead reactor manufacturer, along with General Electric and Atomics International) and a giant consortium of 753 utility companies nationwide, as well as many other vendors and consultants. Project costs  escalated, and in 1977 the Carter administration decided to terminate the licensing activity and attempted to kill the project. The CRBR project went on in semi-limbo for years, with much hardware being constructed. Finally, after a brief attempt in 1983 to find ways to increase outside funding for the project, it was cancelled—with over 70 percent of the equipment either delivered or ordered, site preparation work underway, licensing activity nearly completed, and environmental hearings completed (DOE-NE-0050, March 1983.)

When the breeder project was launched, the liquid metal–cooled breeder reactor seemed very much the path to the future for nuclear energy, in order to close the fuel cycle. Now, the SMR seems the path to the future, to provide industrial power and process steam, even for off-grid use. It’s supremely fitting that the Clinch River site—just green field now, but where the “old future” of nuclear energy died—will see the launch of the “new future.” In order to help close the historical circle, let’s take a look at some of the hardware actually constructed for the CRBR project—but never used. We’ve already seen the first exterior concept for the plant above; we’ll see the final one later on.

Above, the reactor vessel for the CRBR, pictured at Babcock & Wilcox’s facility in Mount Vernon, Indiana, as seen in a Westinghouse CRBR status report from 1981. The special J-shaped rig or mount was designed to both transport and help erect the vessel at the time of installation. Cost of this piece of equipment with core support structure was about $27.7 million. The core support was fabricated by Allis-Chalmers.

Above, flow diagram for the CRBR–sodium in the primary and intermediate loops (3 double loops total) with steam/water in the conventional manner in the final cycle. The odd-looking shape of the steam generators and superheaters in the diagram is no mistake, as we’re about to see.

Above, CRBR “evaporator” or steam generator delivered from Atomics International for testing. Both the primary loops and intermediate loops were to use very large electric pumps to move the liquid sodium, which we’ll see below.

Above, a primary loop sodium pump under test at the Byron Jackson Division of Borg-Warner Corporation, as seen in a Westinghouse update on the CRBR project from 1981 (the same photo is duplicated in the 1982 report).

The CRBR project had its own internal newsletter; above, the cover of the December 1978 “Clinch River Currents.” Below is the text from the cover:

“The CRBRP’s in and ex-containment primary sodium storage tanks are complete and will be shipped by barge to Oak Ridge when needed. The three tanks have been purged, sandblasted and painted and are now in storage at ITO Corporation of Ameriport, Camden, New Jersey.

These tanks for the CRBRP were built at the Joseph Oat Company, Camden, New Jersey, under a subcontract from Atomics International. The materials used were ASME SA-515 and SA-516 carbon steel plate, and SA-105 for the nozzle forgings.  Single piece spun heads were used in fabricating the tanks.

The contract was awarded in October 1976, and fabrication started in February 1977. The 23-foot-long in-containment tank was completed in August 1978 and the two 32-foot-long ex-containment tanks shown here were completed in September 1978. Each of the three tanks is 18 feet in diameter.”

In that same December 1978 issue we find a number of illustrations and details about completion of the in-vessel fuel transfer machine, illustrated below with original caption material included.

“Four years of design work and over a year of fabrication and assembly by Atomics International Division, Rockwell International, Canoga Park, California, have culminated in completion of the two subassemblies of the in-vessel transfer machine. The next step will be final assembly, followed by an integrated checkout of the unit in air in February. Following completion of this phase, the unit will be turned over to the Energy Technology Engineering Center nearby in Santa Susana, California, for testing in sodium. Turnover is scheduled for May 1979.

The $2.3 million apparatus will be used to transfer fuel inside the reactor vessel during refueling. Mounted on the smallest of three eccentric rotating plugs of the reactor vessel head, it will be capable of locating itself over any removable element of the core, picking it up with a straight pull and transferring it to a temporary storage location inside the reactor vessel. It will also pick up replacement elements from the storage location and place them in the proper position in the core. The triple rotating plug locating concept, also used by West Germany in the SNR 300, is the first such head design used in a US designed LMFBR. Prior rotating head concepts in the US were employed on EBR II [Experimental Breeder Reactor II] and FFTF [Fast Flux Test Facility] but consisted of only two heads and a cantilevered in-vessel fuel handling device…”

Below, the reactor vessel head assembled for testing; the eccentric plugs and gears can clearly be made out.

The design layout for the plant changed a number of times as improvements were made. Below, the final layout as found in 1981–1982 Westinghouse status reports, and which was fairly widely released. This was the final plant configuration.

As we have seen, the CRBR was never built. The equipment ordered was laid up or disposed of, and the work force scattered; the site returned to disuse. The promise of a new and different future for nuclear energy never did die, though—it has taken on new faces from time to time since then, none of which has really reached the hardware stage. Now, at last, the Clinch River site will finally see construction and operation of a nuclear power plant, fulfilling its promise. While the design and appearance of the Generation mPower SMR plant will be vastly different from that envisaged for the CRBR, it’s fitting that it is because the look of the future of nuclear energy has also changed that much in the intervening quarter century.

One last illustration; below we see the cover of the January 1979 Clinch River Currents, whose headline announces “First Major CRBRP Hardware Delivered to Oak Ridge”—this was a protected water storage tank manufactured by Process Equipment Company, Brockton, Massachusetts, and three primary sodium system cold leg check valves (inset) from Foster Wheeler in Mountaintop, Pennsylvania.

(Illustrations from Westinghouse, CRBR management reports; Clinch River Currents illustrations and text, and both CRBR plant external illustrations from Will Davis collection.)


Will Davis is a former US Navy Reactor Operator, qualified on S8G and S5W reactor plants.  Davis performs Social Media services for ANS under contract, writes for ANS Nuclear Cafe as well as for Fuel Cycle Week, and also writes his own Atomic Power Review blog.