Westinghouse said this development allows better nuclear fuel efficiency, longer times between reactor refuels and lower operating costs.

U.S. pressurized water reactors currently operate on 18-month fuel cycles, and Westinghouse said this new higher burnup fuel will enable reductions in feed batch size, thereby improving fuel cycle economics. This is the first time nuclear fuel batch reloads in the United States will be able to exceed a burnup limit of 62 GWd/MTU.

“We are very pleased to receive approval from the Nuclear Regulatory Commission for incremental burnup in our nuclear fuel,” said Tarik Choho, Westinghouse President of Nuclear Fuel. “This milestone marks the start of production of nuclear fuel with increased capacity for Pressurized Water Reactors, vastly improving fuel costs for U.S. utility customers.”

The incremental burnup approval also represents a milestone for the Encore Accident Tolerant Fuel Program, an initiative started in 2012 and funded by the Department of Energy, aimed at increasing performance and safety of nuclear reactors in support of U.S. energy security and climate goals.

The test cell will be used to observe the “complex chemistry” that can occur in molten salt fueled reactors, ORNL said, and its data will be used to help verify existing computer codes and modeling software to better predict the reactors’ overall performance.

Molten salt reactors (MSRs) are still under development, but could be commercialized “early next decade,” ORNL said. Some MSR designs are intended to operate on liquid fuel, with fissile materials directly dissolved into a molten salt solution that can also cool the reactor.

However, the nuclear and chemical reactions that result can cause gases to bubble out of the molten salt, which runs the risk of impacting reactor neutronics and thermal hydraulic performance, ORNL said. The new glass test cell is meant to help researchers better understand this behavior.

The glass test cell can hold up to one liter of liquid molten salt. The ORNL team injected small helium and krypton bubbles into the cell to observe how they moved. ORNL said this experiment allowed researchers to observe and measure gas bubble velocity, size distribution and interactions with neighboring bubbles using high-speed cameras.

“Understanding gas generation and transport in molten salt reactors is essential to optimizing their performance and safety,” said Daniel Orea, ORNL’s lead R&D associate. “This unique glass test cell allows us to overcome certain engineering challenges caused by the high temperature and composition of salt and its two-phase liquid glass system.”

The research project was supported through the U.S. Department of Energy’s Molten Salt Reactor Program that works to accelerate the research, development, and deployment of molten salt reactor technologies in the United States.

Read more details on the experiment and glass test cell here.

Blue said the company will “continue to explore that option” after being asked on the call, NBC Philadelphia reported, but it understands that “any co-location option is going to have to make sense for us, our potential counterparty and stakeholders in Connecticut.”

Millstone power station has 2,100 MW of generating capacity. Unit 1 was commissioned in 1970 and closed more than 10 years ago. Units 2 and 3 are licensed through 2035 and 2045, respectively.

In 2022, Connecticut state legislators passed a bill that would exempt the Millstone facility from a construction moratorium. The measure would allow the option of on-site expansion at the site.

Generally, the state’s moratorium prohibits new construction on new nuclear facilities until the Department of Energy and Environmental Protection Agency find that the federal government has identified and approved a way to dispose of nuclear waste. Lawmakers spoke favorably about the growth and potential of small modular reactors (SMRs) – Dominion indicated it supported the bill but had no plans to add an SMR at the Millstone site “as their commercial viability is still many years away.”

Earlier this year, Blue said Dominion is receiving requests to power larger data center campuses that require total capacity ranging from 300 MW to as many as “several gigawatts.”

The statement is another reflection of the significant load growth in Dominion’s territory that has accelerated in recent years, largely driven by data centers and their AI computing needs. Dominion has connected 94 data centers totaling over four GW of capacity over the last approximately five years, Blue told investors. The utility’s territory includes Northern Virginia, which is the largest and most dynamic data center market in the world.

Blue said the utility expected to connect an additional 15 data centers in 2024.

Dominion has not only seen a larger number of data center customer requests in recent years, but the size of each facility request (in terms of MW) has grown larger. Blue said historically, a single data center had a demand of 30 MW or more. More recent requests indicate a demand of 60-90 MW, or greater. Now, he said data center campuses with multiple buildings could require several gigawatts.

In the U.S. alone, data center demand is expected to reach 35 GW by 2030, up from 17 GW in 2022, McKinsey & Company projects. Grid operators and utilities are projecting significant load growth driven by electrification, new manufacturing, and data center development. This is especially true throughout the PJM Interconnection. Dominion Energy’s service territory is located within the PJM footprint.

According to the company’s annual report filed with regulators earlier this year, data centers represented 24% and 21% of Dominion’s electricity sales in 2023 and 2022, respectively.

The BWXT Advanced Nuclear Reactor (BANR) is a 50 MWt high-temperature gas reactor (HTGR) that is envisioned for remote power applications. BWXT and the U.S. Department of Energy (DOE) have been developing the BANR microreactor since 2021.

In September 2023 BWXT entered a two-year contract with the Wyoming Energy Authority to evaluate the feasibility of microreactor deployment in the state.

Burns & McDonnell will assist BWXT in developing the balance of the plant (BOP) systems for the microreactor, generating the power plant layout and performing preconstruction planning.

The EPC’s project scope includes developing the power cycle architecture and identifying critical components such as the steam turbine generator and air-cooled condensers. Burns & McDonnell’s scope also includes site integration design and support for steam and power distribution infrastructure and reactor building structures.

“This project has so many unique aspects to it, including cogeneration, which would be the first domestic nuclear application that produces both electricity and steam for industrial use,” said says Scott Strawn, vice president and general manager of the Power Group at Burns & McDonnell.

Burns & McDonnell and BWXT completed phase one of this project in early 2024. Phase two is set to be completed by the third quarter of 2025.

The study, Investigation of potential sites for coal-to-nuclear energy transitions in the United States, ranks the feasibility of converting 245 operational coal power plants in the US into advanced nuclear reactors, a strategy being considered by electric utilities and the Department of Energy.

Converting coal plants into nuclear power plants allows for the same generation of stable, base-load power, but with less emissions. Also, the new nuclear plants can utilize the existing infrastructure, such as transmission lines and provide an economic boost for areas reliant on coal plants for jobs.

“With no new coal plants planned and many utilities aiming to retire all coal power plants within 15 years in the US, transitioning to cleaner energy sources is crucial,” said Md Rafiul Abdussami, a doctoral student of nuclear engineering and radiological sciences at U-M and corresponding author of the study published in Energy Reports.

The data set was generated using a tool called ‘Siting Tool for Advances Nuclear Development‘ co-developed by the University of Michigan, Argonne National Laboratory, Oak Ridge National Laboratory and the National Reactor Innovation Center.

The tool allowed researchers to factor in several variables to select the most feasible locations. These factors include safety, nearby population, regulatory situation, and socio-economic factors.

The results revealed the most feasible locations for transitioning from coal to nuclear, as well as the opportunities and challenges for each location.

For example, researchers identified that the R M Schahfer coal plant in Indiana emerged as the most feasible smaller electric capacity site, while the AES Petersburg plant in Indiana was top-ranked among the larger electric capacity sites.

“This data set can support economic revitalization plans in regions affected by coal plant closures and provide information for engagement efforts in coal communities considering hosting clean energy facilities,” said Aditi Verma, assistant professor of nuclear engineering and radiological sciences at U-M and senior author of the study.

Policymakers and utilities can use the study findings to guide strategic planning and investments, ensuring a smoother transition from coal to nuclear, while maximizing grid stability.

“My hope is that this work, which looks at the potential for coal-to-nuclear transitions in a very granular way, for each coal plant across the country, can inform the national and state-level conversations that are unfolding in real time,” Verma said.

According to Kirsty Gogan, co-founder and managing partner of TerraPraxis and co-founder Eric Ingersoll, repowering existing coal plant infrastructure is the largest single carbon abatement opportunity on the planet, which will sustain jobs and community tax revenues associated with existing coal plants

Repowering coal fleets “offers a fast, low-risk, large-scale and equitable contribution to decarbonizing the world’s power generation”.

Originally published by Pamela Largue in Power Engineering International.

While Dominion stressed the RFP is not a commitment to build an SMR at North Anna, the company said it is an important first step in evaluating the technology and the North Anna site.

The company announced the news at an event at North Anna. Company leaders were joined at the event by Virginia Governor Glenn Youngkin, Virginia Lieutenant Governor Winsome Earle-Sears, Virginia State Senator Dave Marsden, Virginia State Senator Mark Peake and Louisa County Board of Supervisors Chair Duane Adams, among other local and state leaders.

“For over 50 years nuclear power has been the most reliable workhorse of Virginia’s electric fleet, generating 40% of our power and with zero carbon emissions,” said Robert M. Blue, Chair, President and CEO of Dominion Energy. “As Virginia’s need for reliable and clean power grows, SMRs could play a pivotal role in an ‘all-of-the-above’ approach to our energy future. Along with offshore wind, solar and battery storage, SMRs have the potential to be an important part of Virginia’s growing clean energy mix.”

“The Commonwealth’s potential to unleash and foster a rich energy economy is limitless,” said Governor Glenn Youngkin. “To meet the power demands of the future, it is imperative we continue to explore emerging technologies that will provide Virginians access to the reliable, affordable and clean energy they deserve. In alignment with our All-American, All-of-the-Above energy plan, small nuclear reactors will play a critical role in harnessing this potential and positioning Virginia to be a leading nuclear innovation hub.”

The company also announced that it intends to seek rider recovery of SMR development costs in a filing with the Virginia State Corporation Commission (SCC) expected in the fall. This step was enabled by bipartisan legislation passed by the Virginia General Assembly earlier this year.

The legislation contains cost caps limiting current SMR development cost recovery to no more than $1.40 per month for a typical residential customer. The company said it anticipates its initial request will be “substantially” below that limit.

The move is part of PPL and its subsidiaries’ ongoing effort to evaluate options for future replacement of aging generation, and to support energy-intensive customers with zero-carbon objectives. 

“We understand that achieving our goal of net-zero carbon emissions will be challenging, and we continue to pursue an all-of-the-above technology strategy to replace aging generation with a cleaner, more diverse energy mix capable of safely, reliably and affordably meeting our customers’ future energy needs and supporting continued economic growth,” said Vincent Sorgi, president and chief executive officer of PPL.

As with earlier feasibility assessments at LG&E and KU’s Ghent Generation Station in Ghent, Kentucky, PPL’s Research and Development team plans to partner with Gateway for Accelerated Innovation in Nuclear (GAIN), a U.S. Department of Energy initiative, and nuclear design engineering company X-energy in the next phase of assessments.

“Nuclear energy is a carbon-free solution that has the potential to meet our customers’ needs and support manufacturing and data center growth, particularly if technology such as nuclear small modular reactors (SMRs) become more cost-competitive,” said Sorgi. “These in-depth studies are important to determining whether nuclear energy at our locations may be a viable solution moving forward.”

PPL and GAIN’s prior study at the Ghent facility determined that the site is suitable for a nuclear SMR plant, but would have potential size constraints for a larger traditional nuclear reactor.

Phase two of the study will explore alternative locations and industrial partnerships that could enable energy-intensive customers, including manufacturers and data centers, to achieve their zero-carbon objectives.

DOE estimates the U.S. will need approximately 700-900 GW of additional clean, firm capacity to reach net-zero emissions by 2050, and it says nuclear power is a proven option that could be deployed to meet this need, including the growing demand from artificial intelligence and other data centers and the reshoring of manufacturing.

Created by the Consolidated Appropriations Act of 2024 and funded by the President’s Bipartisan Infrastructure Law, DOE anticipates offering funding in two tiers:   

• Tier 1: First Mover Team Support, managed by the Office of Clean Energy Demonstrations (OCED), plans to provide up to $800M to support up to two first-mover teams of utility, reactor vendor, constructor, and end-users or power off-takers committed to deploying a first plant while at the same time facilitating a multi-reactor, Gen III+ SMR orderbook.  
• Tier 2: Fast Follower Deployment Support, managed by the Office of Nuclear Energy (NE), plans to provide up to $100M to spur additional Gen III+ SMR deployments by addressing key gaps that have hindered the domestic nuclear industry in areas such as design, licensing, supplier development, and site preparation.  

DOE anticipates releasing a funding solicitation in late summer or fall of 2024.

DOE said projects are expected to (1) support meaningful community and labor engagement; (2) invest in quality jobs; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the goal that 40% of the overall benefits of certain federal investments flow to disadvantaged communities (the Justice40 Initiative). The strength of a proposal’s community benefits, including a project’s impact on equity and environmental justice, will be considered when reviewing applications. 

“President Biden is determined to ensure nuclear power — the nation’s single largest source of carbon free electricity — continues to serve as a key pillar of our nation’s transition to a safe and secure clean energy future,” said U.S. Secretary of Energy Jennifer M. Granholm. “Today’s announcement will support early movers in the nuclear sector as we seek to scale up nuclear power and reassert American leadership in this critical energy industry.” 

LOS ANGELES (AP) — The California Legislature signaled its intent on Thursday to cancel a $400 million loan payment to help finance a longer lifespan for the state’s last nuclear power plant, exposing a rift with Gov. Gavin Newsom who says that the power is critical to safeguarding energy supplies amid a warming climate.

The votes in the state Senate and Assembly on funding for the twin-domed Diablo Canyon plant represented an interim step as Newsom and legislative leaders, all Democrats, continue to negotiate a new budget. But it sets up a public friction point involving one of the governor’s signature proposals, which he has championed alongside the state’s rapid push toward solar, wind and other renewable sources.

The dispute unfolded in Sacramento as environmentalists and antinuclear activists warned that the estimated price tag for keeping the seaside reactors running beyond a planned closing by 2025 had ballooned to nearly $12 billion, roughly doubling earlier projections. That also has raised the prospect of higher fees for ratepayers.

Operator Pacific Gas & Electric called those figures inaccurate and inflated by billions of dollars.

H.D. Palmer, a spokesperson for the California Department of Finance, emphasized that budget negotiations are continuing and the legislative votes represented an “agreement between the Senate and the Assembly — not an agreement with the governor.”

The votes in the Legislature mark the latest development in a decades-long fight over the operation and safety of the plant, which sits on a bluff above the Pacific Ocean midway between Los Angeles and San Francisco.

Diablo Canyon, which began operating in the mid-1980s, produces up to 9% of the state’s electricity on any given day.

The fight over the reactors’ future is playing out as the long-struggling U.S. nuclear industry sees a potential rebirth in the era of global warming. Nuclear power doesn’t produce carbon pollution like fossil fuels, but it leaves behind waste that can remain dangerously radioactive for centuries.

A Georgia utility just finished the first two scratch-built American reactors in a generation at a cost of nearly $35 billion. The price tag for the expansion of Plant Vogtle from two of the traditional large reactors to four includes $11 billion in cost overruns. In Wyoming, Bill Gates and his energy company have started construction on a next-generation nuclear power plant that the tech titan believes will “revolutionize” how power is generated.

In 2016, PG&E, environmental groups and plant worker unions reached an agreement to close Diablo Canyon by 2025. But the Legislature voided the deal in 2022 at the urging of Newsom, who said the power is needed to ward off blackouts as a changing climate stresses the energy system. That agreement for a longer run included a $1.4 billion forgivable state loan for PG&E, to be paid in several installments.

California energy regulators voted in December to extend the plant’s operating run for five years, to 2030.

The legislators’ concerns were laid out in an exchange of letters with the Newsom administration, at a time when the state is trying to close an estimated $45 billion deficit. Among other concerns, they questioned if, and when, the state would be repaid by PG&E, and whether taxpayers could be out hundreds of millions of dollars if the proposed extension for Diablo Canyon falls through.

Construction at Diablo Canyon began in the 1960s. Critics say potential earthquakes from nearby faults not known to exist when the design was approved could damage equipment and release radiation. One fault was not discovered until 2008. PG&E has long said the plant is safe, an assessment the NRC has supported.

Last year, environmental groups called on federal regulators to immediately shut down one of two reactors at the site until tests can be conducted on critical machinery they believe could fail and cause a catastrophe. Weeks later, the Nuclear Regulatory Commission took no action on the request and instead asked agency staff to review it.

The questions raised by environmentalists about the potential for soaring costs stemmed from a review of state regulatory filings submitted by PG&E, they said. Initial estimates of about $5 billion to extend the life of the plant later rose to over $8 billion, then nearly $12 billion, they said.

“It’s really quite shocking,” said attorney John Geesman, a former California Energy Commission member who represents the Alliance for Nuclear Responsibility, an advocacy group that opposes federal license renewals in California. The alliance told the state Public Utilities Commission in May that the cost would represent “by far the largest financial commitment to a single energy project the commission has ever been asked to endorse.”

PG&E spokesperson Suzanne Hosn said the figures incorrectly included billions of dollars of costs unrelated to extending operations at the plant.

The company has pegged the cost at $8.3 billion, Hosn said, adding that “the financial benefits exceed the costs.”

Framatome says the pilot line will further verify its ability to convert uranium oxide (UO2) into HALEU metal, initiating a long-term collaboration to supply metal feedstock and help TerraPower build a domestic HALEU supply chain. TerraPower already supports operational centers in Washington state at its Bellevue-based headquarters and laboratory, and at its Everett laboratory location.

“A strong domestic fuel supply chain is crucial for the wide-scale deployment of advanced nuclear energy solutions; an energy source we know is needed to meet clean energy targets and provide reliable, baseload energy. This investment by TerraPower into Framatome’s pilot line is a critical step in bringing advanced reactors like the Natrium^TM technology to market. It is also one more way that TerraPower is delivering on its promise to do our part to support the fuel manufacturing sector,” said Chris Levesque, TerraPower President and CEO.

Metallization of HALEU allows uranium to transform into a metal that is then used to fabricate fuel for advanced reactors.

Framatome submitted an application for U.S. Department of Energy (DOE) funding that will be awarded in response to a DOE HALEU Availability Program (HAP) Solicitation (the HAP Deconversion and Metallization Request for Proposals).

TerraPower is currently developing the Natrium advanced nuclear power plant that it says will provide GW-scale energy storage. The company’s technology features a 345 MWe sodium-cooled fast reactor with a molten salt-based energy storage system. The storage technology can boost the system’s output to 500 MWe for more than five and a half hours when needed. This addition allows a Natrium plant to integrate with renewable resources. The Natrium demonstration plant is being constructed near a retiring coal facility in Wyoming.

Last year, TerraPower and Centrus Energy announced they were expanding their collaboration aimed at establishing commercial-scale, domestic HALEU production capabilities to supply TerraPower’s Natrium reactor and energy storage system. In June 2023, the U.S. Nuclear Regulatory Commission (NRC) approved Centrus’ request to make HALEU fuel at the Piketon, Ohio facility – the first licensed HALEU production facility in the United States..