IAEA reactor simulators get more use during Covid-19 lockdown


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IAEA Nuclear Reactor Simulators enable virtual nuclear power plant training on IPWR/PWR systems, load-following operations, baseload dynamics, and turbine coupling, supporting advanced reactor education, flexible grid integration, and low-carbon electricity skills development during remote learning.

 

Key Points

IAEA Nuclear Reactor Simulators are tools for training on reactor operations, safety, and flexible power management.

✅ Simulates IPWR/PWR systems with real-time parameter visualization.

✅ Practices load-following, baseload, and grid flexibility scenarios.

✅ Supports remote training on safety, controls, and turbine coupling.

 

Students and professionals in the nuclear field are making use of learning opportunities during lockdown made necessary by the Covid-19 pandemic, drawing on IAEA low-carbon electricity lessons for the future.

Requests to use the International Atomic Energy Agency’s (IAEA’s) basic principle nuclear reactor simulators have risen sharply in recent weeks, IAEA said on 1 May, as India takes steps to get nuclear back on track. New users will have the opportunity to learn more about operating them.

“This suite of nuclear power plant simulators is part of the IAEA education and training programmes on technology development of advanced reactors worldwide. [It] can be accessed upon request by interested parties from around the world,” said Stefano Monti, head of the IAEA’s Nuclear Power Technology Development Section.

Simulators include several features to help users understand fundamental concepts behind the behaviour of nuclear plants and their reactors. They also provide an overview of how various plant systems and components work to power turbines and produce low-carbon electricity, while illustrating roles beyond electricity as well.

In the integral pressurised water reactor (IPWR) simulator, for instance, a type of advanced nuclear power design, users can navigate through several screens, each containing information allowing them to adjust certain variables. One provides a summary of reactor parameters such as primary pressure, flow and temperature. Another view lays out the status of the reactor core.

The “Systems” screen provides a visual overview of how the plant’s main systems, including the reactor and turbines, work together. On the “Controls” screen, users can adjust values which affect reactor performance and power output.

This simulator provides insight into how the IPWR works, and also allows users to see how the changes they make to plant variables alter the plant’s operation. Operators can also perform manoeuvres similar to those that would take place in the course of real plant operations e.g. in load following mode.

“Currently, most nuclear plants operate in ‘baseload’ mode, continually generating electricity at their maximum capacity. However, there is a trend of countries, aligned with green industrial revolution strategies, moving toward hybrid energy systems which incorporate nuclear together with a diverse mix of renewable energy sources. A greater need for flexible operations is emerging, and many advanced power plants offer standard features for load following,” said Gerardo Martinez-Guridi, an IAEA nuclear engineer who specialises in water-cooled reactor technology.

Prospective nuclear engineers need to understand the dynamics of the consequences of reducing a reactor’s power output, for example, especially in the context of next-generation nuclear systems and emerging grids, and simulators can help students visualise these processes, he noted.

“Many reactor variables change when the power output is adjusted, and it is useful to see how this occurs in real-time,” said Chirayu Batra, an IAEA nuclear engineer, who will lead the webinar on 12 May.

“Users will know that the operation is complete once the various parameters have stabilised at their new values.”

Observing and comparing the parameter changes helps users know what to expect during a real power manoeuvre, he added.

 

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Ontario prepares to extend disconnect moratoriums for residential electricity customers

Ontario Electricity Relief outlines an extended disconnect moratorium, potential time-of-use price changes, and Ontario Energy Board oversight to support residential customers facing COVID-19 hardship and bill payment challenges during the emergency in Ontario.

 

Key Points

Plan to extend disconnect moratorium and weigh time-of-use price relief for residential customers during COVID-19.

✅ Extends winter disconnect ban by 3 months

✅ Considers time-of-use price adjustments

✅ Requires Ontario Energy Board approval

 

The Ontario government is preparing to announce electricity relief for residential electricity users struggling because of the COVID-19 emergency, according to sources.

Sources close to those discussions say a decision has been made to lengthen the existing five-month disconnect moratorium by an additional three months.

Separately, Hydro One's relief fund has offered support to its customers during the pandemic.

News releases about the moratorium extension are currently being drafted and are expected to be released shortly, as the pandemic has reduced electricity usage across Ontario.

Electricity utilities in Ontario are currently prohibited from disconnecting residential customers for non-payment during the winter ban period from November 15 to April 30.

The province is also looking at providing further relief by adjusting time-of-use prices, such as off-peak electricity rates, which are designed to encourage shifting of energy use away from periods of high total consumption to periods of low demand.

For businesses, the province has provided stable electricity pricing to support industrial and commercial operations.

But that would require Ontario Energy Board approval and no decision has been finalized, our sources advise.

 

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NDP takes aim at approval of SaskPower 8 per cent rate hike

SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.

 

Key Points

An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.

✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023

✅ Panel-approved amid natural gas price surge and higher fuel costs

✅ Avg residential bill up about $5 per step; affordability concerns

 

The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.

The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.

“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”

But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.

She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.

“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”

The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.

“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”

 

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Nuclear plants produce over half of Illinois electricity, almost faced retirement

Illinois Zero Emission Credits support nuclear plants via tradable credits tied to wholesale electricity prices, carbon costs, created by the Future Energy Jobs Bill to avert Exelon closures and sustain low-carbon power.

 

Key Points

State credits that value nuclear power's zero-carbon output, priced by market and carbon metrics to keep plants running.

✅ Pegged to wholesale prices, carbon costs, and state averages.

✅ Created by Future Energy Jobs Bill to prevent plant retirements.

✅ Supports Exelon Quad Cities and Clinton nuclear facilities.

 

Nuclear plants have produced over half of Illinois electricity generation since 2010, but the states two largest plants would have been retired amid the debate over saving nuclear plants if the state had not created a zero emission credit (ZEC) mechanism to support the facilities.

The two plants, Quad Cities and Clinton, collectively delivered more than 12 percent of the states electricity generation over the past several years. In May 2016, however, Exelon, the owner of the plants, announced that they had together lost over $800 million dollars over the previous six years and revealed plans to retire them in 2017 and 2018, similar to the Three Mile Island closure later announced for 2019 by its owner.

In December 2016, Illinois passed the Future Energy Jobs Bill, which established a zero emission credit (ZEC) mechanism

to support the plants financially. Exelon then cancelled its plans to retire the two facilities.

The ZEC is a tradable credit that represents the environmental attributes of one megawatt-hour of energy produced from the states nuclear plants. Its price is based on a number of factors that include wholesale electricity market prices, nuclear generation costs, state average market prices, and estimated costs of the long-term effects of carbon dioxide emissions.

The bill is set to take effect in June, but faces multiple court challenges as some utilities have expressed concerns that the ZEC violates the commerce clause and affects federal authority to regulate wholesale energy prices, amid gas-fired competition in nearby markets that shapes the revenue outlook.

Illinois ranks first in the United States for both generating capacity and net electricity generation from nuclear power, a resource many see as essential for net-zero emissions goals, and accounts for approximately one-eighth of the nuclear power generation in the nation.

 

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Dubai Planning Large-Scale Solar Powered Hydrogen Production

Dubai Green Hydrogen advances electrolysis at the Mohammed Bin Rashid Al Maktoum Solar Park, with DEWA and Siemens enabling clean energy storage, re-electrification, and fuel-cell mobility for Expo 2020 Dubai and public transport.

 

Key Points

Dubai Green Hydrogen is a DEWA-Siemens project making solar hydrogen for storage, mobility, and reelectrification.

✅ Electrolysis at Mohammed Bin Rashid Al Maktoum Solar Park

✅ Partners: DEWA and Siemens; public-private demonstration plant

✅ Hydrogen for buses, re-electrification, and energy storage

 

Something you hear frequently if you are a clean tech aficionado is that excess solar and wind power can be used to split water into oxygen and hydrogen. The Dubai Supreme Council of Energy, the 2020 Dubai Higher Committee and the Dubai Electricity and Water Authority broke ground in early February on a solar power hydrogen electrolysis facility located in the Mohammed Bin Rashid Al Maktoum Solar Park, and related initiatives like the Solar Decathlon Middle East underscore Dubai's clean energy focus. Sheikh Ahmed bin Saeed Al Maktoum, chairman of the Dubai Supreme Council of Energy and chairman of the Expo 2020 Dubai Higher Committee, participated in the groundbreaking ceremony, according to a report by Khaleej Times.

Saeed Mohammed Al Tayer, CEO of DEWA, said at the groundbreaking ceremony the project is important to understanding the limits of green hydrogen technology and how it can contribute to the UAE’s vision of clean energy, and aligns with DEWA's latest renewable initiatives now progressing in the emirate. “This pioneering project is a role model for strategic partnerships between the public and private sectors. It will contribute to developing the green economy concept in the UAE and explore the potential of green hydrogen technology. The hydrogen produced at the facility will be stored and deployed for re-electrification, transportation and other uses.”

Siemens is providing much of the technology that will be used at the demonstration facility, while DEWA expands its China outreach to woo renewable energy firms that can contribute to the ecosystem. Joe Kaeser, president and CEO of Siemens, said the UAE was the perfect location for Siemens to test the technology, building on advances in offshore green hydrogen the company is pursuing. One of the primary uses of the hydrogen produced will be to power Dubai’s public transportation system.

“We are aware of the stress that is placed on vehicles in this region due to the high levels of heat; with hydrogen cells, you are not putting as much strain on the vehicle and that improves its longevity,” Kaeser said. “However, this is only the first step and we are eager to explore more ways in which we can adapt the technology to other sectors. The interest from various companies and partners has been immense and we are eager to work with all interested parties.”

“Dewa, Expo 2020 Dubai and Siemens are working together to help realize His Highness Sheikh Mohammed bin Rashid Al Maktoum, Vice-President and Prime Minister of the UAE and Ruler of Dubai’s, vision to identify new energy resources and provide sustainable power as part of a balanced approach that prioritizes the environment. Our aim is to make Dubai a model of energy efficiency and safety,” said Sheikh Ahmed.

Expo 2020 Dubai intends to use the hydrogen generated at the facility to transport visitors to the Expo 2020 Dubai and the Mohammed bin Rashid Al Maktoum Solar Park, reflecting regional momentum such as Saudi Arabia's clean energy plans over the next decade, in hydrogen fuel cell powered vehicles. Live data of the green hydrogen electrolysis will be displayed at Expo 2020 Dubai to help inform broader efforts like hydrogen hubs in the United States.

 

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Romania moves to terminate talks with Chinese partner in nuke project

Romania Ends CGN Cernavoda Nuclear Deal, as Nuclearelectrica moves to terminate negotiations on reactors 3 and 4, citing the EU Green Deal, US partnership, NATO, and a shift to alternative nuclear capacity options.

 

Key Points

Romania orders Nuclearelectrica to end CGN talks on Cernavoda units 3-4 and pursue alternative nuclear options.

✅ Negotiations on Cernavoda units 3-4 to be formally terminated

✅ EU Green Deal and US partnership cited over security concerns

✅ Board to draft strategies for new domestic nuclear capacity

 

Romania's government has mandated the managing board of local nuclear power producer Nuclearelectrica to initiate procedures for terminating negotiations with China General Nuclear Power Group (CGN) on building two new reactors at the Cernavoda nuclear power plant, where IAEA safety reports continue to shape operations.

The government also mandated the managing board to analyse and draw up strategic options on the construction of new electricity generation capacities from nuclear sources, as other countries such as India take steps to get nuclear back on track in response to demand.

The company will negotiate the termination of the agreement signed in 2015 for developing and operating units 3 and 4 at Cernavoda, even as Germany turns away from nuclear within the European landscape. 

At the end of last month, Economy Minister Virgil Popescu said that the collaboration with the Chinese company couldn't continue as it has yielded no results in seven years, despite China's nuclear program expanding steadily elsewhere.

"We have a strategic partnership with the US, and we hold on to it, we respect our partners. We are members of the EU and Nato, even as Germany's final reactor closures unfold in Europe. Aside from that, I think that seven years since this collaboration with the Chinese company began is enough to realise that we can't move on," Popescu said at that time.

Liberal Prime Minister Ludovic Orban announced in January that the government would exit the deal with its Chinese partner. He invoked the European Union's Green Deal rather than security issues or cost concerns circulated previously as the main reason behind a potential end of the deal with CGN to expand Romania's only nuclear power plant, amid concerns that Europe is losing nuclear power when it needs energy.

In August last year, the US included CGN on a blacklist for allegedly trying to get nuclear technology from the US to be used for military purposes in China, even as nuclear cooperation with Cambodia expands in the region.

 

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Blackout-Prone California Is Exporting Its Energy Policies To Western States, Electricity Will Become More Costly And Unreliable

California Blackouts expose grid reliability risks as PG&E deenergizes lines during high winds. Mandated solar and wind displace dispatchable natural gas, straining ISO load balancing, transmission maintenance, and battery storage planning amid escalating wildfire liability.

 

Key Points

California grid shutoffs stem from wildfire risk, renewables, and deferred transmission maintenance under mandates.

✅ PG&E deenergizes lines to reduce wildfire ignition during high winds.

✅ Mandated solar and wind displace dispatchable gas, raising balancing costs.

✅ Storage, reliability pricing, and grid upgrades are needed to stabilize supply.

 

California is again facing widespread blackouts this season. Politicians are scrambling to assign blame to Pacific Gas & Electric (PG&E) a heavily regulated utility that can only do what the politically appointed regulators say it can do. In recent years this has meant building a bunch of solar and wind projects, while decommissioning reliable sources of power and scrimping on power line maintenance and upgrades.

The blackouts are connected with the legal liability from old and improperly maintained power lines being blamed for sparking fires—in hopes that deenergizing the grid during high winds reduces the likelihood of fires. 

How did the land of Silicon Valley and Hollywood come to have developing world electricity?

California’s Democratic majority, from Gov. Gavin Newsom to the solidly progressive legislature, to the regulators they appoint, have demanded huge increases in renewable energy. Renewable electricity targets have been pushed up, and policymakers are weighing a revamp of electricity rates to clean the grid, with the state expected to reach a goal of 33% of its power from renewable sources, mostly solar and wind, by next year, and 60% of its electricity from renewables by 2030.

In 2018, 31% of the electricity Californians purchased at the retail level came from approved renewables. But when rooftop solar is added to the mix, about 34% of California’s electricity came from renewables in 2018. Solar photovoltaic (PV) systems installed “behind-the-meter” (BTM) displace utility-supplied generation, but still affect the grid at large, as electricity must be generated at the moment it is consumed. PV installations in California grew 20% from 2017 to 2018, benefiting from the state’s Self-Generation Incentive Program that offers hefty rebates through 2025, as well as a 30% federal tax credit.

Increasingly large amounts of periodic, renewable power comes at a price—the more there is, the more difficult it is to keep the power grid stable and energized. Since electricity must be consumed the instant it is generated, and because wind and solar produce what they will whenever they do, the rest of the grid’s power producers—mostly natural gas plants—have to make up any differences between supply and immediate demand. This load balancing is vital, because without it, the grid will crash and widespread blackouts will ensue.

California often produces a surplus of mandated solar and wind power, generated for 5 to 8 cents per kilowatt hour. This power displaces dispatchable power from natural gas, coal and nuclear plants, resulting in reliable power plants spending less time online and driving up electricity prices as the plants operate for fewer hours of the day. Subsidized and mandated solar power, along with a law passed in California in 2006 (SB 1638) that bans the renewal of coal-fired power contracts, has placed enormous economic pressure on the Western region’s coal power plants—among them, the nation’s largest, Navajo Generating Station. As these plants go off line, the Western power grid will become increasingly unstable. Eventually, the states that share their electric power in the Western Interconnect may have to act to either subsidize dispatchable power or place a value on reliability—something that was taken for granted in the growth of the America’s electrical system and its regulatory scheme.

California law regarding electricity explicitly states that “a violation of the Public Utilities Act is a crime” and that it is “…the intent of the Legislature to provide for the evolution of the ISO (California’s Independent System Operator—the entity that manages California’s grid) into a regional organization to promote the development of regional electricity transmission markets in the western states.” In other words, California expects to dictate how the Western grid operates.

One last note as to what drives much of California’s energy policy: politics. California State Senator Kevin de León (the author served with him in the State Assembly) drafted SB 350, the Clean Energy and Pollution Reduction Act. It became law in 2015. Sen. de León followed up with SB 100 in 2018, signed into law weeks before the 2018 election. SB 100 increased California’s renewable portfolio standard to 60% by 2030 and further requires all the state’s electricity to come from carbon-free sources by 2045, a capstone of the state’s climate policies that factor into the blackout debate.  

Sen. de León used his environmental credentials to burnish his run for the U.S. Senate against Sen. Dianne Feinstein, eventually capturing the endorsements of the California Democratic Party and billionaire environmentalist Tom Steyer, now running for president. Feinstein and de León advanced to the general in California’s jungle primary, where Feinstein won reelection 54.2% to 45.8%.

De León may have lost his race for the U.S. Senate, but his legacy will live on in increasingly unaffordable electricity and blackouts, not only in California, but in the rest of the Western United States—unless federal or state regulators begin to place a value on reliability. This could be done by requiring utility scale renewable power providers to guarantee dispatchable power, as policymakers try to avert a looming shortage of firm capacity, either through purchase agreements with thermal power plants or through the installation of giant and costly battery farms or other energy storage means.

 

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