Italy is considering introducing an installed capacity cap for solar power incentives in its new decree on renewable energy, government and industry sources state.
The government, which has decided to scrap the existing generous solar incentive scheme from June, has been drafting a new support scheme.
"We have spoken to the Industry ministry and the feeling is it might introduce a cap on installed capacity, though the decree has not been finalized," a source at one of Italy's energy associations said.
Investors fear an annual cap on incentivized capacity could slow down the country's solar market.
Just recently a junior minister said the government aimed to complete the renewable energy decree by now, but the sources said discussions will require a few more days.
A government source told Reuters the decree was still in the works. When completed it needs to be signed by the Industry and Environment ministries but then needs to go before a committee of representatives of regional governments for its opinion.
The committee is due to meet on April 20 though as yet no agenda has been set, a spokeswoman for the body said.
Solar incentives are paid for by consumers in their energy bills and the government is seeking to lower these costs.
In March a trade union official, after a meeting with the government, told Reuters that Rome was considering capping the overall money it spends on solar incentives every year rather than using an actual installation cap.
But two industry sources said the government is now leaning more toward introducing a yearly cap on installed capacity.
La Repubblica newspaper, citing the latest version of the draft decree, said the government was considering reintroducing a cap on installed capacity of 1550-1800 megawatts for 2011 and up to 2,800 megawatts in 2012.
The article said incentives for solar power generation in 2011 would be cut by 25 percent immediately with an 8 percent cut in 2012.
"I don't think the final version is ready yet. We are proposing for 2012 a 5 percent cut for plants under 1 megawatt and a 10 percent cut for plants over 1 megawatt," GIFI President Valerio Natalizia told Reuters.
Italy's biggest solar industry body GIFI is a key party in talks with the government on new incentives. GIFI has also proposed the tariffs be reduced on an annual basis, under a German model, from 2012.
Italy's solar sector, among the biggest in Europe, has boomed since 2007, when some of Europe's most generous production incentives were launched.
It has attracted the world's biggest photovoltaic module makers such as China's Suntech Power Holdings Co, Trina, Yilgli Green Energy and U.S. firm First Solar.
Italy's biggest renewable operator is Enel Green Power while utilities such as Edison and CIR energy unit Sorgenia have renewable businesses.
Methane Hydrate CO2 Sequestration uses carbon capture and nitrogen injection to swap gases in seafloor hydrates along the Gulf of Mexico, releasing methane for electricity while storing CO2, according to new simulation research.
Key Points
A method injecting CO2 and nitrogen into hydrates to store CO2 while releasing methane for power.
✅ Nitrogen aids CO2-methane swap in hydrate cages, speeding sequestration
✅ Gulf Coast proximity to emitters lowers transport and power costs
✅ Revenue from methane electricity could offset carbon capture
The world is quickly realizing it may need to actively pull carbon dioxide out of the atmosphere to stave off the ill effects of climate change. Scientists and engineers have proposed various carbon capture techniques, but most would be extremely expensive—without generating any revenue. No one wants to foot the bill.
One method explored in the past decade might now be a step closer to becoming practical, as a result of a new computer simulation study. The process would involve pumping airborne CO2 down into methane hydrates—large deposits of icy water and methane right under the seafloor, beneath water 500 to 1,000 feet deep—where the gas would be permanently stored, or sequestered. The incoming CO2 would push out the methane, which would be piped to the surface and burned to generate electricity, whether sold locally or via exporters like Hydro-Qu e9bec to help defray costs, to power the sequestration operation or to bring in revenue to pay for it.
Many methane hydrate deposits exist along the Gulf of Mexico shore and other coastlines. Large power plants and industrial facilities that emit CO2 also line the Gulf Coast, where EPA power plant rules could shape deployment, so one option would be to capture the gas directly from nearby smokestacks, keeping it out of the atmosphere to begin with. And the plants and industries themselves could provide a ready market for the electricity generated.
A methane hydrate is a deposit of frozen, latticelike water molecules. The loose network has many empty, molecular-size pores, or “cages,” that can trap methane molecules rising through cracks in the rock below. The computer simulation shows that pushing out the methane with CO2 is greatly enhanced if a high concentration of nitrogen is also injected, and that the gas swap is a two-step process. (Nitrogen is readily available anywhere, because it makes up 78 percent of the earth’s atmosphere.) In one step the nitrogen enters the cages; this destabilizes the trapped methane, which escapes the cages. In a separate step, the nitrogen helps CO2 crystallize in the emptied cages. The disturbed system “tries to reach a new equilibrium; the balance goes to more CO2 and less methane,” says Kris Darnell, who led the study, published June 27 in the journal Water Resources Research. Darnell recently joined the petroleum engineering software company Novi Labs as a data scientist, after receiving his Ph.D. in geoscience from the University of Texas, where the study was done.
A group of labs, universities and companies had tested the technique in a limited feasibility trial in 2012 on Alaska’s North Slope, where methane hydrates form in sandstone under deep permafrost. They sent CO2 and nitrogen down a pipe into the hydrate. Some CO2 ended up being stored, and some methane was released up the same pipe. That is as far as the experiment was intended to go. “It’s good that Kris [Darnell] could make headway” from that experience, says Ray Boswell at the U.S. Department of Energy’s National Energy Technology Laboratory, who was one of the Alaska experiment leaders but was not involved in the new study. The new simulation also showed that the swap of CO2 for methane is likely to be much more extensive—and to happen quicker—if CO2 enters at one end of a hydrate deposit and methane is collected at a distant end.
The technique is somewhat similar in concept to one investigated in the early 2010s by Steven Bryant and others at the University of Texas. In addition to numerous methane hydrate deposits, the Gulf Coast has large pools of hot, salty brine in sedimentary rock under the coastline. In this system, pumps would send CO2 down into one end of a deposit, which would force brine into a pipe that is placed at the other end and leads back to the surface. There the hot brine would flow through a heat exchanger, where heat could be extracted and used for industrial processes or to generate electricity, supporting projects such as electrified LNG in some markets. The upwelling brine also contains some methane that could be siphoned off and burned. The CO2 dissolves into the underground brine, becomes dense and sinks further belowground, where it theoretically remains.
Either system faces big practical challenges, and building shared CO2 storage hubs to aggregate captured gas is still evolving. One is creating a concentrated flow of CO2; the gas makes up only .04 percent of air, and roughly 10 percent of the smokestack emission from a typical power plant or industrial facility. If an efficient methane hydrate or brine system requires an input that is 90 percent CO2, for example, concentrating the gas will require an enormous amount of energy—making the process very expensive. “But if you only need a 50 percent concentration, that could be more attractive,” says Bryant, who is now a professor of chemical and petroleum engineering at the University of Calgary. “You have to reduce the [CO2] capture cost.”
Another major challenge for the methane hydrate approach is how to collect the freed methane, which could simply seep out of the deposit through numerous cracks and in all directions. “What kind of well [and pipe] structure would you use to grab it?” Bryant asks.
Given these realities, there is little economic incentive today to use methane hydrates for sequestering CO2. But as concentrations rise in the atmosphere and the planet warms further, and as calls for an electric planet intensify, systems that could capture the gas and also provide energy or revenue to run the process might become more viable than techniques that simply pull CO2 from the air and lock it away, offering nothing in return.
KHNP Shortlisted for Belene Nuclear Power Plant, named by the Bulgarian Energy Ministry alongside Rosatom and CNNC; highlights APR1400 reactor expertise, EPC credentials, and expansion into the European nuclear energy market.
Key Points
KHNP is a strategic investor candidate for Bulgaria's Belene NPP, leveraging APR1400 and European market entry.
✅ Selected with Rosatom and CNNC by Bulgarian Energy Ministry
✅ Builds on APR1400 reactor design and EPC track record
✅ Positions KHNP for EU nuclear projects and O&M services
Korea Hydro & Nuclear Power (KHNP) has been selected as one of the three strategic investor candidates for a Bulgarian nuclear power plant project amid global nuclear project milestones worldwide.
The Bulgarian Energy Ministry selected KHNP of Korea, RosAtom of Russia and CNNC of China as strategic investor candidates for the construction of the Belene Nuclear Power Plant, KHNP said on Dec. 20. The Belene Nuclear Power Plant is the second nuclear power plant that Bulgaria plans to build following the 2,000-megawatt Kozloduy Nuclear Power Plant built in 1991 during the Soviet Union era. The project budget is estimated at 10 billion euros.
By being included in the shortlist for the Bulgarian project, KHNP has boosted the possibility of making a foray into the European nuclear power plant market, as India takes steps to get nuclear back on track worldwide. KHNP began to export nuclear power plants in 2009 by winning the UAE Barakah Nuclear Power Plant Project, with Barakah Unit 1 reaching 100% power as it moves toward commercial operations. The UAE plant will be based on the APR1400, a next-generation Korean nuclear reactor that is used in Shin Kori Units 3 and 4 in Korea.
The ARP1400 is a Korean nuclear reactor developed by KHNP with investment of about 230 billion won for 10 years from 1992. The nuclear reactor became the first non-U.S. type reactor to receive a design certificate (DC) from the U.S. Nuclear Regulatory Commission (NRC), as China's nuclear energy program continues on a steady development track globally. By receiving the DC, its safety was internationally recognized. In June, the company also won the maintenance project for the Barakah Nuclear Power Plant, completing the entire cycle from the construction of the nuclear power plant to its design, operation and maintenance. However, U.S. and U.K. companies took part of the maintenance project for the nuclear power plant.
In July, KHNP officials visited Turkey and contacted local energy officials to prepare for nuclear power plant projects to be launched in that country, as Bangladesh develops nuclear power with IAEA assistance in the region. Earlier in May, the company also submitted a proposal to participate in the construction of a new nuclear power plant in Kazakhstan, while Kenya moves forward with plans for a $5 billion plant.
Alberta electricity price spike drives 25% CPI surge amid heatwave demand, coal-to-gas conversions, hydro shortfalls, and outages; consumers weigh fixed-rate plans, solar panels, home retrofits, and variable rates to manage bills and grid volatility.
Key Points
A recent 25% monthly rise in Alberta power prices driven by heatwave demand, constraints, outages, and fuel shifts.
✅ Heatwave pushed summer peak demand near record
✅ Coal-to-gas conversions and outages tightened supply
✅ Fixed-rate plans, solar, retrofits can reduce bill risk
Albertans might notice they are paying more when the next electricity bill comes in as bills on the rise in Calgary alongside provincial trends.
According to the consumer price index, Alberta saw its largest monthly increase since July 2015 as the price of electricity in Alberta rose 25 per cent amid rising electricity prices across the province.
“So I paid negative $70 last month. I actually made money. To supply power to the grid,” said Conrad Nobert, with Climate Action Edmonton.
Norbert is an environmental activist who favours solar power and is warning that prices will continue to go up along with the rising effects from climate change.
“My thoughts are that we can mitigate the price of power going up by taking climate action.”
Alberta experienced one of the hottest summers on record and many people were left scrambling to buy air conditioners.
That demand, along with a number of other factors, drove up prices, prompting some households to lock in rates for protection, says an assistant professor at the University of Calgary who teaches electricity systems.
“At the end of June, during the heatwave, we were a couple megawatts shy of setting an all-time record demand for electricity in the province. That would have been the first time that record for demand in the summer. Traditionally Alberta is a winter peaking province, as shown by an electricity usage record during a deep freeze not long ago,” explained Sara Hastings Simon, an assistant professor at the University of Calgary.
There are a few ways consumers can save money on their power bill; installing solar panels and retrofitting your home to opting for a fixed-rate plan, or considering protections like a consumer price cap where applicable.
“So by default, people are put into a variable rate plan, that changes month to month and that helps to manage prices so you don’t get that big surprise at where prices might be. I think we will get a lot more people looking at that option.”
A statement provided by Dale Nally, Alberta’s Associate Minister of natural gas and electricity, noted recent policy changes including the carbon tax repeal and price cap now in place that affect consumers, says in part:
“This period of high market prices is driven by low supplies of hydro-generated electricity from British Columbia and the pacific northwest, scheduled outages for coal-gas-conversions, unplanned infrastructure outages and unprecedented, and record-breaking high demand due to hot weather. We expect some of the factors that have caused recent increases in prices will be short-term.”
Scottish Renewable Grid Upgrades address outdated infrastructure, expanding transmission lines, pylons, and substations to move clean energy, meet rising electricity demand, and integrate onshore wind, offshore wind, and battery storage across Scotland.
Key Points
Planned transmission upgrades in Scotland to move clean power via new lines and substations for a low-carbon grid.
✅ Fivefold expansion of transmission lines by 2030
✅ Enables onshore and offshore wind integration
✅ New pylons, substations, and routes face local opposition
Renewable energy in Scotland is being held back by outdated grid infrastructure, industry leaders said, with projects stuck on hold underscoring their warning that new pylons and power lines are needed to "ensure our lights stay on".
Scottish Renewables said new infrastructure is required to transmit the electricity generated by green power sources and help develop "a clean energy future" informed by a broader green recovery agenda.
A new report from the organisation - which represents companies working across the renewables sector - makes the case for electricity infrastructure to be updated, aligning with global network priorities identified elsewhere.
But it comes as electricity firms looking to build new lines or pylons face protests, with groups such as the Strathpeffer and Contin Better Cable Route challenging power giant SSEN over the route chosen for a network of pylons that will run for about 100 miles from Spittal in Caithness to Beauly, near Inverness.
Scottish Renewables said it is "time to be upfront and honest" about the need for updated infrastructure.
It said previous work by the UK National Grid estimated "five times more transmission lines need to be built by 2030 than have been built in the past 30 years, at a cost of more than £50bn".
The Scottish Renewables report said: "Scotland is the UK's renewable energy powerhouse. Our winds, tides, rainfall and longer daylight hours already provide tens of thousands of jobs and billions of pounds of economic activity.
"But we're being held back from doing more by an electricity grid designed for fossil fuels almost a century ago, a challenge also seen in the Pacific Northwest today."
Investment in the UK transmission network has "remained flat, and even decreased since 2017", echoing stalled grid spending trends elsewhere, the report said.
It added: "We must build more power lines, pylons and substations to carry that cheap power to the people who need it - including to people in Scotland.
"Electricity demand is set to increase by 50% in the next decade and double by mid-century, so it's therefore wrong to say that Scottish households don't need more power lines, pylons and substations.
Renewable energy in Scotland is being held back by outdated grid infrastructure, industry leaders said, as they warned new pylons and power lines are needed to "ensure our lights stay on".
Scottish Renewables said new infrastructure is required to transmit the electricity generated by green power sources and help develop "a clean energy future".
A new report from the organisation - which represents companies working across the renewables sector - makes the case for electricity infrastructure to be updated.
But it comes as electricity firms looking to build new lines or pylons face protests, with groups such as the Strathpeffer and Contin Better Cable Route challenging power giant SSEN over the route chosen for a network of pylons that will run for about 100 miles from Spittal in Caithness to Beauly, near Inverness.
Scottish Renewables said it is "time to be upfront and honest" about the need for updated infrastructure.
It said previous work by the UK National Grid estimated "five times more transmission lines need to be built by 2030 than have been built in the past 30 years, at a cost of more than £50bn".
The Scottish Renewables report said: "Scotland is the UK's renewable energy powerhouse. Our winds, tides, rainfall and longer daylight hours already provide tens of thousands of jobs and billions of pounds of economic activity.
"But we're being held back from doing more by an electricity grid designed for fossil fuels almost a century ago."
Investment in the UK transmission network has "remained flat, and even decreased since 2017", the report said.
It added: "We must build more power lines, pylons and substations to carry that cheap power to the people who need it - including to people in Scotland.
"Electricity demand is set to increase by 50% in the next decade and double by mid-century, so it's therefore wrong to say that Scottish households don't need more power lines, pylons and substations.
"We need them to ensure our lights stay on, as excess solar can strain networks in the same way consumers elsewhere in the UK need them.
"With abundant natural resources, Scotland's home-grown renewables can be at the heart of delivering the clean energy needed to end our reliance on imported, expensive fossil fuel.
"To do this, we need a national electricity grid capable of transmitting more electricity where and when it is needed, echoing New Zealand's electricity debate as well."
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Nick Sharpe, director of communications and strategy at Scottish Renewables, said the current electricity network is "not fit for purpose".
He added: "Groups and individuals who object to the construction of power lines, pylons and substations largely do so because they do not like the way they look.
"By the end of this year, there will be just over 70 months left to achieve our targets of 11 gigawatts (GW) offshore and 12 GW onshore wind.
"To ensure we maximise the enormous socioeconomic benefits this will bring to local communities, we will need a grid fit for the 21st century."
Pickering Nuclear False Alert Investigation probes Ontario's emergency alert system after a provincewide cellphone, radio, and TV warning, assessing human error, Pelmorex safeguards, Emergency Management Ontario oversight, and communication delays.
Key Points
An Ontario probe into the erroneous Pickering nuclear alert, focusing on human error, system safeguards, and oversight.
✅ Human error during routine testing suspected
✅ Pelmorex safeguards and EMO protocols under review
✅ Two-hour all-clear delay prompts communication fixes
An investigation into a mistaken Pickering alert warning of an incident at the Pickering Nuclear Generating Station will be completed fairly quickly, Ontario's solicitor general said.
Sylvia Jones tapped the chief of Emergency Management Ontario to investigate how the alert warning of an unspecified problem at the facility was sent in error to cellphones, radios and TVs across the province at about 7:30 a.m. Sunday.
"It's very important for me, for the people of Ontario, to know exactly what happened on Sunday morning," said Jones. "Having said that, I do not anticipate this is going to be a long, drawn-out investigation. I want to know what happened and equally important, I want some recommendations on insurances and changes we can make to the system to make sure it doesn't happen again."
Initial observations suggest human error was responsible for the alert that was sent out during routine tests of the emergency alert, Jones said.
"This has never happened in the history of the tests that they do every day, twice a day, but I do want to know exactly all of the issues related to it, whether it was one human error or whether it was a series of things."
Martin Belanger, the director of public alerting for Pelmorex, a company that operates the alert system, said there are a number of safeguards built in, including having two separate platforms for training and live alerts.
"The software has some steps and some features built in to minimize that risk and to make sure that users will be able to know whether or not they're sending an alert through the...training platform or whether they're accessing the live system in the case of a real emergency," he said.
Only authorized users have access to the system and the province manages that, Belanger said. Once in the live system, features make the user aware of which platform they are using, with various prompts and messages requiring the user's confirmation. There is a final step that also requires the user to confirm their intent of issuing an alert to cellphones, radio and TVs, Belanger said.
On Sunday, a follow-up alert was sent to cellphones nearly two hours after the original notification, and similar grid alerts in Alberta underscore timing and public expectations.
NDP energy critic Peter Tabuns is critical of that delay, noting that ongoing utility scam warnings can further erode public trust.
"That's a long time for people to be waiting to find out what's really going on," he said. "If people lose confidence in this system, the ability to use it when there is a real emergency will be impaired. That's dangerous."
Treasury Board President Peter Bethlenfalvy, who represents the riding of Pickering-Uxbridge, said getting that alert Sunday morning was "a shock to the system," and he too wants the investigation to address the reason for the all-clear delay.
"We all have a lot of questions," he said. "I think the public has every right to know exactly what went on and we feel exactly the same way."
People in the community know the facility is safe, Bethlenfalvy said.
"We have some of the safest nuclear assets in the world -- the safest -- at 60 per cent of Ontario's electricity," he said.
A poll released Monday found that 82 per cent of Canadians are concerned about spills from nuclear reactors contaminating drinking water and 77 per cent are concerned about neighbourhood safety and security risks for those living close to nuclear plants. Oraclepoll Research surveyed 2,094 people across the country on behalf of Friends of the Earth between Jan. 2 and 12, the day of the false alert. The have a margin of error of plus or minus 2.1 per cent, 19 times out of 20.
The wording of Sunday's alert caused much initial confusion, and events like a power outage in London show how morning disruptions can amplify concern, warning residents within 10 kilometres of the plant of "an incident," though there was no "abnormal" release of radioactivity and residents didn't need to take protective steps, but emergency crews were responding.
In the event of a real emergency, the wording would be different, Jones said.
"There are a number of different alerts that are already prepared and are ready to go," she said. "We have the ability to localize it to the communities that are impacted, but because this was a test, it went provincewide."
Jones said she expects the results of the probe to be made public.
The Pickering nuclear plant has been operating since 1971, and had been scheduled to be decommissioned this year, but the former Liberal government -- and the current Progressive Conservative government -- committed to keeping it open until 2024. Decommissioning is now set to start in 2028.
It operates six CANDU reactors, generates 14 per cent of Ontario's electricity and is responsible for 4,500 jobs across the region, according to OPG, and OPG's credit rating remains stable.
During the COVID-19 pandemic, Hydro One employees supported the Province of Ontario in the fight against COVID-19.
The Green party is calling on the province to use this opportunity to review its nuclear emergency response plan, including pandemic staffing contingencies, last updated in 2017 and subject to review every five years.
Toronto Mayor John Tory praised Ontario for swiftly launching an investigation, but said communication between city and provincial officials wasn't what it should have been under the circumstances.
"It was a poor showing and I think everybody involved knows that," he said. "We've got to make sure it's not repeated."
ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.
Key Points
ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.
✅ Tokamak magnetic confinement with high-temp superconducting coils
✅ Deuterium-tritium fuel cycle with on-site tritium breeding
✅ Targets net energy gain and grid-scale, low-carbon electricity
It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.
Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.
But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.
“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.
Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.
Constructing a nuclear fusion reactor ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.
The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.
When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.
Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.
In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.
A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.
One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat
The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.
“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.
The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.
“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.
Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.
Choosing a fuel Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.
Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.
At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.
The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.
“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”
