Hydrogen power is gaining momentum, but critics say it’s neither efficient nor green enough

FRI, JAN 7 2022
Catherine Clifford@IN/CATCLIFFORD/@CATCLIFFORD

CNBC

KEY POINTS

When you burn hydrogen, you generate energy in the form of heat, and the only by-product is water, making it a clean source of energy. However, it requires energy to make the hydrogen in the first place.

Hydrogen is part of climate discussions for hard-to-decarbonize sectors like trucking, airplanes and as a store of electricity.

But critics say pursuing green hydrogen as a fuel source is not the best solution for combatting climate change because it’s inefficient and is often created with carbon-emitting energy sources.


The Linde AG logo on a liquid hydrogen tanker truck taking a fuel delivery at the Linde hydrogen plant in Leuna, Germany, on Tuesday, July 14, 2020.
Rolf Schulten | Bloomberg | Getty Images

Hydrogen is the simplest element, and the most abundant substance in the universe.

When hydrogen burns, it generates energy in the form of heat, and the only by-product is water. That means energy created from hydrogen generates no atmosphere-warming carbon dioxide, making it one of many potential energy sources that could help reduce carbon emissions and slow global warming.

But creating hydrogen and transforming it into a useful format requires energy — and that energy is not necessarily renewable. That process is also inefficient and expensive compared with other forms of energy, renewable or not. Many critics say the hydrogen industry a way for oil and gas giants to stall the adoption of pure renewable energy sources like solar and wind, giving them a “green” cover while still maintaining demand for their products.

Despite the debate, companies and the U.S. government alike are pushing forward the continued development of the hydrogen industry.

“In my travels around the world I can’t name a country that hasn’t expressed excitement about hydrogen,” John Kerry, special presidential envoy for climate, at the Department of Energy’s Hydrogen Shot Summit last August. “From Saudi Arabia to India to Germany to Japan we’re setting up hydrogen partnerships around the world to advance this critical technology that every country understands has the opportunity to play a vital role in the clean energy transition.”

Hydrogen may grow into a multitrillion-dollar global market, said Kerry, although he warned China wants to dominate it.

28 August 2021, Brandenburg, Prenzlau: A hydrogen tank is located in the Enertrag hybrid power plant in Brandenburg. At the Enertrag hybrid power plant, green hydrogen is produced from wind power and fed into the gas grid.

Photo by Fabian Sommer/picture alliance via Getty Images

What is green hydrogen, blue hydrogen, and so on?

Producing hydrogen takes energy because hydrogen atoms don’t exist on their own — they are almost always stuck to another atom, often another element. (On earth, hydrogen is particularly abundant in the form of water, or H2O.) Creating pure hydrogen requires breaking those molecular bonds.

In the energy business, people refer to hydrogen by an array of colors to as shorthand for how it was created.

One may of making hydrogen is a process called electrolysis, when electricity is passed through a substance to force a chemical change — in this case, splitting H2O into hydrogen and oxygen.

Green hydrogen is when the energy used to power electrolysis comes from renewable sources like wind, water or solar.

VIDEO15:25 Green hydrogen could help us cut our carbon footprint, if it overcomes hurdles

Blue hydrogen is hydrogen produced from natural gas with a process of steam methane reforming, where natural gas is mixed with very hot steam and a catalyst. A chemical reaction occurs creating hydrogen and carbon monoxide. Water is added to that mixture, turning the carbon monoxide into carbon dioxide and more hydrogen. If the carbon dioxide emissions are then captured and stored underground, the process is considered carbon-neutral, and the resulting hydrogen is called “blue hydrogen.”

But there’s some controversy over blue hydrogen because natural gas production inevitably results in methane emissions from so-called fugitive leaks, which are leaks of methane from the drilling, extraction and transportation process.

Methane does not last in the atmosphere as long as carbon dioxide, but it is much more potent as a greenhouse gas. Over 100 years, one ton of methane can considered to be equivalent to 28 to 36 tons of carbon dioxide, according to the International Energy Agency.

Grey hydrogen is made from natural gas reforming like blue hydrogen, but without any efforts to capture carbon dioxide byproducts.

Pink hydrogen is hydrogen made with electrolysis powered by nuclear energy, which does not produce any carbon dioxide emissions. (Although nuclear energy creates radioactive waste which must be stored safely for thousands of years.)

Yellow hydrogen is hydrogen made with electrolysis from the energy grid. The carbon emissions vary greatly depending on the sources powering the grid.

Turquoise hydrogen is hydrogen produced from methane pyrolysis, or splitting methane into hydrogen and solid carbon with heat in reactors or blast furnaces. Turquoise hydrogen is still in its nascent stages of being commercialized, and its climate-conscious value depends on powering the pyrolysis with clean energy and storing the physical carbon.

The color system is a bit simplistic and needs to be updated and made more specific, said Daryl Wilson, the executive director of the coalition of the Hydrogen Council, an organization of industry CEOs.

“The color scheme is not helpful in in the sense that it’s not getting to the key point, which is what are the environmental attributes of the hydrogen being produced,” Wilson told CNBC. “The key issue is there has to be a methodology for tracking and declaring the specific CO² intensity of whatever hydrogen you’re working with.”

Proponents say hydrogen is versatile, but expensive

Hydrogen is already a key component of chemical industrial processes and in the steel industry. So making clean hydrogen to use in those industrial processes is critical to reducing carbon emissions, says Jake Stones at market research firm Independent Commodity Intelligence Services (ICIS).

But as an energy source itself, hydrogen’s big advantage is its versatility according to Sunita Satyapal, who oversees hydrogen fuel cell technology for the Department of Energy.

“It’s often called the Swiss Army knife of energy,” she says.

Clean hydrogen would be useful in decarbonizing industrial heavy transportation like trucking, big industrial boats, and planes, according to Stones.

It’s less interesting for smaller consumer vehicles, as battery-powered cars are being adopted much more readily. But bigger vehicles require larger batteries, which increases their weight, which in turn increases their energy use. Hydrogen can be a way around that conundrum.

Hydrogen can also be used as a way to store energy from intermittent renewable sources, which are intermittent -- the sun isn’t always shining and the wind isn’t always blowing. Instead, utilities can convert the excess energy into hydrogen and then use it for energy later on, as an alternative to battery storage.

Hydrogen “can be stored underground for as long it needs to be, much the same as natural gas, and on a seasonal basis,” Stones told CNBC.

A hydrogen-powered vehicle during refueling at the newly opened hydrogen fueling station, operated by Saudi Aramco, in the Air Products New Technology Center in Dhahran, Saudi Arabia, on Sunday, June 27, 2021. Saudi Aramco outlined plans to invest in blue hydrogen as the world shifts away from dirtier forms of energy, but said it will take at least until the end of this decade before a global market for the fuel is developed.
Photographer: Maya Siddiqui/Bloomberg via Getty Images

The main drawback of hydrogen is its expense. Making hydrogen from natural gas costs about $1.50 per kilogram, said Satyapal. Clean hydrogen costs about $5 per kilogram.

Last June, the Department of Energy launched a program called the Hydrogen Shot, which aims to reduce the cost of clean hydrogen to $1 per one kilogram in one decade.

Driving down the price of clean hydrogen “would be a huge step toward solving climate change,” said billionaire Bill Gates, the founder of Breakthrough Energy Ventures, at the Department of Energy’s Hydrogen Shot Summit. “The goal of cutting premium by 80 percent is a fantastic and ambitious goal,” he said.

There are three primary pathways the Department of Energy sees as how to get the cost of clean hydrogen down from about $5 per kilogram to $1:
Improving the efficiency, durability and manufacturing volume of electrolyzers.
Improving pyrolysis, which generates solid carbon, not carbon dioxide as a byproduct, Satyapal said.
“Advanced pathways,” which is a bit of a catch-all for experimental technologies. One example is photoelectrochemical approach (PEC), where sunlight and specialized semiconductors are used to break water into sunlight and hydrogen.

Skeptics say it’s inefficient and impractical

While green hydrogen could be critical to decarbonize heavy industry, power ships and planes, and perhaps store energy, it is not efficient to use more broadly as an energy source, says Robert W. Howarth, professor of ecology and environmental biology at Cornell University.

Howarth is one of the 22 members of the New York Climate Action Council, a group charged with developing an implementation plan for the law mandating New York’s decarbonization plan. In summer of 2020, natural gas industry stakeholders suggested using blue hydrogen in the existing natural gas pipeline infrastructure to heat homes.

But Howarth and Stanford professor Mark Jacobson published a research paper in August showing that was a bad idea.

“The bottom line is that blue hydrogen has huge emissions and cannot be used except at low percentages in the current gas system,” Howarth told CNBC. “It is far cheaper to instead move to electrically driven heat pumps for heating.”

Other critics say the problems with hydrogen are more fundamental.

The process of producing hydrogen, compressing it, and then turning that compressed hydrogen back into electricity or mechanical energy is grossly inefficient, according to Paul Martin, a chemical process development expert and member of the Hydrogen Science Coalition.

“It’s worth putting up with a lot of problems with a battery because for every one joule you put in, you get 90% of it back. That’s pretty great,” Martin told CNBC. In producing and storing hydrogen, you get only 37% of the energy back out. “So 63% of the energy that you said, is lost. And that’s best case.”

But the idea of using hydrogen as a fuel is bogus, said Martin, who calls himself a life-long environmentalist.

“The people that are really behind this hydrogen push are the fossil fuel industry, because without it, what are they going to do? The fossil fuel industry without fossil fuels is basically the petroleum chemicals and materials business, which is about 25% of the current business.”

Still, Martin thinks pursuing green hydrogen is important for all its other uses, like industrial processes and the Haber-Bosch process, which converts hydrogen and nitrogen to ammonia to use in fertilizer. The Haber-Bosch process is credited with massively increasing food production and helping to feed the earth’s exploding population over the last 100 years.

“I don’t want people to think I’m anti-hydrogen. I think making green hydrogen is super-important,” Martin said.

“But it’s also super important to use it for the right things and not dumb things.”

Banks risk becoming new fossil fuel villains in 2022

Banks are turning on the taps for green finance but they are far from closing them for fossil fuels

Pilita Clark

Net Zero Banking Alliance requires banks to calculate and model the carbon footprint of loan portfolios worth billions of euro. Photograph: Getty

As businesses were gearing up for the COP26 climate summit in Glasgow last year, one of Europe’s larger banks released an update on how it planned to do its bit to combat global warming.

Switzerland’s UBS group said it had become a founding member of the new Net Zero Banking Alliance, a UN-convened club of mostly western banks committed to decarbonising their portfolios.

“We’ll publish a comprehensive climate action plan later this year, setting science-based targets, including intermediate milestones,” UBS said. This was in April. But there was no new action plan by the end of the year. The bank says it is now aiming for March.

One explanation for the delay is that the climate programme had to fit in with a broader strategic vision for UBS, which its newish chief executive, Ralph Hamers, is due to unveil in February. But the lag also reflects a wider industry dilemma: the vast volume of work that banks are confronting as they grapple with net zero commitments that are set to make 2022 a year when financing fossil fuels grows more visible – and troublesome – than ever before.
The world’s 60 largest private sector banks have put more than $3.8tn into the oil, gas and coal sectors since the 2015 Paris agreement

“It’s a huge task,” says Jörg Eigendorf, head of communications and sustainability at Deutsche Bank. Membership of the Net Zero Banking Alliance requires it to calculate and model the carbon footprint of a loan portfolio worth billions of euro, which it will disclose by the end of 2022.

“That will bring much greater transparency and scrutiny from regulators, politicians, investors and the general public,” says Eigendorf.
Green financing

You might not think this will matter much, considering the trend towards green financing. Renewables and other climate-friendly ventures received more bank-issued bonds and loans than the fossil fuel sector for the first time in 2021, and more backing is in the pipeline.


Deutsche Bank, JPMorgan Chase and HSBC are among more than a dozen banks whose annual green financing commitments now outstrip their 2020 support for fossil fuels, says Autonomous, a financial research firm.

Definitions of green financing can be generous, but the direction of greenward travel seems clear – except for one thing. Banks may be turning on the taps for green finance but they are far from closing them for fossil fuels.

The world’s 60 largest private sector banks have put more than $3.8 trillion (€3.35 trillion) into the oil, gas and coal sectors since the 2015 Paris agreement, according to NGO research. And a lot has gone to oil and gas companies with big expansion plans.
Zeroing emissions

With no sign of rapid change, banks face a double difficulty in exposing their fossil financing to more scrutiny – and charges of climate villainy – without showing how they might eventually wind it back.

In theory, the problem should be solved by a group like the Net Zero Banking Alliance, whose 98 members account for more than 40 per cent of global banking assets. They have to set out plans for zeroing out emissions. The trouble is the brutal maths.

Scientists have established it is much safer to limit global warming to 1.5 degrees. So human-made carbon emissions, much of which come from burning oil, gas and coal, should nearly halve by 2030 and fall to net zero by about 2050. Long story short: the world has to quickly wean itself off fossil fuels, that make up about 80 per cent of the energy mix, and ditch plans to dig up more.

Banks have reduced backing for coal over time. But very few net zero alliance members have issued detailed plans showing how and when they might wind down support for oil and gas as well – the rules give them several years.

One exception is France’s La Banque Postale. In October it said it would exit oil and gas industries completely by 2030, the same as its deadline for coal. Goldman Sachs, JPMorgan Chase and other banks in the alliance that have begun to publish more detailed net zero plans have yet to follow its lead.

They may stand to lose more business than the French bank, but some analysts think loss of brown financing could be offset by green growth. Rising demand from a swelling green sector for loans and other banking services could be worth an extra net $2.3 trillion a year for decades, says Autonomous.
Private equity

Privately, some bankers acknowledge the risk of sticking with companies determined to keep generating a lot of emissions, but little bank revenue, especially if rival lenders start staking out profitable green turf. Others say it is risky to be a first-mover in the absence of meaningful carbon pricing or other government policies to level the financing playing field.

And what’s the point of listed banks exiting fossil fuels if private investors facing less scrutiny step in? Private equity firms are estimated to have invested more than $1 trillion in the energy industry since 2010, mostly in fossil fuels, which underlines where the net zero financing battle is heading next.

“Publicly traded banks are not the end of the problem,” says Mike Hugman, director of climate finance at the Children’s Investment Fund Foundation. Private equity investors should demand that all companies they back have meaningful climate action plans, he says.

Not long ago, this idea would have sounded fanciful. But times are changing fast. Just ask a bank.

 – Copyright The Financial Times Limited 2022

AUSTRALIA 

Brisbane Times

Shell’s Prelude gas vessel faced ‘catastrophic failure’ from power outage

 By Peter Milne: January 5, 2022 

Power problems on Shell’s giant Prelude gas vessel in December with almost 300 workers on board risked the “catastrophic failure” of parts of the ship’s structure, according to a report by the offshore safety regulator.

While the crew off the WA coast battled in tropical heat without air conditioning or ventilation to restore power, the steel spine of the vessel was cooling towards a point where it could have lost the strength to support the 80,000 tonnes of gas processing equipment on top of the 488 metre-long vessel.

A National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) investigation report obtained by this masthead reveals a long list of safety concerns.

The regulator on December 23 ordered Shell not to recommence production until it demonstrated it could keep the Prelude safe if another power failure occurred.

Shell’s $24 billion floating liquified natural gas factory has suffered a series of safety and production problems since mid-2017, when it arrived at its moorings 475 kilometres from Broome from a South Korean shipyard.

The world’s largest vessel was to be the first of many deployed by the Anglo-Dutch oil and gas giant but has been in production for less than 12 months in 4½ years.

The most recent problems started on the evening of December 2, 2021, when a small fire triggered an emergency shutdown that depressurised the Prelude’s complex plant by sending vast quantities of gas to a flare tower to be burnt.

With no gas to generate power, the Prelude relied on three diesel backup units that all failed to work properly. The fire was quickly extinguished but for the next 2½ days Prelude’s multitude of complex systems to keep the vessel and its 293 crew safe only operated sporadically due to a lack of reliable power.

Crew reported temperatures as high as 45 degrees in their living quarters with humidity making it difficult to walk on the wet floors. Some crew worked 30-hour shifts to fix a cascade of technical problems.

Four of seven crew treated for heat exhaustion required intravenous drips. All have now recovered.

While the crew were troubled by heat below decks, steel that loses strength in low temperatures was getting colder and colder.

Steel structures supporting the deck sit in a water-filled cavity along the centre of the Prelude between vast 35 metre-wide insulated tanks that store LNG at minus 162 degrees. Without power there was no heating of the cavity to prevent the temperature of the steel falling to dangerously low levels.

NOPSEMA inspectors concluded the unreliable power produced “significantly higher than normal” risks on the Prelude, including “cooling of the substructure in the vicinity of the LNG tanks could lead to catastrophic failure if unmitigated”.

NOPSEMA found Shell “appropriately managed” the immediate risks to crew and when its inspectors visited a week later that the incident was under control. However, the regulator’s report listed numerous failures that made it harder for the crew to make the vessel safe.

Without power, key information was unavailable and the crew had to rely on memory. Some procedures to restart equipment were inadequate but by luck experts from suppliers happened to be onboard to assist. The emergency response team only had limited communication as radio equipment did not work properly.

A repeat of the December total power outage was “foreseeable and credible”, according to NOPSEMA, and there was potential for another emergency shutdown to exceed design limits of the flare system that handles the escaping gas.

The report found Shell had not yet determined the root causes of the initial fire or the subsequent power and equipment failures.

A NOPSEMA spokeswoman said the regulator was not considering a prosecution of Shell at this stage.

“An enforcement action has been issued which requires Shell to satisfy us that the facility is safe before production can recommence,” she said.

A Shell spokeswoman said the company had temporarily suspended production and was investigating the root cause of the incident. “We will continue to work methodically through the stages in the process to prepare for hydrocarbon restart with safety and stability foremost in mind,” she said.

To date the Prelude has not been a successful investment for Shell and its joint venture partners.

Shell never released Prelude’s cost, but it is understood to have risen from about $US12 billion to about $US17 billion.

Prelude was one of the main reasons Shell slashed more than $11 billion from the value of its global LNG business in mid-2020. Japan’s Inpex reduced the value of its 37 per cent stake in Prelude by a third, or $1.7 billion.

Shell’s global accounts released in early 2021 revealed it expects to never pay Australia’s Petroleum Resources Rent Tax for the gas extracted by the Prelude. The PRRT is based on profit that the Prelude is unlikely to achieve due to cost overruns, delays to start up and unreliable production.

Peter Milne covers business for WAtoday, The Age and The Sydney Morning Herald with a focus on WA energy, mining, construction and property.Connect via Twitter or email.

NUKE NEWS

Hunterston B nuclear power station closes after 46 years

07 January 2022

Electricity generation has ended at Scotland’s Hunterston B power station with the shutting down of Reactor 4, an advanced gas-cooled reactor (AGR). Operator EDF says the power station produced enough electricity during its lifetime to power every home in Scotland for nearly 31 years.

The Hunterston B plant (Image: EDF)

The plant, which came online for the first time in February 1976, was initially expected to run for 25 years but had its generating lifespan increased to more than 45 years. The station’s other unit, Reactor 3, was taken offline in November.

“The contribution Hunterston B power station has made to this country cannot be underestimated. As well as providing stable, well paid employment for thousands of people in the North Ayrshire area, it has produced almost 300TWh of zero-carbon electricity,” said station director, Paul Forrest.

“Everyone here is proud of what the station has accomplished. We will pause to reflect the end of generation but we are looking forward to the future. We don’t just switch off the power station, close the gates and walk away. It will take time to defuel and decommission the site and we will continue to need skilled people to do this.”

Both reactors were taken offline in 2018 after cracks in their graphite cores were discovered during routine inspections. The UK’s Office for Nuclear Regulation (ONR) gave approval to restart Reactor 4 in August 2020 and Reactor 3 the following month. However they were taken offline again in 2021 for further inspections of their graphite cores, with the ONR then giving permission for them to be switched on for about six months of operation each. 

The two reactors will now be prepared for defueling - where nuclear fuel is removed from the reactors and transported to Sellafield in northwest England for storage. That process is expected to take three years, with the site then due to be handed over by EDF to the UK’s Nuclear Decommissioning Authority for its subsidiary Magnox to continue with the decommissioning.

All seven of the UK’s advanced gas-cooled reactors are expected to end their operational lives this decade, meaning the UK “needs to move forward rapidly with plans for new reactor construction to expand the role of nuclear in its generation mix to meet its net-zero goals,” said Sama Bilbao y León, director general of World Nuclear Association.

"The current energy crisis, driven by sky-rocketing gas prices, shows that a reliance on imported fossil fuels is not only bad for the environment, it is also too risky for the economy. The UK needs to invest in new nuclear capacity to provide a reliable electricity supply at an affordable price," she added.

The Nuclear Industry Association - the trade association for the civil nuclear industry in the UK - says that over its lifespan, Hunterston B has saved 224 million tonnes of carbon dioxide emissions, worth GBP16.8 billion (USD22.7 billion) at current carbon prices.

The association’s Chief Executive, Tom Greatrex, said: “Hunterston B has shown the best of what nuclear can provide for Scotland - clean, reliable power to keep the lights on and save our planet, and long-term, skilled jobs, on which people can build a life and a family.”

The Hunterston A plant comprised two Magnox reactors capable of generating 180 MWe each. Hunterston A Reactor 1 began power generation in February 1964, with Reactor 2 following in June that year. Reactor 2 shut down on 31 December 1989 and Reactor 1 on 31 March 1990.

IAEA releases guide to stakeholder engagement

06 January 2022

The International Atomic Energy Agency (IAEA) has published its first "guide level" publication to support national efforts to engage with stakeholders throughout the life cycle of all nuclear facilities. To succeed, nuclear projects need to engage with all relevant stakeholders, including the public, and explaining nuclear energy, strengthening relationships and building trust with stakeholders is key to this, the Agency said.

(Image: IAEA)

Stakeholder Engagement in Nuclear Programmes provides theoretical and practical guidance on developing and implementing stakeholder engagement programmes and activities, and is part of a series of IAEA initiatives to support countries in this area. The guide aims to help communication experts, senior managers and other experts to establish and maintain a long-term stakeholder engagement strategy and activities covering the entire life cycle of nuclear facilities from uranium mining and new and operating reactors to non-electric applications, radioactive waste management and decommissioning.

"Stakeholders come in a variety of shapes and sizes," the IAEA said. "Some, such as regulators, are required by law to be involved in projects. Others include any individuals or groups who feel affected by an activity." Stakeholder engagement programmes can enable those individuals and groups to be involved and understand the basis for decisions, enhancing confidence and building trust in a project.

The publication builds on years of experience from working with governments and organisations, identifying good practices and crafting methodologies and approaches for effective stakeholder engagement, said IAEA Technical Officer Lisa Berthelot. "There is no engagement recipe, in the end, because each context is different, but this guide lays out the foundations for what is a crucial element in any nuclear programme," she added.

The new guide identifies five key principles for effective engagement: building trust, demonstrating accountability, exhibiting openness and transparency, practising early and frequent consultation; and communicating the benefits and risks of the nuclear technology. It covers the development of stakeholder engagement strategies and plans, including practical information such as stakeholder mapping; the roles and responsibilities of key nuclear organisations; and the engagement approaches for the different life cycle stages, each of which requires its own strategic approach.

Stakeholder engagement is of particular interest to newcomer countries seeking to introduce a new nuclear power programme and is one of the 19 nuclear infrastructure issues that make up the IAEA’s Milestones Approach, together with others such as nuclear safety and security, funding and financing and radioactive waste management. There are currently around 30 such newcomers, with Bangladesh and Turkey already constructing their first nuclear power plants, the Agency said.

The IAEA has provided newcomer countries with insightful capacity building support in stakeholder engagement for years," said Arda D Duran of the Turkish Ministry of Energy and Natural Resources. "With this publication, the IAEA will keep helping newcomer countries to improve our understanding and ability to effectively engage with stakeholders."

Nuclear icebreaker Sibir enters service

06 January 2022

Rosatom subsidiary Atomflot has accepted delivery of the Sibir, its newest nuclear-powered icebreaker. The twin-reactor vessel was officially handed over by the Baltic Shipyard which built it.

Three more vessels identical to Sibir are currently under construction (Image: Baltic Shipyard)

Sibir will join five other nuclear icebreakers in the Atomflot fleet, which also includes a nuclear-powered LASH carrier. Sibir's primary mission will be to maintain the passibility of the Northern Sea Route.

"We are confident that the efficient operation of these vessels will become a determining factor in sustainable development" of the route, said Atomflot CEO Mustafa Kashka.

Kashka officially took control of Sibir after signing an acceptance certificate with Aleksey Kadilov, the General Director of the Baltic Shipyard, on 24 December. Kadilov presented Kashka with the traditional bottleneck of the champagne used when Sibir was launched, as well as a portrait of Sibir's 'godmother', Tatyana Golikova, who is Deputy Prime Minister of Russia for Social Policy, Labour, Health and Pension Provision.

As the second 'Project 22220' icebreaker, Sibir follows the Arktika in service.

They use two RITM-200 reactors of 175 MWt each, which deliver 60 MW at the propellers via twin turbine generators and three motors. Three more vessels identical to the Sibir are under construction at the Baltic Shipyard - the Ural, Yakutia and Chukotka. 

Posiva applies to operate used fuel disposal facilities

05 January 2022

Finnish radioactive waste management company Posiva Oy has submitted its application for an operating licence for the used fuel encapsulation plant and final disposal facility currently under construction at Olkiluoto. The repository - the first in the world for used fuel - is expected to begin operations in the mid-2020s.

A rendering of the underground used fuel repository at Olkiluoto (Image: Posiva)

Posiva submitted the application to the Ministry of Economic Affairs and Employment (TEM) on 30 December. The company is applying for an operating licence for a period from March 2024 to the end of 2070.

Posiva's plan is for used fuel to be packed inside copper-steel canisters at an above-ground encapsulation plant, construction of which began in September 2019 and is scheduled to be completed in mid-2022. The fuel will then be placed in the bedrock, at a depth of 400-430 metres. The disposal system consists of a tightly sealed iron-copper canister, a bentonite buffer enclosing the canister, a tunnel backfilling material made of swellable clay, the seal structures of the tunnels and premises, and the enclosing rock.

According to the application, most of the used fuel of Posiva's owners - Teollisuuden Voima Oyj (TVO) and Fortum Power & Heat Oy - would be disposed of in the facility between 2024 and 2070. The disposal of all the used nuclear fuel of TVO and Fortum is expected to be completed by the late-2120s according to current nuclear power operation plans.

The ministry said it will organise a public consultation regarding the licence application at a later date. TEM will then request statements from several authorities, organisations and municipalities in the affected area, and provide citizens and communities with an opportunity to express their opinions. These statements and opinions, it said, will be considered when the operating licence application is processed.

TEM has requested a statement on the safety of the encapsulation plant and disposal facility from the Radiation and Nuclear Safety Authority (STUK). STUK will perform an evaluation to ensure that the encapsulation plant and disposal facility have been built according to plans, that the nuclear facility as a whole can be used safely, and that the personnel of the nuclear facility have been trained to operate the facility safely. STUK will supervise the operation and maintenance of the encapsulation plant and disposal facility throughout their service life. As an important part of its statement, STUK will evaluate the long-term safety of the facility.

"The safety case compiled for Posiva's application for the operating licence is the outcome of more than 40 years of research and demonstrates the safety of final disposal," said Tiina Jalonen, Posiva's senior vice president of development. "The review procedure of the operating licence application is estimated to proceed so that Posiva will be in a position to start the final disposal operation in mid-2020s."

The site for Posiva's repository was selected in 2000. The Finnish parliament approved the decision-in-principle on the repository project the following year. Posiva submitted its construction licence application to the Ministry of Employment and the Economy in December 2013. The company studied the rock at Olkiluoto and prepared its licence application using results from the Onkalo underground laboratory, which is being expanded to form the basis of the repository.

The government granted a construction licence for the project in November 2015 and construction work on the repository started in December 2016.

The Onkalo geological repository will be the first in the world for used nuclear fuel. A similar repository is planned at Forsmark in Sweden.

"The work carried out for several decades to demonstrate long-term safety and develop the final disposal facility concept Onkalo to suit the conditions of Olkiluoto has now been finalised and we can concentrate on the installation of equipment in the encapsulation plant and the final disposal repository, commissioning of the facility and preparations for operational activities," said Posiva CEO and President Janne Mokka.

Researched and written by World Nuclear News

Feds deny Oklo’s application to build an advanced nuclear reactor in Idaho

PUBLISHED FRI, JAN 7 2022
Catherine Clifford@IN/CATCLIFFORD/@CATCLIFFORD

KEY POINTS

In a decision released Thursday, the Nuclear Regulatory Commission denied the application from Silicon Valley nuclear innovation company, Oklo, to build and operate its advanced nuclear reactor, called Aurora, in Idaho.

Federal regulators denied the application due to “significant information gaps in its description of Aurora’s potential accidents as well as its classification of safety systems and components,” NRC Director of the Office of Nuclear Reactor Regulation Andrea Veil, said.

The decision was issued without judgement and Oklo “is free to submit a complete application in the future,” the NRC said.


An artist rendering of Oklo’s Aurora powerhouse
Image credit: Gensler

Federal regulators have denied the application from Silicon Valley nuclear power start-up Oklo to build and operate its advanced nuclear reactor, dubbed Aurora, in Idaho.

The Nuclear Regulatory Commission filed the decision on Thursday and cited lack of sufficient information about potential accidents and safety measures. Oklo may re-apply.

“Oklo’s application continues to contain significant information gaps in its description of Aurora’s potential accidents as well as its classification of safety systems and components,” said the NRC’s Andrea Veil, in a written statement.

“These gaps prevent further review activities. We are prepared to re-engage with Oklo if they submit a revised application that provides the information we need for a thorough and timely review,” Veil said.

Oklo’s plan is to build miniature nuclear reactors that are much smaller and cheaper than conventional nuclear reactors. Conventional reactors require massive construction projects which are often beleaguered by construction timeline and budget overruns, like the Vogtle plant in Georgia. Oklo’s mini reactors are supposed to be powered by the waste of conventional nuclear reactors and housed in aesthetically pleasing A-frame structures. The company has raised more than $25 million from venture investors to pursue this plan, according to Pitchbook.

The Idaho National Laboratory had announced it would grant Oklo access to used nuclear waste to develop and demonstrate its technology.

The NRC’s decision surprised Oklo, said co-founder and Chief Operating Officer Caroline Cochran.

“It was pretty much as much of a surprise to us as anyone else. We weren’t given any heads up at all before it basically went public yesterday,” Cochran told CNBC. “We really didn’t have any indication that this was coming.”

Cochran launched Oklo in 2013 with her husband Jacob DeWitte, and they began having conversations with the NRC in 2016. In June 2020, Oklo’s application to build an advanced reactor was accepted for review by the commission.

Cochran said in their many meetings with the NRC, they have aimed to provide as much information as they were asked for.

But the NRC pointed CNBC to a letter it wrote to DeWitte stating that the regulators did not get the information they requested.

“Oklo has repeatedly failed to provide substantive information in response to NRC staff requests for additional information (RAIs) on the maximum credible accident (MCA) for the Aurora design, the safety classification of structures, systems, and components (SSCs), and other issues needed for the NRC staff to establish a schedule and complete its technical review,” the letter said.

An MCA is a worse case scenario, explained Scott Burnell, a public affairs officer at the NRC. The agency analyzes an accident “resulting in the greatest radioactive release” possible from a event, hazard or sequence of events.

Cochran said she has been encouraged by some conversations she and the Oklo team have had with members of the NRC since the decision was made public.

“After chatting with some folks with the NRC yesterday after it went public, they made pretty clear that there’s a pathway for us to provide more information again, and just continue the process,” Cochran said.

The NRC did say it has made the decision “without prejudice” and that Oklo “is free to submit a complete application in the future.”

A disappointment to nuclear advocates

The Oklo decision from regulators was a disappointment to nuclear industry stakeholders. The nuclear industry has been in a pivotal moment of reinvention, working to move past its reputation tarnished by catastrophic accidents, and reinvent itself as a solution to decarbonization efforts which have become a priority in efforts to combat climate change.

“Advanced nuclear technologies, including the Aurora, are being built to help overcome our greatest climate challenges and essential to reaching the nation’s climate goals,” said Doug True, the Chief Nuclear Officer at the industry’s trade group, the Nuclear Energy Institute.

The NRC needs to update its licensing procedures, according to True. “The next generation of nuclear technologies are being designed with inherent safety features and will require the NRC to modernize their approach in licensing the carbon-free nuclear reactors of the future,” he said.

Alex Gilbert, a project manager for nuclear power think tank the Nuclear Innovation Alliance, also told CNBC the decision was a disappointment and a sign of out dated regulatory processes.

“Advanced reactors are expected to be safer than any reactors to date and should be able to meet NRC’s standards,” Gilbert said.

A regulatory overhaul process is in its very early stages, Gilbert said. “This work is ongoing and requires work from industry, NRC, and civil society to ensure efficient licensing,” Gilbert told CNBC.

Fossil Gas No Longer Needed As Bridge To Clean Energy Future

Natural gas plant. Image by Loïc Manegarium from Pexels.

By Laurie Stone
RMI

As coal plants shut down across the United States, there is a pervasive belief that gas is the necessary “bridge” to a low-carbon grid. As of late 2021, utilities and other investors are anticipating investing more than $50 billion in new gas power plants over the next decade. But, in reality, we no longer need these gas plants to tide us over until renewables are ready or affordable. Renewables are here now, and are often cheaper than gas.

In fact, clean energy portfolios — combinations of renewable energy, efficiency, demand response, and battery storage — are increasingly economical compared with new gas plants. A recent RMI report found that clean energy portfolios are a cheaper option than more than 80 percent of gas plants proposed to enter service by 2030. At least 70 GW of proposed gas plants could be economically avoided with cleaner alternatives, saving $22 billion and 873 million metric tons of CO2 over project lifetimes. This is the equivalent of taking more than 9 million vehicles off the road each year.


Already, more than half of gas plants proposed to come online in the past two years have been canceled before construction began.

For example, in New Mexico, the Public Service Company (PNM) is planning to retire the coal-powered San Juan Generating Station in 2022. To replace capacity, PNM proposed a 280 MW gas plant, the Piñon Energy Center, along with solar and storage projects. However, stakeholders pushed back on the plan, and in July 2020, the commission approved an alternate 100 percent renewable and storage replacement for San Juan based on costs, economic development, and New Mexico energy law.

And in Maryland, the Mattawoman Generating Station — a 990 MW gas plant — was approved in 2015 in a majority-Black community of Prince George’s County. However, due to economics (clean energy portfolios became cheaper than the proposed gas plant in 2018), a federal civil rights complaint, and pipeline cancellations, the project was declared no longer feasible, and was canceled in January 2021.

Replacing all of the proposed gas plants with clean, renewable power also has other benefits, based on RMI’s report. It creates 20 percent more job-years, mostly in construction and manufacturing, and would prevent $1.6 billion to $3.7 billion in health impacts each year​. And many of these job and health impacts will be found in low-income communities and communities of color.



Today, even more risks are emerging making gas plants an unsuitable risk. Declining renewable energy costs, rising gas prices, pollution-regulating policies, and more all threaten the viability of new gas projects.

As utilities and investors look to invest more than $50 billion in new gas plants over the next decade, we must remember that the myth that gas is needed as a bridge fuel to a clean energy future is just that, a myth. Fortunately, leading examples from across the country demonstrate that this decade is the time to invest in renewables — for our economy, our health, and our communities.

© 2022 Rocky Mountain Institute. Published with permission. Originally posted on RMI Outlet.

USA

First, end ratepayer subsidies for natural gas expansion. Then study the future of gas in Connecticut


CT VIEWPOINTS
by PETER MILMAN
JANUARY 6, 2022


PHOTO BY ANTHROVIEW LICENSED UNDER CC BY-NC 2.0

Gas line installation.

You may be surprised to learn that Connecticut natural gas ratepayers are subsidizing the expansion of the natural gas system. Yes, in 2021 as we are trying to stop burning fossil fuels that contribute to climate change, ratepayers’ funds are being used to increase the number of natural gas customers.

The System Expansion Program (SEP) began in 2013 when the Malloy administration and legislature directed the Public Utilities Regulatory Authority (PURA) to develop a ten-year plan to encourage households that used heating oil to convert to natural gas. At the time, it was believed that burning gas instead of oil would reduce emissions (though it turns out that between combustion emissions and methane leaks, gas is not a good climate solution). The conversion program required ratepayer investments in gas pipelines and infrastructure that will lock in the use of natural gas for decades. Meanwhile, the supposed cost benefits to customers have disappeared as gas prices have increased.

In 2020, PURA recognized that the program was not working as intended and asked its office of Education, Outreach, and Enforcement (EOE) to review the program. In a victory for common sense and a recognition of the facts, EOE’s review concluded that “the program should ‘downsize’ immediately and the System Expansion Program should end at the 10-year mark.”

Among other findings, EOE recognized that:

The climate justification for the program has diminished: State policy is relying far less now than in 2013 on natural gas as a tool to meet the state’s Global Warming Solutions Act emissions goals, and EOE expects the deemphasis on natural gas to continue.

The program is unfair to ratepayers: Diverting millions of ratepayer dollars into the program instead of lowering customer bills is “a significant change in the treatment of customers that must be addressed.”

The evaluation process has been flawed: The criteria for assessing the program were, “far too liberal to provide any meaningful assessment of the program.”

The program does not meet current needs and priorities: The program is designed in a way that, “does not adequately account for market trends, and cannot respond rapidly to negative trends,” such as changes in the difference between gas and oil prices and increased concern with emissions.

Now that EOE has issued its report on the System Expansion Program, it is up to PURA to enact the recommendations.

There is another problem with the gas expansion program, namely the way it has been marketed to potential new gas customers. In August 2021, Connecticut’s Attorney General and Office of Consumer Counsel filed a petition to PURA calling for an investigation into Eversource’s gas expansion marketing tactics. According to the Hartford Courant, a South Windsor resident received plainly deceptive materials from Eversource designed to pressure people into signing up for the gas expansion program. “These mailers and high-pressure marketing tactics are nothing short of alarming,” Attorney General William Tong said. PURA agreed to investigate and on Dec. 17, 2021 issued a Notice of Violation against Eversource, along with a $1,797,000 civil penalty.

Connecticut is not the only state to be increasingly wary of investing more in natural gas infrastructure. As a recent RMI study, Overextended: It’s Time to Rethink Subsidized Gas Line Extensions, notes: “A new natural gas customer is added to the system every minute in the United States, and existing gas customers are covering their construction costs through subsidies known as line extension allowances. Each year, these extensions of gas service enable utilities to pass hundreds of millions of dollars in costs to existing customers while expanding the fossil fuel system for decades to come … Utility regulators in every state should reform line extension allowances to eliminate subsidies for gas, align with state climate policies, and reduce the financial burden on existing gas customers.”

Among the states beginning to act is Massachusetts, where the advisory council that oversees Mass Save, the state’s energy efficiency program, is seriously questioning the continuation of incentives for the conversion of home heating systems from oil to gas. Critics of Mass Save point out that heating with natural gas will still produce large amounts of greenhouse gas emissions and lock in the emissions for decades. And who designed the Mass Save program? Gas utilities, among others.


Meanwhile the State of Maryland’s People’s Counsel recently wrote that Maryland gas utilities are continuing to expand their distribution infrastructure despite the growing danger of climate change. Why? Because it benefits shareholders. But the problem goes deeper than that. As Maryland and other states transition away from fossil fuels, ratepayers will still be paying for the investments gas companies are making right now. The question is, who will bear the unrecovered costs of obsolete infrastructure, ratepayers or shareholders? The question has not been answered in Maryland, but given the efforts of gas utilities to expand, it is reasonable to assume that they are counting on ratepayers.

In Connecticut, we need to ask the following question: who will pay for gas infrastructure that becomes obsolete as the state transitions away from burning fossil fuels?

One of the best ways to address the question would be to open a Future of Gas docket at PURA, similar to what the Department of Public Utilities did in Massachusetts. Initiated by the Massachusetts Attorney General’s office, Docket 20-80 is considering what an orderly decrease in the use of natural gas for heating would look like, what alternatives exist for heating buildings, how much ratepayer money should utilities spend on repairing and replacing leaking pipelines that may be phased out, and how should remaining gas ratepayers be protected from the costs of maintaining a distribution system that has fewer and fewer customers.

Gov. Ned Lamont’s recent Executive Order No. 21-3 suggests that Connecticut needs to look squarely at the future of natural gas. “GHG emissions from buildings have increased instead of being on track to achieve the roughly one-third reduction in such emissions needed to achieve the GWSA 2030 target, [and] a new Comprehensive Energy Strategy is needed that identifies the best clean, affordable and resilient heating and cooling options for buildings, and reconsiders the natural gas expansion program recommended in the 2013 Comprehensive Energy Strategy.”

Governor, push to completely end the current natural gas expansion program that is expensive, unfair to ratepayers, and inconsistent with the state’s greenhouse gas emission reduction goals. Then join with Attorney General Tong to request that PURA open a docket that explores the future of gas. Ratepayers, voters, and future generations will thank you.

Peter Millman is a member of Beyond Gas CT, a coalition that includes the Conservation Law Foundation, Sierra Club CT, Acadia Center, The Nature Conservancy, Save the Sound, CT Citizen Action Group, and People’s Action for Clean Energy.

Breakthrough Technology Converts Captured CO2 Into Sustainable Aviation Fuel

6 Jan 2022, ·

 

by Otilia Drăgan 

Until electric aircraft and hydrogen fuel cell systems can become the norm, aviation needs a quick, affordable solution that can lower as much as possible the negative environmental impact. The U.S. government is actively supporting initiatives for sustainable aviation fuel (SAF) development. One of the most innovative ones claims to turn CO2 and green hydrogen into SAF.

 6 photos

Johnson Matthey is not an aviation specialist, but a company that focuses on sustainable technology across multiple industry sectors. Its latest launch is a technology meant to capture carbon dioxide and convert into drop-in fuel for aircraft, with the help of green hydrogen. Under the simple name of Hycogen lies a complex process, based on “Reverse Water Gas Shift technology.”

Basically, green hydrogen and CO2 are converted it into carbon monoxide (CO), through a catalyzed process. The carbon monoxide is then mixed with more hydrogen, becoming synthesis gas (syngas), a basic component for fuel production. Together with an additional technology (developed in partnership with bp), Hycogen can transform up to 95% of CO2 into synthetic crude oil, which can then be further processed into SAF or other types of sustainable fuel.

By combining these two technologies, Johnson Matthey claims to have developed a scalable, cost-effective solution for SAF production. It can be deployed as a small-scale project, using hydrogen from a single electrolyser, or a large-scale version using multiple, bigger electrolysis modules.

In 2021, Hycogen’s developer was part of one of the pioneering projects, led by Boeing and United Airlines. Back in December, a commercial aircraft with more than 100 passengers onboard conducted a pioneering flight using SAF. The Boeing 737 MAX 8 flew from Chicago to Washington D.C., with 500 gallons (1,892 liters) of 100% SAF in one of its engines, and an equal quantity of conventional fuel in the other engine. That’s because current regulations only allow a maximum of 50% SAF for regular flights.

In fact, ramping up SAF production, and making it readily available, is one of the most important factors in achieving 100% SAF-powered flights in the near future. Hycogen promises to make that happen faster.