LONDON RECONNECTION
THE SECOND COMING OF HYDROGEN? LONDON’S HYDROGEN BUSES

By Long Branch Mike
JAN 2021

Despite impressive advances, bus battery technology is still not optimal – poor range, and reduced energy storage in cold weather. So to avoid putting all their clean energy buses in one basket, TfL has consistently been evaluating hydrogen fuel cell buses.

Long before the first official determination of pollution as the cause of death of a 9 year old London girl shone the spotlight on the impact of pollution on respiratory systems, London had been at the vanguard of advancing clean transport technologies.

Additionally, a recent series of troubling London air pollution reports, such as the levels of nitrogen dioxide (NO2) and other toxic volatile organic chemicals (VOC), are shedding new light on the extent of inhaled toxins and carcinogens on the Capital’s streets. Diesel bus exhaust results in buildup of NOx (NO + NO2) inside bus terminals.

Modelled 2020 annual NO2 pollution levels in Marylebone. MappingLondon

The sudden reduction of cars, trucks, and buses in March 2020 due to the onset of the pandemic just as quickly resulted in clear skies over major cities worldwide. Unfortunately, traffic quickly returned, and the startling view of crystal clear air that shouldn’t be easily forgotten, has been forgotten. We note the recent realisation of the impact of brake and tyre particulates on air quality and breathing, but address only zero emission buses in this article.

TFL‘S ZERO EMISSION BUSES

To tackle the capital’s air quality crisis believed to be largely caused by diesel engines, recent Mayors and TfL had initiated a number of new clean air transport initiatives. We recently covered battery buses and ULEZ’s in On The Buses: Fares, Fumes and Finances, and now look at the role that hydrogen fuel cell (HFC) buses are starting to play.

We had first looked at London’s hydrogen buses in 2014 in Asphalt and Battery: The future of the London Bus (Part 2):

When you are responsible for a fleet of over eight thousand diesel buses it is only right and proper that you investigate alternative options and this TfL has done. At one stage hydrogen looked very promising. In the past few years TfL have experimented off and on with hydrogen buses on route RV1 but, whilst the latest buses are still in service, there does not seem to have been any effort made to extend them beyond this one route. This is probably because they are very expensive indeed. It is also the case that, although hydrogen can be seen as a solution for getting rid of tailpipe emission at the point of use, it does not solve any energy issues because more energy in the form of electricity is required to extract the hydrogen from water than can be obtained from burning it as a fuel (and creating water). As such, hydrogen is merely an alternative to the battery.

There are of course various other gases apart from hydrogen that can be burned. The problem with these are that they are still hydrocarbons but in gaseous rather than liquid form. The main attraction of these fuels for taxis and other vehicles is that they don’t attract fuel duty – something that bus operators don’t pay anyway.

Transport in London has had a long history of innovation, from the pioneering Metropolitan Line in 1863, the first electrically powered Underground line in 1890, to the world’s first automated underground line in 1968. Buses have not been exempt from technological advancement, with London at the forefront of bus technologies and designs such as the original Routemaster.

LONDON’S FIRST HYDROGEN BUS ROUTE – RV1

TfL’s first foray into hydrogen power started on Riverside bus route RV1 in 2002. The route connected Central London with South Bank attractions, including the Royal Festival Hall, National Theatre, London Eye, and Tate Modern, and operated between Covent Garden via Tower Gateway station, Waterloo, London Bridge station and Tower Bridge, serving many streets that previously had not been served by buses. The short 6 mile route length, dense central London routing and high visibility to tourists meant that RV1 was an ideal route to trial and fly the environmentally friendly bus flag – the only emissions of hydrogen vehicles being oxygen and water.

A hydrogen fuel cell bus on RV1

The hydrogen buses serving on this route were initially three hydrogen fuel cell (HFC) powered Mercedes-Benz Citaros operated between 2004 and 2010. Some of these buses were also trialled on route 25 in 2009. This small fleet allowed TfL to compare their efficiency directly against diesel powered Citaros. However, due to a lack of hydrogen capacity in those buses, their limited range only allowed operation in the mornings and early afternoon. Whilst the RV route prefix was part of Riverside branding, there was cynical speculation that it also meant Research Vehicle.

Mercedes-Benz Citaro in 2004. Walthamstow Writer


The Citaros were removed from RV1 service in 2010, replaced by eight new Wrightbus Pulsar 2 hydrogen-powered VDL SB200 bodied single-decker buses purchased by First London, which were operated on the route until 2013. Two Van Hool single decker hydrogen fuel cell A330FCs replaced the Alexander Dennis Enviro 200 Darts on route RV1 in January 2018, allowing a full hydrogen fleet to operate for the first time.

Hydrogen tanks atop RV1 bus at Tower Gateway

Some of the RV1 hydrogen buses have apparently had poor ride quality and high interior noise levels, equivalent to a diesel bus. As a comparison, battery electric buses are considered far superior in these respects.

MASSIVE CUTBACK IN RV1 BUS FREQUENCY AFTER LONDON BRIDGE REBUILD

Part of route RV1’s continued raison d’être was the Thameslink Programme London Bridge rebuild. The biggest capacity gap it was helping to fill started to fall off post May 2016 (when the bus route ridership halved), then in August 2017 with the station works phasing changes. With the Blackfriars Southern entrance opening, combined with renewed peak Thameslink service from London Bridge, the 2019 RV1 ridership dropped to about 10% of what it once was.

It was thus no surprise that route RV1 was discontinued on 15 June 2019. Diesel bus route 343 was then extended from Aldgate to Tower Gateway to replace the service between London Bridge and Tower Gateway. The Wrightbus hydrogen single deckers were moved to route 444 and the Van Hools to storage.

To develop a dedicated hydrogen source, TfL are coordinating with Project Cavendish, a collaborative feasibility project between Southern Gas Networks (SGN), National Grid, and Cadent. This project is evaluating the potential of using the Isle of Grain’s existing infrastructure to supply hydrogen to London & the South East, including hydrogen generation by steam methane reforming (SMR), storage, and transport. Sixty kilometres east of London, the Isle of Grain hosts the National Grid’s Grain liquid natural gas (LNG) terminal, as well as a number of gas shipping terminals, gas blending facilities, and considerable natural gas storage.

SMR is the traditional hydrogen generation technology, also called ‘gray hydrogen’ for its dirty fossil fuel production method, which releases carbon into the atmosphere during processing. However, this process can be rectified with CO₂ capture, to a low-carbon standard to make ‘blue hydrogen’. This is the hydrogen that TfL is hoping to use.

NEXT GENERATION HYDROGEN BUSES

In 2018 London once again took a technological jump on transport innovation – TfL commissioned two hydrogen fuel cell double deckers – a world first. One is a conversion of a former hybrid bus demonstration vehicle, and the second is a brand new double decker Streetdeck FCEV (fuel cell electric vehicle), again from Wrightbus, powered by Ballard hydrogen fuel cells. They are due to be trialled by Tower Transit from Lea Interchange garage.

THE MAYOR’S IMPERATIVE

Mayor Sadiq Khan has made tackling the public health issues caused by air pollution one of his major initiatives. Toxic air is a threat to all Londoners’ health, especially children, the elderly, and those with lung and heart problems. Scientific studies are starting to show that high values of air pollutants correlate with more severe COVID symptoms.

Under his initiative, the 2019 Mayoral Plan set the goal of 2,000 zero-emission London buses by 2025, and a full zero-emission bus fleet by 2037 at the latest. When TfL introduced the ten Low Emission Bus Zones and the world’s first Ultra Low Emission Zone (ULEZ) in April 2019, harmful nitrous oxides (NOx) emissions were reduced by 90% on some of the capital’s busiest roads in only a few months.

TfL then announced in May 2019 that it will introduce 20 of the new Wrightbus hydrogen buses into service in 2020 on London bus routes 245, 7 and N7. All of the buses in the ULEZ, and 75% of the entire bus fleet, already meet these standards. The plan was to have the entire TfL bus fleet meet the standards by October 2020, making the entire city a Low Emission Bus Zone. Unfortunately, one of responses to the coronavirus pandemic was to temporarily remove the ULEZ restrictions.

London ULEZ in 2014

TfL’s currently operates over 200 zero emission buses, Europe’s largest electric fleet, mostly battery powered. However, hydrogen buses can store more energy on board than equivalent battery buses, meaning they can be deployed on longer routes. Hydrogen buses now only need be refuelled for five minutes once a day, making them much quicker to refuel than to recharge battery buses.

In June 2020 Ryse, a hydrogen generation company, and Wrightbus, the manufacturer of London’s New Routemasters, won the 10-year contract to deliver these buses in 2020. Once the new Wrightbus hydrogen bus squadron is in service, London will have the largest zero-emission bus fleet in Europe. We know what you’re thinking – so hold that thought.

Hyundai vs Tesla: Hyundai races to produce electric cars as Tesla takes off

No traditional automaker has been successful yet in catching up with Tesla, which retains an edge in battery and software technology

REUTERS
Published Jul 28, 2021

Hydrogen champion Hyundai races to electric as Tesla takes off. (AFP Photo)


SEOUL: Hyundai Motor Co, an early backer of hydrogen cars, has watched the electric rise of Tesla, including on its home turf. Now’s it’s going on the offensive in the battery-powered market led by its U.S. rival.

The South Korean company plans to introduce two production lines dedicated to electrics vehicles (EVs), one next year and another in 2024, according to an internal union newsletter seen by Reuters.

Euisun Chung, leader of the Hyundai Motor Group conglomerate that also includes Kia Motors, has also held a series of meetings since May with his counterparts at Samsung, LG and SK Group, which make batteries and electronic parts.

The purpose of the talks, which were publicly announced, was for Hyundai to try to secure batteries at a time of tight supply as the race for EVs intensifies, according to several industry sources. Those manufacturers also supply the likes of Tesla, Volkswagen and GM.

Hyundai told Reuters it was collaborating with Korean battery suppliers “to scale up” its electric car production efficiently. It declined to comment on any plans to introduce dedicated production lines.

Samsung, LG and SK declined to comment.

The moves indicate the carmaker is moving aggressively to expand its electric capacity, days after Chung announced on July 14 that Hyundai Motor Group aimed to sell 1 million battery EVs a year and grab a global market share of over 10% by 2025.

There’s some way to go; Hyundai Motor Group sold 86,434 battery EVs last year, according to data from industry consultant LMC Automotive. That was above the 73,278 sold by Volkswagen Group but behind the 367,500 delivered by Tesla.

Hyundai, the world’s No.5 automaker together with Kia Motors, said its agility allowed it to lead the charge into EVs. “We are certain Hyundai is never going to fall behind,” it added.

NO KODAK MOMENT

A senior Hyundai insider, who declined to be identified because of the sensitivity of the issue, said the company had not been concerned about Tesla when the Silicon Valley company was producing high-end cars.

But it became more worried when Tesla brought out a cheaper Model 3 in 2017, according to the insider who described it as a “strategic victory”.

No traditional automaker has been successful yet in catching up with Tesla, which retains an edge in battery and software technology.

Hyundai could also face a roadblock from its powerful union, which is worried about job security as EVs require fewer components and workers than gasoline vehicles; at Hyundai, this is partly because the automaker makes a number of key components for conventional cars in-house, while many EV parts are outsourced at present.

The union is pushing for the company to assemble key EV components, like battery packs and motors, in-house to offset any reduction in workforce.

“We are not opposed to EV business. Kodak went bankrupt because it stuck to film even as the industry was shifting to digital photography,” union spokesman Kwon Oh-kook told Reuters.

“We just want to protect the jobs of our members,” he said.

Hyundai said automakers and unions needed to accelerate change to remain viable in the long term.

HYDROGEN V ELECTRIC

Back in 2010, Hyundai Motor Co made 230 electric cars for the government, but they ended up being mothballed at a research center outside Seoul due to a lack of charging infrastructure, according to Lee Hyun-soon, R&D chief at the time.

In a 2014 book Lee, who developed South Korea’s first gasoline engines, said such electric vehicles were “not realistic”, also citing high battery costs, and that hydrogen cars - a rival clean technology - offered a “bright” future.

Along with Toyota and Nikola, Hyundai was one of a few automakers to have backed hydrogen cars. It launched the industry’s first mass-produced hydrogen car, Tucson Fuel Cell, in 2013 and the NEXO in 2018.

However the technology has not taken off; 7,707 hydrogen fuel cell cars were sold globally last year, compared with 1.68 million battery EVs, according to LMC Automotive.

In Hyundai’s home market, Tesla had its best month in June, with its Model 3 beating Hyundai’s Kona EV, as well as premium models from BMW and Audi.

“Hyundai did not expect Tesla to dominate the EV market so quickly,” another person familiar with the company’s thinking told Reuters.

Hyundai Motor Co has a market capitalization of about 25.3 trillion won ($21.2 billion) - less than a tenth of that of Tesla, now the world’s most valuable automaker.

While Hyundai promotes its hydrogen cars with K-pop boyband BTS, it only plans to introduce up to two hydrogen models by 2025, and 23 battery-powered models.

Peter Hasenkamp, vice president at electric startup Lucid, who previously worked at Tesla and Ford, said established carmakers faced historical “inertia” to make the EV transition.

“Part of the reason we’re based in Silicon Valley is to leverage both software and electrical engineering expertise,” Hasenkamp told Reuters.

“You’ve got a couple of generations for the big car companies to learn really how to do this well. It is a lot harder than they thought it was.”

Linde and Hyosung Partner to Develop Hydrogen Infrastructure in South Korea

GUILFORD, UK / ACCESSWIRE / February 4, 2021 / Linde (NYSE: LIN; FWB: LIN) announced today that it has partnered with Hyosung Corporation (Hyosung), one of South Korea's largest industrial conglomerates, to build, own and operate extensive new liquid hydrogen infrastructure in South Korea. This robust hydrogen network will support the country's ambitious decarbonization agenda to achieve net zero emissions by 2050.

On behalf of the joint venture, Linde will build and operate Asia's largest liquid hydrogen facility. With a capacity of over 30 tons per day, this facility will process enough hydrogen to fuel 100,000 cars and save up to 130,000 tons of carbon dioxide tailpipe emissions each year. Based in Ulsan, the plants will use Linde's proprietary hydrogen liquefaction technology which is currently used to produce approximately half of the world's liquid hydrogen. The first phase of the project is expected to start operations in 2023.

Under the partnership, Linde will sell and distribute the liquid hydrogen produced at Ulsan to the growing mobility market in South Korea. To enable this, the joint venture will build, own and operate a nationwide network of hydrogen refueling stations.


"Hydrogen has emerged as a key enabler of the global energy transition to meet the decarbonization goals set out in the Paris Agreement," said B.S. Sung, President of Linde Korea. "The South Korean government has set ambitious targets for hydrogen-powered fuel cell vehicles and the widespread, reliable availability of liquid hydrogen will be instrumental to achieving these targets. We are excited to partner with Hyosung to develop the hydrogen supply chain in South Korea."

"Our partnership with Linde is a cornerstone of the development of South Korea's national hydrogen economy and will advance the entire liquid hydrogen value chain across the country, from production and distribution to sales and services," said Cho Hyun-Joon, Chairman of Hyosung Group. "We look forward to working with Linde to further reinforce and strengthen Hyosung as a leader in the global hydrogen energy transition."

Linde is a global leader in the production, processing, storage and distribution of hydrogen. It has the largest liquid hydrogen capacity and distribution system in the world. The company also operates the world's first high-purity hydrogen storage cavern, coupled with an unrivaled pipeline network of approximately 1,000 kilometers to reliably supply its customers. Linde is at the forefront in the transition to clean hydrogen and has installed close to 200 hydrogen fueling stations and 80 hydrogen electrolysis plants worldwide. The company offers the latest electrolysis technology through its joint venture ITM Linde Electrolysis GmbH.

About Linde

Linde is a leading global industrial gases and engineering company with 2019 sales of $28 billion (€25 billion). We live our mission of making our world more productive every day by providing high-quality solutions, technologies and services which are making our customers more successful and helping to sustain and protect our planet.

The company serves a variety of end markets including chemicals & refining, food & beverage, electronics, healthcare, manufacturing and primary metals. Linde's industrial gases are used in countless applications, from life-saving oxygen for hospitals to high-purity & specialty gases for electronics manufacturing, hydrogen for clean fuels and much more. Linde also delivers state-of-the-art gas processing solutions to support customer expansion, efficiency improvements and emissions reductions.

For more information about the company and its products and services, please visit www.linde.com.

View source version on accesswire.com:
https://www.accesswire.com/627870/Linde-and-Hyosung-Partner-to-Develop-Hydrogen-Infrastructure-in-South-Korea

IEA’s ‘Future of Hydrogen’ report charts a way through fossil-fuelled isles


The G20 meeting of environment and energy ministers in Karuizawa, Japan on the weekend came out largely in favour of adopting lower-emissions energy technologies: that means cleaner coal as well as driving development of solar- and wind-powered

green hydrogen.

JUNE 17, 2019 NATALIE FILATOFF


Image: Siemens


An International Energy Agency report on The Future of Hydrogen was released at the G20 Ministerial Meeting on Energy Transitions and Global Environment for Sustainable Growth, held in Karuizawa in Japan on the weekend. It offers a positive outlook for the development of green hydrogen using renewable energy sources such as solar.

The report was accompanied by Japan’s Minister for Economy, Trade and Industry, Hiroshige Seko restating his country’s commitment to clean-coal technologies, such as carbon capture and storage (CCS) and carbon capture and utilisation (CCU). Seko said, “It’s inevitable that in some countries, coal thermal has to be used. … Japan’s coal thermal power, compared with conventional coal thermal power, has fewer carbon dioxide emissions and we should provide and implement it in developing countries.”

Was it in the same spirit that Minister Seko signed a Memorandum of Cooperation with Angus Taylor, Australia’s Minister for Energy and Emissions Reduction to promote trade and investment, support research and innovation and tackle energy security, reliability and affordability challenges?

Hydrogen, black or green?

There’s no doubt that development of hydrogen technologies is high on both countries’ energy agendas. Japan’s Basic Hydrogen Strategy has been devised and revised under various names since 2014, with the latest update formulated in March this year. Among many key points, it seeks to slash the cost of hydrogen to equal the cost of LNG in Japan, and has set targets for fuel-cell uptake in several heavy-vehicle categories by 2030. As chair of the G20 during 2019, Japan also commissioned the The Future of Hydrogen report to help shape the agenda of G20 talks.

Australian initiatives include the Federal Government’s $25 million investment in clean-hydrogen research and development through the Australian Renewable Energy Agency (ARENA), and also $50 million (matched by a further $50 million from the Victorian Government) in a controversial coal-to-hydrogen project, in which Japan has an interest, in Victoria’s La Trobe Valley.

Earlier this month, during an Australian Science Media Centre (AusSMC) briefing on hydrogen, Dr Daniel Roberts, Leader of the CSIRO Hydrogen Energy Systems Future Science Platform said, “Hydrogen is already made in very large quantities all around the world from gas and from coal, and those pathways will play a role in providing the transition to low-carbon hydrogen a bit of scale at the outset.”

Currently, according to the IEA report on The Future of Hydrogen, fossil-fuelled production of hydrogen is responsible for “annual CO2 emissions equivalent to those of Indonesia and the United Kingdom combined”. The report says, “Harnessing this existing scale on the way to a clean energy future requires both the capture of CO2 from hydrogen production from fossil fuels and greater supplies of hydrogen from clean electricity.”

The solar pv-powered beacon

It cites the recent success of solar PV, wind, batteries and electric vehicles in showing that countries can use policy and support innovation “to build global clean industries”.

Although the cost of producing hydrogen from low-carbon energy is still a barrier to widespread uptake of green hydrogen, IEA analysis shows that the cost of producing hydrogen from renewable electricity could fall around 30% by 2030 as a result of declining costs of renewables and scaling up of hydrogen production. The report also suggests that, “Fuel cells, refuelling equipment and electrolysers (which produce hydrogen from electricity and water) can all benefit from mass manufacturing.”

At the AusSMC Hydrogen Briefing Professor Douglas MacFarlane, Leader of the Energy Program in the ARC Centre of Excellence for Electromaterials Science was confident that in the long term, green hydrogen based on solar and electrolysis will dominate the market. “This will be driven by economics as the price of installing and maintaining very large-scale solar farms decreases — people are already talking about $20MWh — and also as the cost of large-scale electrolysis drops. We and others are researching the latter to bring down the cost of the materials,” he says.

For the near term, The Future of Hydrogen report identifies four opportunities to accelerate the widespread use of clean hydrogen:

Make industrial ports the nerve centres for scaling up the use of clean hydrogen. Today, much of the refining and chemicals production that uses hydrogen based on fossil fuels is already concentrated in coastal industrial zones around the world, such as the North Sea in Europe, the Gulf Coast in North America and southeastern China. Encouraging these plants to shift to cleaner hydrogen production would drive down overall costs. These large sources of hydrogen supply can also fuel ships and trucks serving the ports and power other nearby industrial facilities like steel plants.

Build on existing infrastructure, such as millions of kilometres of natural gas pipelines. Introducing clean hydrogen to replace just 5% of the volume of countries’ natural gas supplies would significantly boost demand for hydrogen and drive down costs.

Expand hydrogen in transport through fleets, freight and corridors. Powering high-mileage cars, trucks and buses to carry passengers and goods along popular routes can make fuel-cell vehicles more competitive.

Launch the hydrogen trade’s first international shipping routes. Lessons from the successful growth of the global LNG market can be leveraged. International hydrogen trade needs to start soon if it is to make an impact on the global energy system.

“International co-operation is vital to accelerate the growth of versatile, clean hydrogen around the world,” concludes the report, and in that sense, the signing of the Australia-Japan Memorandum of Cooperation is a positive step.

Australian collaboration with Japan on projects such as the recent first export of green hydrogen from Queensland and on the Victorian brown-coal-to-hydrogen project, which aims to capture and store the 100 tonnes of CO2 generated during its pilot phase in 2020, can both be viewed as exploratory stages toward a clean-hydrogen industry.

But in the context of Japan’s plans to build as many as 30 new coal-fired power stations on its own territory, and its financing of new coal-fired plants in Asia; and with Australian governments clearing the way for coal-mining companies to break new ground, in the absence of any policy for a clear long-term transition to renewable-energy, the collective intent behind the various initiatives remains unclear.

pv-magazine.com.


Natalie Filatoff has been a journalist and editor for more than 30 years, working successively in the areas of computing, the arts, popular culture and health. Over the past five years she has written primarily about science, technology and renewable energy.

Hydrogen Evolution or Revolution?
Dec 10, 2020
by Michael Welch
The American Society of Mechanical Engineers

Hydrogen is the most abundant element in the universe. Engineers are working to overcome the challenges to producing hydrogen fuel at scale and adapting gas turbines to burn it.


This article is part of THECLEAN ENERGYCOLLECTION

This year is on track to be the hottest since measurements began, according to the National Oceanic and Atmospheric Administration (NOAA). The agency estimates there’s a 75 percent chance that 2020 temperatures will beat the record set in 2016, despite the temporary reduction in emissions due to the COVID-19 pandemic, continuing an upward trend in global temperatures that is altering the climate of our planet.

In 2015, nearly 200 nations agreed to respond to the threats of climate change by curbing emissions in order to keep the increase of average global temperatures below 2 °C above pre-industrial levels and try to limit increase to 1.5 °C. In order to meet those emission goals, many nations and organizations, including the European Union, are aiming to become carbon neutral by 2050. In a study published in Applied Energy last April, researchers indicate it’s possible, with the use of the right technologies, to reduce industrial greenhouse gas emissions to net zero by 2070.

Currently, between 30 and 40 percent of the electrical power in the world comes from gas turbines, most of which are powered by natural gas or other liquids that emit carbon dioxide—a major contributor to climate change. For that reason, manufacturers are looking to hydrogen, the most abundant element in the universe, as a fuel source in power generation turbines. Converting gas systems to use hydrogen fuel instead of a carbon-based fuel could, therefore, be an important link in decarbonizing the energy industry.

Despite the push to spend billions on research and development (R&D) to create this capability, hydrogen—which needs to be extracted from readily available molecules—has proven to be a difficult, and energy intensive, fuel to source. Many in the green sector are pushing for utilizing wind and solar energy to power the element’s extraction. However, the amount of resources currently required makes these ideas challenging from an economic perspective. Hydrogen is a clean-burning fuel, but its production is anything but clean or easy, at least for now.

There are, however, other ways to move us toward a hydrogen economy. Instead of running power generation turbines on 100 percent natural gas, as we do now, turbines could operate on combinations of natural gas and hydrogen, helping reduce carbon footprint while undertaking the challenges of using the new fuel in steps. To move forward, however, technological, economical and political challenges must be met with solutions that tackle each of these alone and in combination with one another, carving a path for hydrogen to become more commonplace in the energy sector.

From Grey to Blue to Green

Gas turbines convert fuels like natural gas into mechanical energy by pulling in ambient air at normal atmospheric pressure from the outside and increasing its pressure to anywhere between approximately 15 and 30 times atmospheric pressure. The engine then puts that air into a combustion can and mixes it with fuel. The fuel is ignited to create hot gases that expand over turbine stages, which turn the whole gas turbine and drive a generator, pump, or compressor.

With this very simple principle, the main objective from a combustion perspective is to mix the air and fuel in order to create very high temperature gasses that enter the turbine stages at 980 to 1370 °C. The result is exhaust gasses at temperatures of around 590 °C, which means the process is able to extract some 40 percent of the fuel energy in an open cycle configuration. Though, the fuel source for these turbines is typically natural gas, liquefied petroleum gas and alternative sources like diesel and even biogas are also common.

More on This Topic: Hydrogen Breakthrough Begins

What these fuels have in common, however, is they are all carbon-based, which means when they burn, they produce carbon dioxide, a major greenhouse gas, as a byproduct.

Hydrogen, a plentiful element in the environment, on the other hand, is considered a clean fuel source. High in energy with close to zero pollution, hydrogen does not occur as a gas on its own and can be found in organic matter, water, and hydrocarbons that make up fuels like gasoline, methanol, and natural gas. To use it, hydrogen needs to be extracted from these compounds via heat or electrolysis.

Extracting hydrogen from natural gas by adding steam produces carbon dioxide as a byproduct, which at the moment is vented into the atmosphere. For every kilogram of extracted hydrogen about 8 to 10 kilograms of carbon dioxide are generated. Hydrogen produced with such high emissions is known as grey hydrogen, with an overall carbon dioxide footprint that is worse than burning just natural gas.

To minimize this footprint, we would need a process to capture, store and sequester the carbon dioxide. Hydrogen produced as such is known as blue hydrogen. This can reduce carbon dioxide emissions to 1 to 1.5 kilograms of carbon dioxide per kilogram of hydrogen, making a massive reduction in carbon intensity of power generation.

Being a very small molecule, hydrogen will leak through most materials. One would have to use the right type of steel materials, without any rubber or non-metallic seals. And current safety measures would need to be adjusted for the new fuel mix.For these reasons, environmental advocates have pushed to use wind and solar energy to power electrolyzers—devices that use electricity to separate water into hydrogen and oxygen—to extract hydrogen, where by inputting water, the only byproduct is oxygen. The problem with this approach for power generation is that the initial investment costs required are considerably higher than a conventional natural gas-fired power plant, because as well as the power plant, large wind and solar farms would be required along with the electrolyzers.

The idea also raises the question as to why use electricity to produce so-called green hydrogen instead of selling the electricity directly. The proposal is that in times when there's, for example, too much wind generation compared to load demand, or the electricity transmission system cannot handle the high quantities, we could divert this curtailed wind energy to produce hydrogen for medium- to long- term storage, and use the hydrogen later during periods of low wind generation. The challenge with this thinking is that the capital costs go up once again because of the expenditure to build the hydrogen storage facility. And so, whereas currently industrial hydrogen is between 1 and 2 dollars per kilogram, and blue hydrogen from steam methane reforming and carbon capture is probably in the 1.5 to 2.5 dollars per kilogram range, electrolysis costs will be 3 to 5.50 dollars per kilogram for green hydrogen in the short- and medium- term. Some analysts forecast the cost of green hydrogen could fall as low as the current levels of industrial hydrogen in regions with plentiful renewable energy resources, and certainly achieve parity with blue hydrogen. However, even this equates to a fuel price of 18 dollars per one million British Thermal Units (mmbtu), considerably higher than natural gas.

Further, wind and solar energy are not continuous. For example, for a power-to-hydrogen project based on an offshore wind farm with a capacity factor of around 45 percent, to produce a continuous flow of hydrogen at about 4 to 4.5 metric tons of hydrogen per hour, you would need a gigawatt scale wind farm, approximately 500 megawatts of electrolyzers and 1,000 metric tons of hydrogen storage. While this scale of plant may be appropriate for providing hydrogen to the industrial or transport sectors, the amount of hydrogen produced will barely run a 50-megawatt gas turbine, so one can begin to see the size of the challenge: The amount of renewable energy needed to provide the amount of green hydrogen required just for current industrial uses is immense.

If the goal is to use green sources for power as well, then we need many times the currently installed renewable energy capacities, which requires trillions of dollars of investments and years to construct, in addition to setting aside the large land or sea areas required for the solar photovoltaic (PV) devices and wind farms. Today, around 70 million metric tonnes per year (or 8,000 tonnes per hour) of ‘grey’ hydrogen is produced for industrial purposes. With a 50-megawatt gas turbine consuming about 4.5 tonnes per hour of hydrogen, 8,000 tonnes per hour of hydrogen equates to around 100 gigawatt of power generation capacity, whereas the current installed base for natural gas-fired generation is 1,644 gigawatt and this is forecast to rise to around 3,000 gigawatt by 2050. If hydrogen is to fully replace natural gas generation, global hydrogen production needs to increase thirtyfold, before we even consider displacing natural gas usage in industrial and domestic heating applications.

Why Hydrogen?

There isn't an easy way to decarbonize the energy industry or, in many countries, to decarbonize domestic heating. Those who live in climates where the winters are cold, like the U.K. or the northeast of the United States, use four times as much energy in the form of natural gas for heating and cooking as they do electricity. If we were all to switch to electric heating in our homes, we'd need five times as many power stations, or 20 to 30 times as much renewable energy, as we currently have. We’d also require five times as much transmission and distribution capacity, all of which create a major challenge.

Additionally, it’s not always technically or economically possible to simply retrofit electric options in industrial processes to displace combustion of natural gas or coal, so fossil fuels need to be replaced with something cleaner. The more pragmatic solution is using hydrogen as a fuel for domestic and industrial applications. At Siemens, we are involved in a project for Voestalpine in Linz, Austria, under the EU-Funded H2Future Project where they're using green energy to create hydrogen for use in steel mill steel production to displace some coke or coal. Another example of fossil fuel displacement is Cadent’s HyDeploy project at Keele University in the U.K. , which involves blending hydrogen into a natural gas network up to 20 percent by volume so they can partially decarbonize the heat network at the university.

Currently, less than 1 percent of the global installed gas turbine fleet is operating on a hydrogen-rich fuel, and only one refinery in Italy claims to run on 100 percent hydrogen. The composition of the fuel gases in refineries varies hour by hour. Therefore, one has to design a system so it runs on different fuels at different times of operation. For example, in a refinery project we’ve designed for use for Braskem, a Brazilian petrochemical company, the system can run on varying hydrogen concentrations from zero to 60 percent by volume with no impact on performance.

Although not the zero carbon emissions that people aspire to, hydrogen-rich fuel gas blends can cut CO2 emissions enough to make an impact on global emissions now. For example, with a blend of 20 percent hydrogen and 80 percent natural gas, carbon dioxide emissions can be cut by about 7 percent. Increasing the blend to 60 percent hydrogen will provide about a 20 percent carbon dioxide reduction. The technology is currently available to achieve these CO2 reductions and put us on course to limit global temperature rises to below 2 degrees Celsius, while helping the hydrogen economy to develop at the pace needed to achieve net zero carbon emissions by 2040 or earlier. Of course, these numbers are not necessarily the big reductions that many would like to see immediately but it's a step in the right
direction.

A Two-Step Goal

In an agreement announced by EU Turbines in January 2019, gas turbine manufacturers in Europe, which basically includes every major gas turbine supplier in the world, committed to provide gas turbines able to operate on 20 percent hydrogen by volume in combination with natural gas by 2020 and for customers to be able to acquire gas turbines for operation on 100 percent hydrogen by 2030. While the ultimate aim is be using 100 percent hydrogen, it’s clear it won’t be easy to achieve this in one big bold step. Initially, most turbines are likely to operate more on blends with much less than 100 percent hydrogen because there simply isn't enough hydrogen available, as acquiring sufficient hydrogen at an affordable cost for operating solely on hydrogen is going to be a significant challenge.

For example, for a thirty-minute whole engine test on a gas turbine at our Finspong factory in Sweden, we basically had to source every spare bit of hydrogen in that nation and extend the search to some neighboring countries. There simply isn’t enough of it readily available.

Environmental advocates have pushed to use wind and solar energy to power electrolyzers—devices that use electricity to separate water into hydrogen and oxygen—to extract hydrogen, where by inputting water, the only byproduct is oxygen.To aid this shortcoming, some of the projects in Europe, and in the U.K. in particular, are aiming to create a sufficient supply of hydrogen at a reasonable cost in order to start decarbonizing industrial sectors and replacing natural gas with hydrogen in high quantities. Six industrial clusters in the U.K. have been identified for additional funded studies to decarbonize industry and power generation, with some of these clusters proposing to use ‘blue’ hydrogen and carbon capture technologies.

Once that challenge is met, the turbines would need to be retrofitted to accommodate the new fuel mixtures. The combustion systems, a major area for change, are currently designed for natural gas with a specific flammability range and flame speed of a fuel that contains predominantly methane.

Hydrogen, on the other hand, has a much faster flame speed—approximately 10 times as fast as methane—and a wider flammability range, so it can burn when, and where, it isn’t wanted. Therefore, the fuel injectors need to be redesigned to create a flame profile and position that the combustion system can cope with. Further, as hydrogen flame burns hotter than natural gas flame, increases in thermal nitrogen oxides (NOx) also occur.

The next challenge is getting the hydrogen into the combustion system. Being a very small molecule, hydrogen will leak through most materials. One would have to use the right type of steel materials, without any rubber or non-metallic seals. And current safety measures would need to be adjusted for the new fuel mix. For example, a gas detector that's for standard natural gas will not detect a hydrogen leak.

Also, hydrogen burns with a different color flame, so a flame detector designed to sense the blue flame from natural gas wouldn’t pick up a hydrogen flame, which is virtually invisible to the naked eye.

These challenges are well understood and solutions to overcome them have already been mapped out. From a technology perspective, there is confidence that the gas turbine industry will get to 100 percent hydrogen with low emissions at some point. The biggest challenge, therefore, is an economic one—having enough hydrogen at a reasonable cost so that energy doesn’t end up costing three or four times as much as what we’re paying for today.

To that end, nearly every turbine manufacturer is currently working on this issue by responding to industry demands. Globally, politicians, especially in Europe, are pushing for decarbonization. And no matter how much we improve the efficiency of turbines running on fossil fuels, it is not going to hit their CO2 reduction targets. So we’ve either got to have carbon capture on the power plants, or use a zero carbon fuel.

Further, gas pipeline companies are taking an interest in the technology because if, say by the mid-2030s, politicians decide that no more fossil fuels will be used, there will be thousands of miles of pipeline which will become stranded assets. So gas companies are looking at how they can repurpose those assets for either transporting carbon dioxide for sequestration or transporting natural gas and hydrogen blends down existing piping systems. Re-purposing existing infrastructure assets could be critical in keeping down the costs of the energy transition.

For turbine manufacturers the major challenge is where the hydrogen will come from. That's what markets and the politicians need to really think about. There's no point pushing researchers and companies to develop 100 percent hydrogen-capable gas turbines by 2030 if it will take another 30 years before there’s enough hydrogen to run a turbine.

If the push is for companies to spend millions on research and development to create 100 percent hydrogen capability, there needs to be enough fuel to run the gas turbines on. And while wind farms, electrolyzers and green hydrogen with zero carbon footprint is a great idea, if 1,000 megawatts of wind farm are required to run a 50-megawatt gas turbine continuously, the setup will be impractical. So we need to be looking at the various methane reforming options and carbon capture more seriously.

It’s Political

While there are technical and environmental challenges of utilizing hydrogen as a fuel, the overall political dimension of the issue is often overlooked. Add to that the varying politics of each region or nation and the energy field becomes a patchwork of approaches that resembles a multi-fabric, multi-design quilt.

Germany, for example, doesn't believe in carbon capture because the nation doesn't really have any suitable geological formations where it can store captured carbon dioxide. On the other hand, Norway, the U.K. and Australia are quite comfortable with carbon capture and sequestration as they have depleted offshore oil and gas fields where captured CO2 can be stored. In fact, Norway has for many years been sequestering CO2 in the Utsira aquifer offshore. And the U.S. has been using carbon dioxide for enhanced oil recovery in Texas in the Permian Basin and in Wyoming for years, as have the Canadians, in order to maximize oil recovery from older oilfields.

Additionally, many governments don't want to relax environmental legislation, creating a challenge to meet similar emission levels with hydrogen as required with natural gas. So, if these governments insist on lower and lower NOx emissions with hydrogen, a turbine alone isn’t enough to achieve that. This means there would have to be post-combustion exhaust cleanup systems to achieve single digit NOx levels, which increases the cost of power even more. The end result is a more expensive plant and fuel, pushing up the cost of energy that then becomes a political no-no. Because, while everybody wants clean power, nobody wants to pay a lot more for it and it’s essential for our future that energy poverty is eradicated.

At its core, having this technology succeed is about finding a technological, economical, and political balance, where we can have this abundant clean electricity that's available 24 hours a day, seven days a week, 365 days a year. It's a complex area with multiple strategies that have got to come together with compromises that need to be made in all areas to get the get the whole hydrogen economy moving in the right direction.

Perhaps it’ll serve us to learn from the past: One such example is the biomass gasification is initiative where efforts were focused so much on intellectual research, conducting studies and trying to find what the ultimate best possible solution was, it created an environment that led to nothing being built. One can certainly reduce costs far quicker by building commercial-scale demonstration plants and repeating designs and learning from them, than by more research and development to try and improve things by a fraction of a percent. You build your first plant. Prove it, test it, and then you can go back and knock 10 or 15 percent of the cost of the plant and continue cutting costs by repeating designs and learning, instead of promising the Earth and not delivering.

Fortunately, governments in Europe have become much more pragmatic and see this as the step we need to take. They realize that though it's not quite the efficiency levels, emissions reductions and low costs we are ultimately seeking, this is going to get us from where we are today to where we need to be in 2040, as opposed to trying to make that revolutionary jump in one go and failing. It's much more of an evolutionary process. Certainly in Europe, the political scene, good support, and realistic approach are there.

Europe is not aiming for an interplanetary shot with a first rocket. Instead, our goals are realistic.

Michael Welch is an industry marketing manager at Siemens Industrial Turbomachinery in Lincoln, U.K.

THE PROS AND CONS OF HYDROGEN FUEL CELLS AS BACKUP GENERATORS


Posted by research/ media organizations | Sep 6, 2020 | Fuel cell, hydrogen storage | 1 |


can fuel cells replace backup generators and batteries? Microsoft is trying to find out

Microsoft has been experimenting with hydrogen power since 2013 when it began testing solid oxide fuel cells (SOFCs), which extract hydrogen (H2) from natural gas, to run server racks in data centers. SOFC technology was (and still is) expensive, relies on fossil fuels, and produces CO2, so the software giant eventually put the project on the back burner.

Meanwhile, the price of proton exchange membrane (PEM) fuel cells has dramatically decreased. PEM fuel cells use purified H2 rather than hydrogen extracted from natural gas. They operate at lower temperatures and are carbon neutral, making them favorable alternatives to SOFCs.




Microsoft’s 250kW PEM fuel cell backup generator built by Power Innovations. Image courtesy of Power Innovations.

Instead of trying to run the data centers exclusively from fuel cell energy, Microsoft is using PEM fuel cells to replace diesel-powered backup generators, which are called into service so infrequently that they burn more fuel during monthly testing than they do in actual operation. But they still require maintenance and diesel fuel has a limited shelf life, so finding a reliable, cost-effective replacement makes sense. For a comparable price, PEM fuel cells can deliver the same generating capacity as diesel generators.

Fuel Costs

While the price of a PEM fuel cell is similar to that of an equivalent diesel generator, the cost of the fuel the systems use is not. One kilogram of hydrogen has almost as much energy as a gallon of diesel fuel, but per unit of energy content, hydrogen fuel costs more than five times as much as diesel. Some of that cost is offset by the fact that fuel cells are twice as efficient as diesel generators, but in terms of price per kilowatt hour of electricity generated, hydrogen is still nearly three times more expensive. If only there were an abundant, inexpensive source of hydrogen available. Oh, yeah … there is!

Electrolysis

Two-thirds of our planet’s surface is covered in a hydrogen-rich substance (H2O), but those hydrogen atoms are quite attached to their oxygen siblings, and covalent bonds are tough to break. Separating water molecules by electrolysis requires about 50kWh of electricity to obtain a single kilogram of hydrogen. (The resulting hydrogen contains 33kWh of energy.) That’s a problem if you’re buying electricity from the grid, but less of a concern if you’re using solar, like Microsoft plans to do. Here’s how electrolysis by solar works:

Video courtesy of the U.S. Department of Energy.

Fueling Up

Although the photovoltaic effect and the electrolysis process are both relatively inefficient, for this particular application—backup generation—efficiency is less important, for two reasons. First, sunlight is free. (Solar panels cost money, but that’s a small initial investment in this case.) Second, these generators rarely run, so their hydrogen tanks can be “trickle charged,” so to speak, with a relatively small array that runs the electrolyzer whenever the sun happens to be shining.


Hydrogen tanks. Image courtesy of Microsoft.

For example, Microsoft’s fuel cell, with a 250kW capacity, was able to power 10 racks of data servers for 48 hours. That’s a total of 12MWh of electricity. Fuel cells are about 60 percent efficient, so it would take 600kg of hydrogen to produce that much electricity.

How big of an array would you need to replenish that? Well, at 50kWh/kg, it takes 30MWh of electricity to produce 600kg of hydrogen. But keep in mind that these are backup generators; it’s extremely unlikely that they’ll be running for 48 hours straight. If you start with enough hydrogen to power the racks for a few hours, say, 60kg or so, then a one-megawatt solar array could produce the remaining 540kg in less than a week. According to Microsoft engineer Mark Monroe, the generators sit idle for more than 99 percent of their lives, which means they run about three days a year. On average, then, electrolyzers could take up to four months to slowly refill the hydrogen tanks. At an average of five peak sun hours per day, a modest 50kW array could do the job.

Why Not Use Batteries?

Looking at my calculations above, we see that it takes 50kWh of energy to extract one kilogram of hydrogen, which, in turn, can generate 20kWh of electricity. That’s a round-trip efficiency of 40 percent—pretty bad compared to batteries, which easily exceed 85 percent.

Before the days of cloud-based data centers, companies had on-premises servers with backup power provided by uninterruptible power supplies (UPSs) consisting of a charge controller, a battery, and an inverter. Many data centers continue to run with UPSs on their servers. If batteries work at the server level, then why not use them at the data center level?

When choosing an energy storage system, engineers have to consider factors such as initial price, operation and maintenance costs, round-trip efficiency, capacity, and many others. Fuel cells have a much smaller up-front price, but the low round-trip efficiency can result in a higher overall operating cost if one is purchasing electricity to produce the hydrogen. Although batteries win on round-trip efficiency, they incur a larger capital cost, one that’s proportional to the amount of storage capacity. With hydrogen, however, increasing storage capacity only involves more (or larger) tanks, not additional fuel cells. According to the National Renewable Energy Laboratory (NREL), for durations above 12 hours, hydrogen has an economic advantage over batteries.


Credit: NREL

In the previous example, Microsoft ran its servers for 48 hours, drawing about 12MWh of energy. In a few years, we can expect the price of Li-ion batteries to drop as low as $100 per kWh, so a 12MWh battery will set you back about $1.2 million. At $50 per kW, a 250kW fuel cell runs $12,500. (That doesn’t take into account the cost of storage tanks or solar arrays, but it’s safe to say that those won’t approach the million-dollar mark.) How many MWh of electricity it will produce depends on the size of the hydrogen storage tanks in the system.

Environmental Impact

There’s no technology that’s entirely benign; the goal of sustainability is to do the least amount of damage possible. Manufacturing “green energy” equipment is often a dirty process, especially when the materials require mining, smelting and other processing. The catalyst in most PEM fuel cells is platinum, a rare, precious metal that’s mined primarily in South Africa, with smaller operations in Russia, Zimbabwe, Canada and the U.S. In addition to its use in fuel cells, platinum is also used in catalytic converters and gasoline refineries. While extracting and processing platinum ore has a high carbon footprint, the metal itself is recyclable, which decreases its negative environmental impact. In fact, recycling platinum has led to lower prices, which is part of the reason that fuel cells are becoming more affordable. Even better, researchers are developing catalysts made from platinum alternatives, such as carbon nanofibers and even biosynthesized materials.

More on Efficiency

Fuel cells produce a lot of heat, so they’re often used in combined heat and power (CHP) or co-production systems, which increases their efficiency since the heat isn’t wasted. During the summer months, the excess heat can also be used to cool an area, using an absorption chiller. That seems like less of an issue in this application, since backup generator fuel cells rarely produce energy, but just as otherwise idle data center UPSs are now being considered for grid support, the fuel cells could be employed in a similar capacity. Maybe fuel cells, instead of batteries, will become the new peaker plants.

Will It Fly?

At this point, Microsoft is still in the exploratory stages of using fuel cells as backup generators. The 250kW system was a proof of concept; the next step is to test a 3MW system, which is equivalent to the diesel-powered generators at the company’s data center sites.

In a larger sense, one reason that the hydrogen economy has been slow to expand is the lack of an infrastructure, which is sort of a chicken-or-egg problem: it’s hard to buy into the technology without an infrastructure, but nobody wants to invest in the infrastructure until people are using it. While the government is providing some funding for green energy, we need more companies in the private sector to explore alternate uses for these energy systems in order to grow a green economy and a sustainable environment. Hydrogen has enormous potential in that regard; how soon it becomes an economically viable technology depends on how many companies are willing to take a chance on it.

Alberta Can Transition from Oil and Gas and Have a Strong Economy. Here’s How

‘Tens of thousands’ of people would be put to work immediately in high-skill jobs, say advocates.

By Geoff Dembicki 31 Jul 2019 | TheTyee.ca

Geoff Dembicki reports for The Tyee. His work also appears in Vice, Foreign Policy and the New York Times.

I

ron & Earth founder Liam Hildebrand holds a photo of himself standing by a log cabin in the woods. His message: ‘There are two major parts to who I am, the steelworker who is also passionate about the environment.’ Photo from Iron & Earth.


What will a transition away from oil and gas mean for workers in Alberta?

Perhaps greater job security than in the boom and bust heydays of the oilsands, comparable wages and less time apart from family.

This is not a utopian pipe dream. Over the past month The Tyee spoke with experts across the province and the country who said Albertans have the skills and desire to build the sustainable energy system necessary to address our climate emergency.

“A lot of the people that support the pipeline are also very pro-renewable energy,” said Lliam Hildebrand, who spent years working in the oilsands and now runs a group called Iron & Earth that advocates for policies connecting oil workers to the millions of jobs required to build a low-carbon economy in Canada.


Decades of employment for laid-off Albertans could be unlocked by our political leaders in a matter of days

Calgary roofer and Alberta Liabilities Disclosure Project researcher Regan Boychuk says tens of thousands of oil workers could be hired to clean up polluted oil and gas wells.

“It could be implemented in a weekend,” he added.

“Humans are somewhat predisposed to wanting to avoid change,” said Alison Cretney, managing director of the Alberta-based Energy Futures Lab, which works on plans for the province’s transition from fossil fuels.

But she says business leaders who embrace the future instead of resisting it could find great opportunities. They could build companies that extract lithium for electric car batteries from oil wastewater, or use Alberta’s vast fossil fuel reserves to create a hydrogen economy many times more lucrative than selling oil and natural gas at a discount to the U.S.

Decision-makers who harness the massive economic changes happening all around us could start healing the severe damage that oil and gas extraction has inflicted on Alberta’s natural environment and help repair Canada’s relationship with the Indigenous people who’ve lived there for at least 11,000 years.

Albertans haven’t been told about the opportunities after fossil fuels, says Bronwen Tucker. Photo by Carol Linnitt, the Narwhal

Bronwen Tucker, an Edmonton-based researcher for the advocacy group Oil Change International said people don’t yet grasp the opportunities that are available.

“We’ve never told another story of what’s possible in Alberta,” said Tucker, “[We’ve] never been allowed to.”

‘It was terrifying’

Iron & Earth’s Lliam Hildebrand worked at the Long Lake oilsands project in 2015 when plummeting oil prices caused companies across the industry to fire tens of thousands of people.

“It was terrifying,” he said. He started talking to others about a Plan B. “What we found out was that in a lot of countries renewable energy was actually the fast-growing job provider and that a lot of those jobs were very relevant to our skill set,” he said.

Hildebrand has worked in a steel-fabricating shop that built things like pressure vessels, flare stacks and drilling rig platforms for the oilsands. The shop also took on contracts to build an industrial heat-generating composter, a biomass plant and a wind farm weather station.

“I was able to build all these different renewable energy technologies without retraining,” he said. “It was the same process of steel coming through, I’d read the blueprint, cut the steel up, put it into place and have the welders weld it.”

Nearly two-thirds of energy sector workers surveyed by Iron & Earth in 2016 said their skills could be directly applied to renewable energy work with additional training and about 15 per cent said they could make the shift without it.

Training could mean something as simple as a five to 10-day intensive “upskilling” course. But Hildebrand notes that many workers aren’t eligible for training subsidies covering these types of courses until they’ve secured actual employment in renewable energy.

“But that’s backwards,” he says.

He argues we should be providing the skills training first, so that workers have a way of earning money during periods when oilsands work dries up. They could then switch back and forth between fossil fuels and renewables depending on where the most work is. That would provide some stability and help build a more sustainable system. Those workers are less exposed to mass layoffs caused by oilsands downturns while at the same time helping to build a more sustainable system.

Hildebrand says it’s about “diversifying our work opportunities.”

And leaving fossil fuels doesn’t necessarily mean a pay cut. “Some of the larger projects like wind farms and utility-scale solar pay actually fairly comparable to other energy industries,” he said.

Turning liabilities into jobs

The transition away from oil would also make Alberta healthier. Across the province there are about 450,000 oil and gas wells, at least 155,000 of which aren’t producing, but haven’t been reclaimed and cleaned up. Some people living close to them say they have experienced severe headaches and chronic health problems.

The government says that the total cost of cleaning up Alberta’s oil and gas industry is about $58 billion.

But earlier this year, the Alberta Liabilities Disclosure Project released a report estimating the cost of cleaning up abandoned oil wells alone at $40 to $70 billion. Private regulatory documents obtained by Boychuk suggest when you add in aging pipelines and things like toxic tailings ponds, the cleanup cost could exceed $260 billion.

That’s a looming financial and ecological catastrophe for the province, given that it’s collected less than $2 billion from companies to cover cleanup costs.

But Boychuk says with the right policies, cleaning up after the industry could be “a quarter trillion economic opportunity.”

For years he’s been fine-tuning a plan that would see tens of thousands of people — including those still struggling from the oil downturn — put to work reclaiming polluted oil wells. Many could start immediately.

“In the service sector all the truck drivers, all the different services involved in drilling and servicing a rig, are the same ones involved in the cleanup,” he said.

Boychuk proposes that when an oil and gas company goes bankrupt — like Calgary’s Trident Exploration, which folded in May and walked away from 3,358 operating wells — a government-supported reclamation trust could step in and operate the wells.

“You don’t have to pay executives anymore, you don’t have to pay investors,” he said. “What oil and gas is left behind from these failed companies just became a lot more profitable.”

The revenue would then be used to pay cleanup workers. Because wells are spread over every corner of the province, it’s conceivable people can work close to homes and families. Boychuk claims it would potentially create decades of employment.

“We’ve been offering this plan to the government in Alberta for years,” he said. “But there’s a lack of political will.”

‘Everybody’s replaceable’

The political leaders in favour of new pipelines and oilsands expansion tend to put forward a simplified view: things that create jobs are good. But we seldom debate the quality of those jobs, the tolls they take on families or the unjust power relations that can be built into them.

Over the past several years Angele Alook has been interviewing working-class Indigenous people in the town of Wabasca in northern Alberta to learn about the social impacts of oilsands employment.

“The industry works 24-7, so people are working very long shifts, they work 12- to 13-hour days,” she said. They can be away from partners and children for weeks or months. “That really creates an imbalance in families,” she said.

Alook is a member of the Bigstone Cree Nation. She worked as a researcher with the Alberta Union of Provincial Employees and recently became an assistant professor in the School of Gender, Sexuality and Women’s Studies at York University.

Some people she spoke with struggled with feelings their employment was precarious. “Everybody’s replaceable, right?” one worker told her.

Indigenous workers said they were often passed over for wage increases and promotions in white-owned companies and were stuck in lower-skilled positions. Research suggests that during resource downturns, they are often the first to be laid off.

“Indigenous people don’t reap the benefits of this industry,” Alook said.

The shift away from oil could create opportunities for better-paying and more meaningful work. The billions of dollars that Canada spends subsidizing the oil and gas industry could partly be redirected to education for Indigenous peoples, she said. “The federal funding that we get for post-secondary does not meet the demand that we have,” she said.

Canada could accelerate the healing of our natural environment by fully implementing the United Nations Declaration on the Rights of Indigenous Peoples.

“There’s specific articles that... talk about our right to our sovereignty and decisions regarding our land,” she said. “If the land is healthy and prosperous, then we are.”

A just transition for workers

There’s no denying economic transitions can be painful. Canadian Labour Congress president Hassan Yussuff was reminded of this as he travelled the country meeting people affected by the federal government’s decision to shut down coal-fired power generation by 2030. “There was a lot of worries about what was going to happen,” he said.

Yussuff did this work as co-chair of a federal government task force on “Just Transition for Canadian Coal Power Workers and Communities.”

The group, set up on the urging of Canada’s labour movement, looked at the social impacts of shifting away from coal, a fossil fuel that helped build the country’s economy, and give advice on how to make those impacts less severe.

“When the Government of Canada says it is going to ‘phase out coal,’ coal workers and communities hear that Canada is phasing out their future, livelihood, stability and identity,” the task force wrote in a report this spring.

But the signs of coal’s global decline are clear. And the guiding logic behind the task force’s work was that it’s better to meet with workers and ease them into whatever comes next rather than waiting for the market to collapse and forcing them to fend for themselves.

“The concept of just transition is not idealistic,” Yussuff explained. It’s a concrete strategy for ensuring as few people as possible suffer during our shift to a more sustainable economy, he added. The task force produced 10 recommendations, including setting up “locally-driven transition centres,” pension supports for workers who have to retire early and job-creating infrastructure projects.

The feds have so far committed $35 million to this effort. Yet the task force thinks the final “costs of the phase-out will stretch well into the hundreds of millions of dollars.”

Yussuff suggested the investment is well worth it, not only for coal workers and their families, but as a proof of concept for shifting our entire economy off climate-destroying activities.

“If you can get some of this right, hopefully we might be able navigate some bigger challenges that we have to deal with in this country,” he said.

‘It’s within reach’

One common misconception about building a low-carbon economy is that we have to start from scratch. The Energy Futures Lab challenges that logic by supporting research into new business opportunities that grow out of old ones. “There’s tweaking and adjustments that need to happen,” Cretney said. “But we’re not talking about a complete remake of everything.”

The Lab’s work is supported by several dozen fellows who span a wide range of industries and backgrounds. Its supporters include oilsands companies (Suncor), public sector organizations (Alberta Innovates), renewables groups (Indigenous Clean Energy) and environmental watchdogs (the Pembina Institute).

Cretney says one way we get to a low- or zero-carbon economy in Alberta is by using bitumen to build things rather than burning it in vehicle engines. The resource could potentially be used in carbon fibre, fortified steel, asphalt or even as a source of vanadium for renewable energy storage batteries.

There is also huge potential to produce zero-emission fuel from the province’s oil and gas reserves, argue University of Calgary professor David Layzell and hydrogen researcher Jessica Lof.

“Our research shows that Alberta’s best ‘Plan B’ for the future of its oil-based economy is to transition to the production of a clean, more energy efficient, and much more valuable transportation fuel: hydrogen,” they write.

Alberta oil currently sells for the equivalent of $4 to $8 per gigajoule of energy. They calculate that hydrogen fuel could fetch prices of $18 to $25. “[It] would generate two to four times more economic activity for Alberta than producing and exporting crude oil for the diesel market,” Layzell and Lof write.

All these solutions require foresight and creativity from our political leaders. But those are the same qualities that allowed Alberta to build an oil industry in the first place. Now it’s time to create an economy that helps solve the climate crisis, gives people stable and meaningful jobs and is every bit as prosperous — if not more so —than what came before it.

“It’s about developing these industries of the future not in spite of, but really because of, the oil and gas industry today,” Cretney said. “Because of that it’s within reach.”

RUSSIA 

The Hydrogen Economy- a path towards low carbon development

• June 2019

DOI:10.13140/RG.2.2.23559.75686

Authors:

Tatiana Mitrova

• SKOLKOVO Business School, Moscow, Russia

Yuriy Melnikov

• Moscow School of Management SKOLKOVO

(PDF) The Hydrogen Economy- a path towards low carbon development (researchgate.net)