ENERGY GL BAL SUMMER 2021
Making our world more productive
Connecting the world of hydrogen – From source to service
The hydrogen future is here now. And Linde can deliver it. The company covers every link in the hydrogen value chain from source to service – whether it be used as a zero-emissions source of fuel for trains, buses and cars; a feedstock gas for industries such as steel and refining.
And the best bit: Hydrogen can be generated at scale with a zero carbon footprint by using renewable energy such as wind power to separate water. Regardless of your target application, we have the technologies and expertise to support your project.
Think hydrogen. Think Linde. linde-engineering.com/hydrogen
34. Harnessing the power of the sun
Umberto Magrini, Head of Engineering and Construction, Enel Green Power.
04. Bonjour, hello, hola to renewables
Kay Hobbs and Simon Courie, TLT, UK, and Harald Wiersema, Holla, the Netherlands.
38. Solar to re-energise the economy Jamie MacDonald-Murray, Lisarb Energy, UK.
42. Look above for the answer
Lorenzo Mancini, Total Solar Distributed Generation, Singapore. Kay Hobbs and Simon Courie, TLT, UK, and Harald Wiersema, Holla, the Netherlands, look at the recent trends and developments in Europe’s renewables industry, and how the landscape for clean energy in the region is changing.
46. Store more for the world of tomorrow Tadgh Cullen, Statkraft, UK.
020 was a year to remember in many ways and not for the best reasons, but from an energy standpoint, there was one encouraging statistic to emerge. For the first time ever, more electricity was generated by clean energy sources across Europe than by fossil fuels (38% vs 37%), according to a report by think tanks Ember and Agora Energiewende, with Germany, Spain, and the UK achieving this balance at a national level. Is this a sign that the pledge made back in 2014 by former European Commission President Jean-Claude Juncker to make the EU the “world number one in renewables” is coming to fruition? With the climate crisis becoming ever more urgent, and with the Paris Agreement ambitiously aiming to cap global warming at 1.5˚C above preindustrial levels, many people will be hoping so. Analysis by management consultancy Kearney estimates that energy companies are planning to invest up to €1 trillion in clean energy by the end of this decade, and many other sources of investment and
ENERGY GLOBAL SUMMER 2021
50. Who gets a bigger piece of the pie?
Elchin Mammadov, Senior Industry Analyst in the UK, Bloomberg Intelligence.
08. One man's trash is another man's treasure
Fabio Poretti, Technical & Scientific Officer, and Ella Stengler, Managing Director, Confederation of European Waste-toEnergy Plants (CEWEP), Belgium/Germany.
14. Set fire to the waste
Diana Baganz, Doosan Lentjes GmbH, Germany.
20. Plants of the future
Filippo Vescovo, Turboden S.p.A., Italy.
24. Waste for energy, not for the oceans Myles Kitcher, Peel NRE, part of Peel L&P, UK.
30. Transforming waste into a resource Mario Marchionna, Saipem SpA, Italy.
54. Euros in their eyes
Daniel Atzori, Research Partner, Cornwall Insight, UK.
58. Fuelling the road to green Brandon Bromberek, Emerson, USA.
62. Land of the renewables
Christopher Smith, Port of Cromarty Firth, Scotland.
68. Digital solutions to improve safety at sea Gaby Amiel, Sennen, UK.
72. Plot the route to success Luis Sabaté, Matrix Renewables, Spain.
76. Tailored to the landscape Marco Frassinetti, EXERGY, Italy.
82. The transfer of knowledge Chum Wai Hoe, Welltec, Denmark.
86. Global news
Reader enquiries [email@example.com]
ON THIS ISSUE'S COVER
ENERGY GL BAL SUMMER 2021
What makes Calgary, Alberta a global energy centre? Alberta is Canada’s largest oil and natural gas producer and the province also boasts some of the country’s best wind, solar, bioenergy, and geothermal resources. Calgary’s energy sector is a recognised leader in the global energy transition and the city’s energy companies will invest CAN$2.3 billion in digital transformation from 2022 to 2024. Find out more about Calgary Economic Development at: www.yycenergyenvironment.com Copyright © Palladian Publications Ltd 2021. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements.
Sulzer Chemtech’s fractionation unit helps to fight plastic waste Common plastics can take centuries to degrade or they do not degrade at all. To break this pattern, solutions are needed to turn single-use, non-biodegradable, non-recyclable plastics into valuable resources. In order to combat plastic pollution, Sulzer Chemtech has worked jointly with a chemical recycling company to develop an innovative process that can considerably decrease the volume of non-recycled plastic waste while reducing the usage of natural oil and gas resources in the petrochemical industry. The novel conversion process consists of two depolymerization steps - to produce alkanes - and a distillation stage to separate different hydrocarbon fractions. Sulzer Chemtech, with its extensive knowledge and expertise in mass transfer technology as well as advanced manufacturing capabilities was selected. High-quality skid-mounted units and plants were supplied with our customer maximizing its speed to market whilst benefitting from substantial cost savings. Because life is fluid – www.sulzer.com
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ENERGY GL BAL
he topic of single-use plastics has been muttered about for years, but has garnered more attention recently. In fact, ‘single-use’ was the 2018 Word of the Year, according to Collins Dictionary, which is indicative of the rise in public concern over plastic waste and general pollution. In the current day in England, you cannot receive a beverage in a restaurant or bar and it be accompanied by a plastic straw; and as of 3 July 2021, drinks products cannot be supplied with single-use plastic straws attached to the packaging. Cross the ocean to the US, and the situation is very different as it depends on which part of the country you are in and the rules in place there. Often, plastic straws can be requested by a patron. But with research finding that Americans are using, on average, 500 million single-use straws every day, it is a mentality that will take time (and regulation) to influence. It is not just the role of governments and policy makers that can introduce change, it is major corporations too. I vividly recall being in India in 2012 and purchasing several plastic bottles of water – since the safety and cleanliness of tap water in the country is questionable, we could only have packaged drinks. These bottles were iconic because firstly, they had eye-catching neon pink lids and wraps, with powerful messages inscribed on the side, and secondly because I couldn’t believe Tata Steel was the manufacturer behind this bottled water. Tata Steel the steelmaking company – where the steel making process has multiple detrimental environmental impacts. Years have passed, and Tata Steel has recently begun a Quit Plastic Campaign, having taken note of the growing plastic pollution problem, and observing that only 10 - 13% of plastic items are recycled worldwide. No longer are plastic bottles being manufactured by the company, and thus
less waste is meeting landfills. On a similar note, to carry a reusable bottle at all times is becoming commonplace in many nations and encouraged in businesses. However, an interesting new creation that has increasingly been replacing plastic water bottles on supermarket shelves is canned water. Aluminium cans are fully recyclable, not to mention that recycling aluminium is one of the cheapest and most efficient materials to recycle, so again we reduce our landfill contributions. Whilst it is true that our household waste is collected like clockwork each fortnight and delivered to extensive landfills, and Peel NRE’s article (p.24) acknowledges that some products may always have a finite life – which has become particularly prevalent during COVID-19 as PPE and single-use products flood our daily lives – the dramatic decline in landfill rates in Europe since 2001 is evident to see. Thermal waste treatment has the ability to not only reduce landfills but also produce energy that will substitute the use of fossil fuels. To read expert knowledge on the topics of waste disposal, recycling, and waste-toenergy, this issue has a series of articles to indulge in, starting with the Confederation of European Waste-to-Energy Plants’ piece on p.8 which details the role waste-toenergy can play in improving Europe’s green objectives. This issue of Energy Global magazine is not all about trash, waste, and unwanted products, it is also packed full of other technical articles covering all manner of renewable energies, including the road to green hydrogen, technological innovations for geothermal across the world, the development of solar power, plus many more. There is much to absorb from this Energy Global issue, and we hope you are able to acquire some new information on the evolving renewables industry.
Kay Hobbs and Simon Courie, TLT, UK, and Harald Wiersema, Holla, the Netherlands, look at the recent trends and developments in Europe’s renewables industry, and how the landscape for clean energy in the region is changing.
020 was a year to remember in many ways and not for the best reasons, but from an energy standpoint, there was one encouraging statistic to emerge. For the first time ever, more electricity was generated by clean energy sources across Europe than by fossil fuels (38% vs 37%), according to a report by think tanks Ember and Agora Energiewende, with Germany, Spain, and the UK achieving this balance at a national level. Is this a sign that the pledge made back in 2014 by former European Commission President Jean-Claude Juncker to make the EU the “world number one in renewables” is coming to fruition? With the climate crisis becoming ever more urgent, and with the Paris Agreement ambitiously aiming to cap global warming at 1.5˚C above preindustrial levels, many people will be hoping so. Analysis by management consultancy Kearney estimates that energy companies are planning to invest up to €1 trillion in clean energy by the end of this decade, and many other sources of investment and
ENERGY GLOBAL SUMMER 2021
funding are coming to the fore. With increasingly ambitious carbon reduction commitments being made by European governments inside and outside the EU as they strive for net zero carbon emissions, coupled with strategies to support and incentivise the transition to clean energy, the outlook is positive. So, what are the trends and developments driving this momentum, and what are the potential challenges that could slow it down?
Growing and emerging technologies Growth in electricity generated from renewable sources has largely been fuelled by wind and solar power over the past decade, according to Eurostat. Sharply falling costs have contributed to this expansion – so much so that the International Energy Agency (IEA) says that solar power schemes now provide the cheapest form of electricity. Legal interventions are also having an impact. For instance, in the Netherlands, a new Environmental Act (enactment planned on 1 January 2022) will enable municipalities to require all new houses to have solar panels installed on the roof. Subsidies have played an important part in helping these technologies become established and proven in many European jurisdictions as well, building trust in wind and solar projects, to the extent that in some countries they have practically been phased out and are no longer necessary to help secure equity or debt funding. An example of this is the UK market where subsidy-based schemes such as the Renewables Obligation have been replaced with auction-based Contracts for Difference, offering price certainty to those projects that offer the most competitive energy price. In other continental European countries where solar and wind infrastructure subsidies are still available, such as in Scandinavia, the guaranteed income they provide is helping to attract significant investment, notably from Asian investment funds. However, wind and solar projects only form part of the picture and new technologies are also gaining traction – not least energy storage, which is key to underpinning clean energy systems, and electric vehicle charging infrastructure (EVCI) projects. Carbon capture technologies are also starting to come into the mix, for instance alongside traditional fossilfuelled power plants to help make them greener and reduce their carbon footprint. Geothermal power, hydrogen fuels, and biofuels are becoming more prominent sub-sectors of clean energy too, although when it comes to bio-based vehicle fuels, the potential for fraud from products that are labelled sustainable (but are not) is an issue to watch out for. Currently this is a market that is in some cases not well regulated, and trade needs to become more transparent, especially as many companies increasingly view it as a means to green their vehicle fleets. Stricter controls are needed and are likely to come into place, which could push prices upwards.
The rise of localised multi-technology schemes Major projects such as large solar schemes in Italy, Spain, and Greece demonstrate the impact that deploying this kind of technology at scale can have and these look set to
ENERGY GLOBAL SUMMER 2021
become increasingly common. However, at the other end of the spectrum, a number of smaller schemes are getting off the ground, and a clear trend towards multi-technology projects, where different clean technologies are co-located on the same site, is gaining traction. These localised hubs pair different types of power generation with battery storage and other energy infrastructure such as EVCI, making power generation and consumption more efficient and 100% clean from end-to-end. Businesses and communities are seeing the advantages of having solar panels, roof-mounted wind turbines, energy storage, electric vehicle (EV) charging points, etc., interconnected on premises or nearby on industrial estates, in shopping centres, or other community spaces. By exporting electricity back to the local community to power homes and businesses or deliver clean energy for EVs, multitech hubs can deliver an affordable and reliable supply, while simultaneously meeting environmental, social, and governance (ESG) goals and reducing the strain on national grid systems. It is a win-win for all concerned. Working with businesses and local authorities on projects like this is another route to market for clean energy developers. Joint ventures are also being seen between municipalities and developers, for instance to upgrade district heat networks or create energy centres, reducing heat loss and building new revenue streams while ensuring that heat generation is green. In countries like the Netherlands where space is limited, governments and local authorities are trying to better plan clean energy infrastructure and distribution – something that has hitherto evolved organically over time and not always in the most co-ordinated way. For example, this could take the form of making ‘zoning’ plans to decide where projects and amenities would be best placed, similar to the way that new housing or commercial developments are planned, and ensuring common infrastructure can be used for multiple local projects. Weighing up how best to meet local need on the one hand must simultaneously be balanced with an awareness of the potential for community backlash against new and imposing projects being sited on people’s doorsteps. Resistance to having projects ‘in my backyard’ remains a real issue in numerous countries, especially in densely populated areas where space is at a premium. Moreover, managing the demands of businesses and local people is becoming more and more complex. Should priority be given to providing power for major global corporates’ data centres, for example, given that they facilitate millions of people to work remotely? Or should priority be given to directly power local homes and businesses? On the whole, European countries are continuing to see a rise in both small, localised clean energy schemes as well as larger sites, but while the energy market across the continent is becoming more integrated across borders, national energy strategies do remain fairly divergent. For example, countries such as France and the Netherlands continue to prioritise or research the feasibility of nuclear power projects while Germany is moving out of this technology. The contrast
between heavily renewable Scandinavia on the one hand and Poland, which still relies on coal, on the other is also a case in point. Indeed, while clean energy is progressing across the continent, it is not doing so with the same technologies or at the same rate across all countries, with northern Europe notably outperforming the rest of the continent.
The evolving funding environment Since energy generation is a leading cause of carbon emissions, continuing to invest in the development and rollout of clean energy technologies is clearly key to tackling climate change as quickly as possible. Highlighting the scale of the challenge, the UK’s Committee on Climate Change recently said that low carbon investment will need to reach £50 billion/yr to put the country on track to meet its net zero targets – the vast majority of which will need to come from the private sector. Multiply that across the whole of Europe and the potential opportunity value is staggering. Thankfully, demand to invest is high and the cost of capital is relatively cheap, enabling developers to get even less mature and higher risk projects off the ground. TLT and Holla expect this high level of investor interest to continue, especially as the COP26 summit later this year re-focusses attention on climate issues and the need for clean energy to play an even greater role in powering our world and delivering a green economic recovery from COVID-19. Much of the investment market remains focussed on bankable projects in mature technologies like wind and solar power. With these technologies now mature and viable subsidy-free, their financing has become extremely competitive and a large proportion of investment is being redirected into other types of projects such as battery storage, carbon capture, EVCI, or heat networks. To what extent other emerging technologies including hydrogen fuels, geothermal power, or biofuels will benefit remains to be seen but these technologies are also increasingly being looked at by investors. Market competition is such that investors are increasingly open to opportunities to diversify into non-subsidised projects in emerging technologies, but here too there is an oversupply of capital chasing projects. Investors may need to change their way of thinking to make investments viable, by adjusting their expectations around risk and returns or coming on board at an earlier stage, even at the consented or greenfield stage. Financing these less mature technologies is still very much a play for private equity investors. Although the industry is starting to see a few debt deals in areas such as biomass, clearing banks and other more traditional financial institutions remain much more comfortable lending to wind and solar schemes. New entrants such as global pension funds are now starting to participate in the debt finance market, driving up competition here too. As this happens, lenders may increasingly look to diversify into emerging technologies, developing new products to manage issues like merchant risk or uncertainty around forward-looking power prices and seize the potential these other sub-sectors have to offer.
If funding channels for critical technologies like energy storage, for instance, are to be fully unlocked, such innovations will be vital.
COVID-19 and supply issues The clean energy sector has not been significantly impacted by the COVID-19 pandemic directly, although there is a strong sense that people have become even more aware of their environment and the impact that humans are having on it. If anything, this has heightened the impetus to better protect the planet and generate energy in a sustainable way using clean technologies. COVID-19 did, however, create some supply chain issues which raise questions for the clean energy sector in Europe. Chief among them is security of supply and how to make supply chains more resilient by potentially moving the manufacture of vital components or the sourcing of materials closer to home, to reduce reliance on suppliers based outside of Europe. After all, one of the principal motivations behind clean energy (other than green concerns) is that it can give European countries more control over their own energy supply, and reduce dependence on gas being piped from Russia, for example. In the UK specifically, the supply chain issue has been exacerbated by Brexit, with the price of photovoltaic panels skyrocketing due to higher import costs, prompting more debate about building production facilities in Britain. Other considerations include how green it is to transport raw materials and finished products long distances by air and sea, such as importing wooden pellets for biomass projects from outside Europe (especially if their sustainability can be brought into question). There are no easy answers: finding good quality, local supply is not straightforward but it is increasingly on the radar as an issue at the European level. With the supply chain under pressure, finding solutions that simultaneously increase resilience, enhance control, and tick ethical boxes are likely to be an increasingly high priority. It will be interesting to see to what extent and how quickly on-shoring or near-shoring of production facilities or new approaches to supply chain management evolve.
The outlook ahead Overall, the outlook for the clean energy sector looks very positive, even though there are many tough challenges ahead as European countries strive to meet demanding carbon reduction goals. But the political dial is moving in the right direction, innovation is continuing apace, finance is flowing in from a variety of sources, issues around sustainability and ESG are gaining prominence, and public opinion is generally supportive. Developers, businesses, local communities, and financiers are increasingly working together to find solutions to the existential emergency presented by climate change and clean energy is front and centre of that fight. The 2020s is set to be an exciting and critical decade for the sector, with Europe continuing to lead the charge on clean energy.
ENERGY GLOBAL SUMMER 2021
ENERGY GLOBAL SUMMER 2021
Fabio Poretti, Technical & Scientific Officer, and Ella Stengler, Managing Director, Confederation of European Waste-to-Energy Plants (CEWEP), Belgium/Germany, highlight how waste-to-energy has a pivotal role to play in moving towards a resource-efficient, low-carbon, circular economy, and how it can help Europe achieve some of the objectives listed in the European Green Deal.
limate and sustainability goals are the two new pillars of the European Union (EU) and they have become the driving force behind almost every decision taken by the new European Commission so far. Shortly after taking office in December 2019, the new executive presented their impressive master plan – the European Green Deal. The Commission is seeking not only to make Europe the first climate-neutral continent by 2050, but is also introducing numerous environmental, energy, and financial proposals in order to make Europe more sustainable in general. This article will highlight how waste-to-energy (WtE) – through the enabling of a full circular economy and contributing to climate protection – will play a pivotal role towards some of the ambitious objectives of the European Green Deal.
Outlook of the waste-to-energy sector in Europe Many of the products used in society are not designed to be easily repaired and are often made from mixed materials which cannot be easily recycled. While we should do everything to reduce waste generation upfront, current production methods and consumption patterns will continue to create vast amounts of residual waste. Even if all waste streams were separately collected, it is not possible to recycle 100% of them. In line with the waste hierarchy, WtE is the most environmentally-sound
treatment for recovering value from residual waste. The circular economy also needs an outlet for residual waste that cannot be recycled in practice. The essential role of WtE is indeed to offer a sanitary service to society, still as necessary nowadays as it was in the past. In the past, waste was burned as a means to deal with infectious diseases, e.g. cholera, and even though society has come a long way, hygiene and health are still strongly related. Today, the world has been reminded by this importance while facing the COVID-19 challenge. Some sanitary items cannot be reused or recycled and it must be ensured that germs and viruses are safely destroyed. WtE is designed to thermally treat residues from households, industry, or businesses by incinerating them under
Figure 1. Number of waste-to-energy (WtE) plants in Europe and amount of waste treated per country in 2018.
Figure 2. Municipal waste treatment in 2019 (EU27 plus UK, Norway, and Switzerland). Source: CEWEP graph based on EUROSTAT figures.
Figure 3. Municipal waste treatment trends in EU27 for 2001 - 2019.
10 ENERGY GLOBAL SUMMER 2021
strictly controlled conditions to generate energy. WtE is in fact one of the most stringently regulated industrial sectors in Europe and multiple studies have found no evidence of a negative impact of WtE on health or the environment. WtE acts as a secure, final sink for pollutants, and it guarantees reliable waste treatment, 24 hours a day, all year round.1 Currently there are approximately 500 WtE plants operating across Europe, treating more than 96 million tpy of residual, non-recyclable waste.
Reducing landfill and supporting quality recycling in the waste management sector Almost half of EU Member States are still heavily reliant on landfilling. Valuable resources are being buried with the risk of contaminating soil and groundwater. In 2019 in the EU27, approximately 54 million t of municipal waste were landfilled, which corresponds to 24% of municipal waste treatment. During 2001 - 2019, landfill rates in the EU27 fell sharply while material and energy recovery rates rose almost similarly. This shows that WtE and recycling are complementary and work very well together to reduce landfilling. Furthermore, with increasing recycling rates, WtE will be needed to also treat the rejects from recycling and sorting facilities, additionally to the residual waste remaining after source separation. This is the case for municipal waste as well as commercial and industrial waste.
More circularity and less unsustainable waste routes On 11 March 2020, the European Commission published its new Circular Economy Action Plan introducing a new set of ambitious proposals for circularity, from product design to sustainable waste management. One of the most timely and important elements of this new communication for the waste management sector in Europe was the announced intention to restrict “exports of waste that have harmful environmental and health impacts in third countries.” This, and the increasing environmental and climate pressures, just confirm that it is the obligation of European society to deal with its potentially harmful waste in Europe, where it is produced. In a shift away from a linear economic model, in 2018 the EU already adopted the Circular Economy Package. The package introduced new waste management targets. For municipal waste, it set a 10% cap for landfilling and a recycling target of 65% by 2035. In a desirable scenario where all these targets would be reached, there will still be a need to treat residual waste that cannot be recycled in an environmentally-sound way. In addition, municipal waste is only a small part of the whole waste volume. In industrialised countries, approximately 50% of the waste treated by WtE comes from commercial and industrial waste, for which there are currently no targets set. CEWEP assessed the capacity needs for waste treatment in Europe in 2035, assuming that the 65%
recycling target of municipal waste would be met and, even more ambitiously, that 68% of non-hazardous commercial and industrial waste would be recycled, and not more than 10% sent to landfills. With this scenario in mind, CEWEP estimated that approximately 126 million t of residual waste treatment capacity would still be needed in EU27 by 2035.2 The current WtE capacity in EU27 is approximately 80 million t and the capacity for co-incineration, mostly in cement kilns, is around 9 million t. This would leave a gap of approximately 30 - 40 million t which must be closed if ambitious recycling and landfill reduction targets are to be met. When there is not enough residual waste treatment capacity, possible side effects can occur such as growth in illegal dumping and open burning of waste. Illegal dumping does not only happen in third world countries, there are some notable examples also in Europe. Through recent years, the media has reported a dramatic increase in cross-border waste trafficking and dumping in Northern France, while Poland has been struggling with waste being stored illegally and set on fire. In Italy, critical situations have also been continuously reported.3 Moreover, an Interpol report also alerted a sharp rise in plastic waste crime4 – and this is just the tip of the iceberg.
Figure 4. Estimated waste treatment capacity needs in EU27 in 2035.
Figure 5. WtE’s contribution to the energy cycle annually.
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It is essential to avoid how that waste could find its way to cheaper or non-sustainable solutions that would interfere with the holistic approach that a good waste management system should always have.
WtE as an effective technology for energy and climate goals The climate ambition is at the very top of the political agenda in Brussels. On 4 March 2020, the European Commission published its proposal on the first European Climate Law which aims at setting in law the EU target of climate neutrality by 2050. On 21 April 2021, a provisional agreement was reached between the European Parliament and the Council, “setting into law the objective of a climate-neutral EU by 2050, and a collective, net greenhouse gas emissions reduction target (emissions after deduction of removals) of at least 55% by 2030 compared to 1990.” In order to align the current legislation with the new and more ambitious targets, several policy tools are now under revision. An important legislative proposal is expected from the Commission in summer 2021 with the ‘Fit for 55’ package. This will include assessments in important cornerstones of the European Green Deal legislation such as the revision of the EU Emissions Trading System and the Effort Sharing Regulation, the revision of the Energy Taxation Directive, the amendment to the Renewable Energy Directive and the Energy Efficiency Directive, the definition of a Carbon Border Adjustment Mechanism, and many more. The Fit for 55 package will cover a wide range of policy areas, where WtE will keep playing an important role towards climate protection and mitigation. As stated previously, the pivotal task of WtE is guaranteeing a hygienic service to society, safely treating the residual, non-recyclable waste produced by communities and industries. At the same time, WtE generates as much energy as possible, substituting fossil fuels for the equivalent production of electricity and heat. Between 11 - 53 million tpy of fossil fuels (gas, oil, hard coal, and lignite) can be substituted, which would emit between 26 - 52 million t of CO2. European WtE plants produce enough electricity to supply almost 19 million people per year. WtE can provide a local source of baseload power that complements intermittent renewable energy sources such as wind or solar, while at the same time making Europe less dependent on fossil fuel imports. More than 60% of WtE plants in Europe are combined heat and power (CHP) plants which provide heat to urban district heating and cooling networks, as well as electricity. WtE plants are able to provide approximately 16 million people in Europe with heat annually. Considerable climate benefits are achieved when WtE plants provide steam to be used by the neighbouring industrial companies that can in turn decommission their fossil-fuelled boilers. Today almost 10% of Europe’s energy covered by district heating comes from WtE. In some urban areas, energy from waste covers more than 50% of the residents’ heat demand – a significant contribution to energy security and air quality, as residents avoid using individual boilers for heating. A large advantage of WtE is also the possibility to rely on programmability and flexibility of energy production, delivering
energy vectors in various forms (electricity, heat, steam, etc.). This also allows for many possibilities of sector coupling and industrial symbiosis to be explored. As an example, some European WtE plants have started to successfully contribute to the decarbonisation of public transport through the production of hydrogen – which can be used afterwards for city buses and waste trucks. By doing so, WtE plants circulate energy through innovative solutions helping to decarbonise two hard-to-abate sectors such as industry and transport. Additionally, approximately half of the energy produced from WtE is qualified as renewable as it comes from waste of biological origin. The exact amount of this part depends on the biodegradable (organic) fraction of the waste input, which is determined by consumer behaviour, local waste management systems, etc. Despite the growing of source separation of bio-waste, a significant fraction of biodegradable matter will still be present in residual waste produced by municipalities but also commercial and industrial facilities. With this regard, approximately half of the CO2 produced by the thermal treatment of residual waste is biogenic, hence carbon neutral. The remaining (fossil) half of energy from waste is recovered as a waste treatment service to society. Other than CO2 emissions savings through fossil fuels substitution, a second important contribution of GHG savings from WtE comes from landfill diversion. Decomposing waste in landfills generates methane – a greenhouse gas 86 times more potent than CO2 on a 20 years perspective. As demonstrated before, even with the recent progress on recycling rates, Europe still landfills significant amounts of municipal waste annually. Considering also commercial and industrial waste, in total, Europe landfills approximately 175 million t of nonmineral waste emitting more than 140 million t of CO2-eq per year. As stated by the German Federal Environment Agency, “Diversion from landfill is the main contributor to GHG mitigation in the waste management sector.”5 Also, a recent UN report, ‘Global Methane Assessment - Summary for Decision Makers’ suggested that the largest potential in Europe for mitigating methane emissions occurs in the waste sector. If these 175 million t could be diverted from landfills to waste treatment options higher in the waste hierarchy, such as quality recycling and WtE, they would deliver 153 million tpy of CO2-eq savings. Further CO2-eq savings can be also achieved in WtE plants through the recovery of valuable raw materials such as metals and minerals from bottom ash – the residues from the combustion process. More than 3 million t of CO2-eq emissions are saved by recovering metals from bottom ash each year. As an example, the amount of iron recovered from European bottom ash each year could be used to build approximately 6000 wind turbines. Finally, with the ultimate goal to reach higher climate mitigation efforts, numerous European WtE plants are also exploring carbon capture usage and storage (CCUS) technologies that have the potential to significantly reduce the carbon footprint of the sector or even to make it carbon negative. These technologies will need further investments to provide effective cost abatement at a wider scale. This will be further explored in the coming years and will have to come
Figure 6. Fuel cell bus powered by hydrogen produced at the Wuppertal waste-to-energy plant in Germany. Source: AWG Wuppertal.
Figure 7. CO2 capture installation at the AVR waste-to-energy plant in Duiven, the Netherlands. Source: AVR.
along with the development of a market and legislation for the removal and use of captured CO2.
Conclusion The WtE sector has, aside from its hygienic task to treat residual waste in a safe manner, a pivotal role to play in moving towards a resource-efficient, low-carbon, circular economy. WtE is an established, secure, and sustainable renewable energy provider for both electricity and heat from residual materials which cannot be further recycled. Landfills are still a big elephant in the room in the European waste management sector but diverting waste from them has numerous benefits, including greenhouse gas mitigation, environmental and health advantages, while boosting recycling and recovery. In light of the EU’s newly set goals of 55% greenhouse gas emission reduction by 2030 and climate neutrality by 2050, the WtE sector will continue to support the European Green Deal and its ambitious targets.
References 1. 2. 3. 4. 5.
CEWEP, Collection of Studies, Health and Environment Section, (June 2021). Calculations peer reviewed by Prognos, (2019). Corriere della Sera, (October 2019) and (June 2020). INTERPOL, ‘Emerging criminal trends in the global plastic waste market since January 2018’, (August 2020). The Climate Change Mitigation Potential of the Waste Sector, Öko-Institut and IFEU on behalf of German Federal Environment Agency (UBA), (2015).
ENERGY GLOBAL SUMMER 2021
Diana Baganz, Doosan Lentjes GmbH, Germany, explains how waste-to-energy can be part of a sustainable global waste management solution.
riven by dynamic economic and population growth, global waste generation is expected to increase by 60% by 2050. In 2016, waste generation in East Asia and the Pacific amounted to approximately 468 million t, but forecasts show that it will increase to 714 million t by 2050. The picture is similar in South Asia, where forecasts predict that the amount of waste produced will increase by half by 2050, compared to 2016. In Europe and Central Asia, waste generation was 392 million t in 2016, while it is expected to increase by 25% by 2050.
Sustainable disposal method for non-recyclable waste Thermal waste treatment is the only proven large scale method to treat nonrecyclable municipal waste in a safe and environmentally friendly way. According to the European waste hierarchy, it is part of a sustainable waste management concept that gives priority to thermal treatment over simple landfilling. By treating residual waste, waste-to-energy (WtE) plants make an important contribution to human health and efforts to reduce humanity’s ecological footprint.
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energy and materials make it possible to exploit fewer primary raw materials and virgin fuels.
Emissions in accordance with regulations With maximum resource efficiency, WtE plants produce low emissions that are in line with the legally required levels according to the EU’s revised Waste Incineration Best Available Techniques Reference (WI BREF) documents. In the process, official institutions monitor the type of pollutants emitted, the emission limits, and the operating conditions in real-time.
How does the waste-to-energy process work? Figure 1. Two-track water-cooled counter-reciprocating grate applied at the 280 000 tpy waste-to-energy (WtE) plant in Harlingen, the Netherlands.
Figure 2. Visualisation of the new WtE plant in Olsztyn, Poland, which will thermally treat 110 000 tpy of refuse-derived fuel from the region when completed.
Since only waste that is at the end of its recyclability or of contaminated nature is fed into the WtE process, it helps to rid the circular economy of hazardous or unusable materials. At the same time, thermal treatment ensures that the residual waste does not end up in landfills. This has a positive impact on the environment, as landfilling produces toxic methane gases (greenhouse gases) that are 86 times more harmful than CO2 over a 20-year period.
Recovery of valuable energy and materials During incineration, the energy contained in the waste is harnessed to generate electricity and heat. Since more than half of the energy contained is of biogenic origin, it is biomass – the use of which helps to achieve renewable energy targets. Using the energy also saves CO2 emissions that would otherwise be produced by burning climate-damaging fossil fuels. The recovered energy can be used for domestic, industrial, or business applications. In addition, the bottom ash produced during incineration is increasingly fed into recycling processes, e.g. used as road construction materials or as additives for cement raw materials and in concrete production. Valuable metals can also be recovered from the bottom ash. The possibilities for recovering
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A modern waste incineration plant consists of a reception and storage area, the combustion chamber with boiler, flue gas cleaning, and water-steam-cycle (WSC). The waste is collected in the tipping bunker and mixed by cranes to ensure uniform calorific values and waste properties. The waste is fed from the cranes into the chutes through which it enters the heart of the WtE plant, which is the thermal treatment. Grate incineration is actually the world’s most commonly used large scale thermal waste treatment technology, successfully deployed in hundreds of plants around the world. This is due to the high flexibility of the grate technology, which can be adapted to changing waste characteristics over the lifetime of the WtE plant. European plant manufacturers such as Doosan Lentjes, an environmental technology company located in Ratingen, Germany, have extensive experience with this technology and have supplied a large number of the WtE plants operating worldwide. On the grate, the waste is incinerated and heats the water in the boiler tubes, which evaporates. The residue from this process, the bottom ash, is collected in a slag bunker for further processing. The steam produced can be extracted for external purposes or is used to drive a steam turbine to generate electricity. A small part of the generated power is used for the self-sufficient operation of the WtE plant, while the larger part is fed into the public grid. Optimisation of the incineration process plays a key role in keeping primary emissions low. Adapting the combustion concept to the specific fuel properties enables uniform waste distribution, movement across the grate surface, and combustion with high ash burnout. Based on the principle of selective non-catalytic reduction (SNCR), ammonia solution (NH3) is injected into the combustion chamber to reduce nitrogen oxide (NOx) emissions. In a downstream flue gas cleaning system, harmful acid gases such as HCl, SO2, SO3, and HF, as well as heavy metals and organic substances such as dioxins and furans are removed. This usually involves dry or wet processes in which additives such as hydrated lime (Ca(OH)2), activated carbon, or sodium bicarbonate are injected into a reactor, which react chemically with the components in the flue gases and neutralise them. After the chemical cleaning process in the reactor, the solid particles are separated in a downstream bag filter. A large amount of the separated particles is fed back into the reactor which improves the consumption efficiency of the utilised reagents. In case of more stringent limit values to be complied with, the flue gases can be denitrified in a selective catalytic reduction (SCR).
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Drivers for establishing thermal waste treatment Drivers for the establishment of thermal waste utilisation as a disposal method are manifold. First of all, there is a need for a clear legal basis in which the framework conditions are defined. This requires a commitment by political decision-makers and a consistent technology promotion. Economic aspects also play a key role because the costs of thermal waste utilisation are usually significantly higher than the very low costs of simple landfilling. Moreover, the acceptance of the people is essential, without which the realisation of the projects will hardly be possible. Growing environmental awareness, with which simple landfilling is not compatible, as well as lack of space are also important drivers for the establishment of thermal waste treatment.
Thermal treatment plants around the globe There are now more than 40 countries in which thermal waste treatment is an established disposal method for the climate- and resource-friendly treatment of residual waste. In addition, there are approximately 150 countries in which the technology is not yet used or is only used to a limited extent. In Western Europe, thermal waste treatment is an established disposal method. A dense network of plants has been established in recent decades, but their advanced age often makes replacement and modernisation investments necessary. In Eastern and South-Eastern Europe, Poland is the market with the highest potential. Seven new plants have gone into operation there in recent years. Another three are in the construction phase. In Warsaw, the largest WtE plant in the country is currently being built with the participation of Doosan Lentjes as technology provider. Once completed, the facility will
Figure 3. The waste-to-energy process.
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process a total of 265 200 tpy of municipal solid waste (MSW) and make a decisive contribution to improving the local disposal infrastructure. With Doosan Lentjes acting as general contractor, another new waste incineration plant is currently being built in Olsztyn, which is scheduled to go into operation in 2023. The new plant will be able to treat up to 110 000 tpy of refuse derived fuels (RDF) from the greater Olsztyn area. The new plant will meet approximately 30% of the district heating demand in the region and will help to compensate for the heat loss that will come with the closure of the local coal-fired Michelin power plant in the near future. This will ensure a continuously reliable and environmentally-sound district heating supply for the local citizens. Positive developments can be observed in some countries around the world, e.g. Indonesia. There, the Indonesian government is in the process of realising reliable legal framework conditions for waste incineration projects. At present, however, the country’s overall economic situation and the inconsistency of the authorities still stand in the way of the actual development of such projects. In Australia, the attitude towards thermal waste utilisation has changed significantly in recent years. The reasons for this are the Chinese import ban on plastic waste and the significant increase in landfill taxes in some Australian states. The country’s first WtE plant is currently being built in Perth and is scheduled to start operation at the end of 2021. Other projects are in various stages of development. It can be assumed that these projects will be concentrated in the metropolitan regions, as there is not enough space to build more landfills there. Australia is thus gradually becoming an attractive market for thermal waste treatment. Interest in thermal waste treatment is high worldwide. This is encouraging, as this technology is the only proven large scale solution for the environmentally friendly and safe disposal of the world’s increasing volumes of non-recyclable waste.
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Filippo Vescovo, Turboden S.p.A., Italy, explores the revolution in the waste-toenergy industry and how Organic Rankine Cycles can help unlock a large potential for smaller, decentralised plants.
mong the mix of power generation plants, waste-toenergy (WtE) plants are likely the only ones in which the generation of energy is not their main duty. These plants are often considered the last resort for ‘waste’ material that could not be reused, repaired or recycled, thus the waste is disposed and their energy recovered.
Güres: WtE in the Aegean region This is the case for Güres Energy, a WtE plant located in Manisa, not far from the Aegean coast in Turkey. Güres is the biggest egg-integrated plant in the country, with more than 4 million chickens. But more than that, this plant produces an average of 350 - 400 tpd of chicken manure: a big challenge for the company since it was dealing
with very high costs for the sanitation, elimination of smell, and eventually disposal of the manure. In 2017, Güres decided to invest in an integrated WtE plant, an ambitious first-of-a-kind project in which the target was to eliminate the chicken manure through its incineration and then to use the heat from combustion to generate 2.3 MW of electric power. In October 2021, the Güres Energy plant will complete its third year of full activity, being able to eliminate all the manure coming from the company’s chickens and to generate more than 40 GWh of electric power and 150 GWh of useful heat.
A technological innovation Prior to Güres, there were several examples of industrial plants for the chicken manure incineration, most of which were
Figure 1. The Ortadogu plant in Turkey recovers heat from landfill motor gases.
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very large scale – such as Foster Wheeler in the US and Eye in the UK. The main challenges for these plants included the aggressive nature of their combustion fumes, their high ash content, and the high investment and operational cost – all of which were common themes for the vast majority of WtE plants. Güres designed a whole new system to overcome these problems. In an industrial landscape dominated by steam boilers and steam turbines, the Turkish company designed a system based on two different technologies: FFA thermal oil heat recovery boiler.
FFAn Organic Rankine Cycle (ORC) for the power generation part.
Thermal oil heat recovery units With a waste heat recovery unit (WHRU) it runs similar to a thermal energy plant where the heat of the hot combustion gasses is transferred to a heat carrier fluid that transfers the heat to a user (in Turboden’s case it is a turbine for the conversion to electricity). While the common way is to employ water, Güres chose the opposite route for its plant and decided to proceed with thermal oil.
Thermal oil has various advantages compared to watersteam, such as a lower pressure level, no phase change (from liquid to vapour), and its simplicity of operation and maintenance. Another key feature is the temperature level of the thermal oil, which at its highest point reaches 300˚C – a level sufficiently low to avoid corrosion problems and expensive practices such as the employment of special materials or the replacement of boiler parts every three to five years.
Organic Rankine Cycle The second main innovation was the selection of the ORC in order to transform the thermal power of the hot oil into electric power and hot water. ORC is a technology that has been around since the late 19th century, but only saw its diffusion in industrial applications in the 2000s. The principle of electricity generation by means of an ORC process corresponds with the conventional Rankine process: FFPressurisation of the fluid (through a pump).
FFVaporisation of the fluid (in an evaporator) by means of the heat transferred by the hot thermal oil.
FFExpansion in the turbine to generate mechanic power, then transformed into electricity by a generator.
FFCondensation of the fluid to the liquid form (through a condenser).
Figure 2. Güres Energy plant in Turkey, an ideal demonstration of Organic Rankine Cycle (ORC) technology in waste-to-energy (WtE) applications.
The substantial difference lies in the fact that an organic working medium (such as silicon oils, refrigerants, or hydrocarbons) is employed instead of water. Its working principle and the different components of the ORC process are shown in Figure 4. In the case presented here, Güres decided to purchase a Turboden 22 CHP model – an ORC unit that can directly transform 10.5 MW of heat into 2.3 MW electricity and 8 MW of hot water at 70˚C. Its main features include: FFVery high efficiency, >21% electrical and 98% total net CHP efficiency.
FFLow operational cost, due to the low pressure employed, with no certified operator needed.
FFLow maintenance cost, as a result of the non-corrosive nature of the fluid employed, as well as the low RPM of the turbine and therefore to its direct connection without the need of a reduction gear.
FFVery high flexibility of the system – ORC systems can work between 20% - 105% of its nominal load. The Güres plant has been operating its unit at different loads according to the quantity of waste and to the energy consumer, both variable in time. Figure 3. MIROM plant – a 3 MW ORC in Belgium working with MSW – is a good example of power generation and district heating working with different seasonal configurations.
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FFNo water consumption. ORC systems do not employ water and do not consume water, especially if the condenser
water circuit is a closed-loop like the Güres plant.
Size counts: How ORCs can help out In WtE plants, one of the main challenges is the high operational and investment cost of its equipment, thus for this reason, WtE is often not realised (remaining mere waste incinerators) or their size is incredibly large in order to reduce the specific cost. An example is the large number of medical waste incinerators in which the thermal power produced (typically from 1 - 5 MW thermal) is not utilised but Figure 4. Simplified scheme of a WtE plant with thermal oil and ORC technology. rather dissipated to the atmosphere, with the further expense of electric power (to run air coolers) or water. This situation is mostly linked to the high operational cost of classic steam cycles such as water treatment and the obligation to have a certified operator on-site. Case studies such as Güres suggest that these obstacles could be solved by employing thermal oil and ORC systems, in order to create power streams where currently energy is wasted. In this regard, it may be useful to look back at what happened in the early 2000s in the biomass-to-energy market in the EU, especially Austria, Italy, Germany and Latvia, where Turboden realised more than 200 ORC plants sized between 200 kW and 2 MW. In these projects, ORC technology was crucial to solve the operational challenges posed by the small size and, on the Figure 5. Turboden ORC systems are designed to contribute to the path other hand, to easily find thermal users in order to go with towards decarbonisation. CHP co-generative configurations, where not only the electric power, but also the hot water could be utilised (i.e. drying or district heating). should be available locally and plants should be built nearby This was similar to what was achieved at Güres, where to heat users for higher total efficiency rates. the 70˚C water output is employed in the drying of the This would help to reduce the impact of waste logistics on manure and in the heating of the chicken cages (in winter). road transport and would make low carbon heat and green power available to local communities. ORC and the quest for decentralised WtE In addition, as separate and selective collection of plants municipal solid waste should be prioritised, the availability of Could the world expect an increase in smaller WtE plants? residual waste will most likely decrease in the future pushing The example of Güres and many others suggest that figures to smaller size. In fact, a small WtE plant is more flexible to may work in some specific contexts, and definitely the cope with waste variations/shortages, which also mitigates implementation of thermal oil and ORC systems instead of financial risk. classic steam cycles (which still remain competitive in larger Turboden has awarded and built 21 ORC plants with a plants above 10 MWe) can help out. total installed power of approximately 60 MW. This figure There are many other criteria to consider, such as the cost covers a variety of installations in various WtE plants of energy, the policies and regulations of the specific country, including medical, industrial, animal waste, and sludge and the geographical position of the plant (i.e. distance to incinerators. Most of these plants were installed in the past electrical or thermal user). five years, with power installed between 1 - 13 MW. In the near The new circular economy principles introduced by the EU future, Turboden also plans to add some old biomass plants are having an impact on the design of next generation waste that are being updated in order to receive a fuel mix that treatment plants. For instance, there is a clear preference for includes both biomass and RDF waste (in ratios from 2:1 to CHP systems and considerable emphasis is given to proximity. 1:1), a trend that may contribute as well to the diffusion of Both those principles together suggest that the waste treated decentralised WtE plants.
ENERGY GLOBAL SUMMER 2021
Myles Kitcher, Peel NRE, part of Peel L&P, UK, looks at the UK’s energy from waste market and how the movement towards net zero is driving change within the industry.
espite the technology having its critics, energy from waste (EfW) is still widely used across Europe to treat municipal waste. In 2019/2020 in the UK alone, more than 11 million t of waste was collected by local authorities as feedstock for EfW facilities. This was used to generate approximately 7769 GWh of energy, enough to power all the washing machines in the UK for a year.1 However, leading the way is Finland, where over half of the country’s municipal waste was treated in EfW facilities in 2019.2
What is energy from waste? Put simply, EfW, or energy recovery, is a way of creating energy from material that is no longer useful. While it is generally used to create electricity, it can be used to generate other forms of energy such as hydrogen and syngas. In addition to energy generation, the technology has benefits for the environment and waste management. It helps to avoid waste going to landfill, which produces methane – a greenhouse gas 25 times more potent than CO2. After treatment, the volume of the waste is significantly reduced, leaving only ash which can be used as an aggregate in the construction industry.
The changing landscape It is clear that EfW will remain a vital means of managing non-recyclable waste and a source of low carbon energy for the foreseeable future.
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However, the landscape is changing which is driving innovation in the sector. With legally binding net zero carbon emissions targets in 2050, it is inevitable that there will be some form of carbon tax introduced, with EfW likely captured by the UK Emissions Trading Scheme (ETS). Like the introduction of the landfill tax, this will drive change within the industry as greater efficiencies and an even lower carbon intensity are sought after. A carbon tax would drive further innovation in the sector. Removing the non-biogenic fraction from the waste stream will become even more important and increase the focus on plastics. There will be added emphasis on the collection of all plastic, which will increase levels of recycling but also incentivise more effective means of recovering energy from the unrecyclable fraction. A generation of EfW facilities will soon start coming to the end of their life and this capacity will need replacing, albeit with more efficient and more innovative facilities. This is even
Figure 1. Aerial view of the Protos site in Cheshire, UK.
Figure 2. Artist’s impression of the Protos site.
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more important as the impacts of Brexit mean (quite rightly so) that the UK is dealing with more of its waste on its shores and not exporting the problem overseas. Technologies are still needed to treat waste that cannot be recycled. COVID-19 has highlighted the ongoing role that plastic will have to play in society, for example in PPE and other medical products. Even in a circular economy many products have a finite life.
Driving innovation This innovation is already starting to happen. At Protos, Peel NRE’s strategic energy and resource hub in Ellesmere Port, Cheshire, UK, the company is developing its first Plastic Park which will deal with a wide range of plastic wastes, providing solutions for materials where recycling has not previously been a viable option. It will cluster together technologies to recycle different types of plastic and recover energy from plastic that has reached the end of its life. The Protos Plastic Park is set to be the home of the UK’s first plastic-to-hydrogen facility. It will take plastic that would otherwise go to landfill and turn it into hydrogen that can be used in cars, buses, and HGVs, helping to improve local air quality. It will use pioneering DMG technology developed by Powerhouse Energy – a form of advanced thermal conversion technology that takes unrecyclable plastic and recovers the maximum amount of energy. First, the non-recyclable plastics are broken up and shredded into similar size pieces which are fed into a thermal conversion chamber. The plastic is then heated at high temperature in a reduced air environment which prevents combustion. The output at this stage is a clean syngas. Next, the longer chain hydrocarbons in the syngas are broken down into the constituents of methane, hydrogen, and carbon monoxide. The residue from this process is made up of inert material which can be used to construct roads and has the potential to support agriculture. Any remaining contaminants are washed and filtered out in the gas clean-up process, leaving a small volume of brine which can be treated as waste water. When the facility is in full hydrogen production mode, it can process approximately 40 tpd of waste plastic. This is just over one-third of the plastic waste generated in Liverpool, UK, in the same time period. Using this waste, it will generate approximately 2 t of hydrogen – enough fuel for 60 lorries to travel 250 - 300 miles. This is equivalent to 48 MWh which can power over 47 000 homes each day. Providing more front-end sorting and a more sustainable solution for unrecyclable plastics will improve the overall economics and therefore drive higher levels of recycling.
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the role it could play in EfW is starting to become part of the discussion. Resources and waste management company, Viridor, recently announced that it plans to link into leading hydrogen and carbon capture project HyNet North West to capture carbon at its largest EfW facility in North West England. This is part of the company’s plans to become the first net negative emissions waste company in the UK by 2045. Peel NRE has partnered with Bioenergy Infrastructure Group (BIG) on the Ince Bioenergy Carbon Capture and Storage project (InBECCS). The project was awarded £250 000 by the Department for Business, Energy & Industrial Strategy (BEIS) as part of the Net Zero Innovation Portfolio. It will fund the design of a carbon capture demonstration facility at Ince Bio Power, the largest waste wood gasification plant in the UK, which is located at Protos. Ince Bio Power currently takes commercial waste wood which would otherwise go to landfill and uses it to generate enough energy to power over 42 500 homes. The project will use chemical technology from C-Capture to capture over 7000 tpy of carbon. The InBECCS project will pioneer the first negative emissions project in the North West and could be ready as early as 2025.
Figure 3. Artist’s impression of plastic-to-hydrogen facility.
The future of energy from waste? Figure 4. Ince Bio Power – a waste wood gasification plant – at Protos.
Peel NRE has plans to roll out Plastic Parks and the Powerhouse Energy technology across the UK.
Generating low carbon energy EfW is not going to make huge inroads into energy generation needs. In the first instance it is about finding ways to manage waste more sustainably. If this also creates electricity then great, but if there is a better alternative, such as creating transport fuel to offset diesel or even aviation fuel, then this should be the focus. This is where the circular economy meets net zero. Increasing efficiency will also bring a greater focus on district heating. Approximately 20% of UK carbon emissions are created by heating buildings and it is simply not feasible to say all heating can be electrified. Combining EfW with district heating could improve the efficiency of a typical facility, while helping developers meet exacting new building regulations.
Carbon capture Carbon capture and utilisation or storage is something also likely to be seen alongside EfW. The UK Government has committed to creating at least two carbon capture clusters by the mid-2020s and while the focus has been on how this could help industry decarbonise and kick start a hydrogen economy,
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The EfW sector will continue to evolve. More new technologies will come to market which can maximise the value of waste and reduce the impact of waste management on the environment. As the sector evolves it is important that the industry is given time to prepare. Transitionary procedures, or at the very least, reasonable notice, will be essential to prevent any unintended consequences of an immediate step up in EfW gate fees, such as increased fly tipping. It cannot be forgotten that EfW is primarily there for good sanitation, so any change needs to be carefully managed to ensure that effective waste management is maintained. Later this year the UK will host the 26th UN Climate Change Conference (COP26) in Glasgow, Scotland. As the first major economy to commit to net zero carbon emissions by 2050, all eyes will be on how the UK plans to deliver on this ambitious target. Home grown technologies such as Powerhouse Energy will demonstrate how the UK is leading, not only on more innovative and sustainable ways to manage waste but also in the production of clean fuels. There is still a future for EfW but innovation and improvement must continue. If this is achieved, the value from resources will be maximised and it will play an important role in the net zero future.
Department for Business, Energy & Industrial Strategy, Energy Consumption in the UK (ECUK) 1970 to 2019, (October 2020). Confederation of European Waste-to-Energy Plants, ‘Latest Eurostat Figures: Municipal Waste Treatment 2019’, (March 2021).
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Mario Marchionna, Saipem SpA, Italy, outlines a selection of sustainable solutions that can be utilised to optimise waste management.
echnology innovation, one of Saipem’s strategic pillars, is a key lever to drive the company faster towards novel and fully decarbonised energies. Saipem acts as an innovative global solutions provider to the energy industry, which means the company provides varied tools to its clients to solve their complex problems, in particular those presented by the energy transition. It is a real mutation process along with all the actors of the energy sector that are accelerating on the transition whilst simultaneously reducing the weight of their traditional business. In this respect, selective technology access is decisive to allow the company to offer the most competitive solutions. Saipem is pursuing several diversified actions with a strategy that reflects four main pillars, along with natural gas that is the cleanest and least carbon dioxide-emitting fossil source and will continue to play a relevant role in the energy transition, especially in the short- to mid-term. The main pillars include the following:
FFRenewables: offshore renewable energies are particularly relevant for Saipem, especially offshore wind and floating solar parks. Their systemic integration is decisive, also through the production of hydrogen that could act as an energy source capable of providing greater independence from the intermittent nature of most of renewables.
FFDecarbonisation of carbon-intensive industries: energy still produced from fossil fuels but the related climate-impacting emissions are significantly reduced. This may impact not only the oil and gas downstream industry but also other carbon-intensive and energy-intensive industries (i.e. steel, cement, and waste treatment).
FFBiomass conversion and circular economy: embracing new models that create value and safeguard the environment by improving the management of resources, eliminating waste through better design, and maximising the circulation of products.
FFHydrogen: it can fill an important role as a totally decarbonised gas that could progressively substitute natural gas. It is evident that the four areas are tightly interconnected, thus cases of overlap among them can be frequently encountered. The different targets are pursued through a mix of efforts with different maturity: innovation activities aimed at intercepting new and potentially disruptive technologies and related markets (scouting activities are continuously underway to identify potential
partners with whom Saipem can co-operate); technologypushed business development efforts aimed at helping clients to re-design their carbon footprint; and already structured commercial projects where the innovative approaches find full exploitation. As a consequence of this approach, Saipem has identified specific opportunities for providing cutting-edge, sustainable solutions that will help the company’s clients meet the demand for a low-carbon future. These opportunities are mapped over a timeline that starts with Saipem’s current operations (projects that may be awarded over three years) and runs into the midand the long-term (Figure 1).
of oil residues and the treatment of different types of waste – such as industrial, toxic, hazardous, and municipal. Moreover, a floating waste to fuel project was also conceptualised and engineered at the start of the last decade. The company also has a strong interest in plastic recycling, with the disposal and recycling of plastic wastes key topics for which a comprehensive solution needs to be found and developed soon. With plastic recycling, a potential new and important market is growing but many challenges need to be faced. As a major international contractor, Saipem has started the analysis, planning, and implementation of plastic recycling projects. Several very diverse stakeholders are involved, including Circular economy and waste management plastic producers, waste sorters and transporters, municipalities, Embracing new models that create value and safeguard the etc., and it is important to realise the contribution expected environment by improving the management of resources, from each of them as well as the state-of-the-art nature of this eliminating waste through a better design, and maximising developing business with its different possible operating models the circulation of the products, is one of the pillars of Saipem’s (Figure 2). There is no one-solution-fits-all approach and there strategy towards a more extensive decarbonisation. is a great need for players who can have a holistic, high-level Technology is a key enabler to all four elements of a circular vision to the problem while maintaining the ability to implement economy – i.e. reduce, reuse, recycle, and remove – and the specific projects tailored to regional situations with specific development of solutions to sustainably treat any kind of waste operating and financial constraints. produced by urban, commercial, and industrial activities (oil In this respect, and in the frame of Saipem’s Innovation and gas, petrochemical, cement, iron and steel, pulp and Factory activities, the company has performed structured paper, etc.), with their consequent valorisation to energy and/or interviews with several stakeholders in order to better realise the valuable products, is becoming an important asset. different viewpoints so as to further refine its understanding of Saipem has already gained significant experience in the the matter. field of power generation and this has matured over the years. As an ambitious final target, Saipem envisages a modular In terms of power generation, this is related to both gasification facility that could bring together the different technologies to treat all type of plastics in one location, to produce new plastic, chemicals, power, and steam to ensure the circularity of plastics. The facility will seek the highest energy efficiency possible and will capture CO2. With this aim in mind, the company is investigating several technology options in order to develop different solutions to be flexibly deployed according to the specific situations. Among them include the following: clean combustion with CO2 recycled (also managing the CO2 issue strictly linked to waste management); gasification to produce syngas to be converted to chemicals; and pyrolysis Figure 1. Empowering the energy transition through technology innovation. Towards with product recycled to the steam decarbonisation: Saipem’s roadmap. cracker in order to produce the olefins monomers which can make plastics production by polymerisation possible.
Figure 2. Plastic waste treatment: from collection to final use.
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In the aforementioned context, it is worth mentioning the License Agreement with ITEA (a company of the Sofinter Group) to produce, through ITEA’s proprietary ISOTHERM Pwr® flameless oxy-combustion technology, steam, electricity, and pure CO2 by flexible
use of low-ranking fuels such as waste, heavy oils, petcoke, and several other feedstocks. The agreement gives Saipem access to the technology for several applications, allowing the company to offer original and circular sustainable solutions to its clients. A typical example is represented by the use of waste streams as feedstock to generate energy and valuable chemical products such as urea or methanol, but also for the optimisation of the hydrogen value chain. Since 2017, Saipem has investigated applications of the ITEA technology for the urea plant value chain – CO2 can be efficiently produced by using waste streams, with an additional overall energy production. This innovative concept allows synergies within an industrial complex and Figure 3. A typical example of plastic waste. decreases its carbon footprint. With similar principles, ITEA technology may be used to produce CO2 for methanol plants and other refinery products, helping with the decarbonisation of the petroleum industry.
Plastic waste treatment The ITEA oxy-combustion technology is also being investigated with the aim of studying new processes for the disposal of plastic waste that is difficult to recycle, such as plastic scraps (called Plasmix in the Italian market), and the integration of this step in a broader process with CO2 capture and possibly reutilisation. Until recently, plastic recycling from differentiated waste has been rather limited. In fact, according to recent studies, only 30% of material collected is recycled, leaving the problem of Plasmix (non-recyclable mixed plastics consisting of a group of heterogeneous plastics included in post-consumption wrappings which cannot be recovered as single polymers) unsolved. In Europe, most of these plastic scraps are thrown away and lost; gate fees are very high for non-recyclable mixed plastics sent to energy recovery plants in some European areas (e.g. Italy, where this type of waste amounts to more than 500 000 tpy). Among the several opportunities to better exploit it, Saipem has examined the possibility of coupling its experience in ITEA technology to produce water, energy, and pure CO2 that can be also opportunistically sold to the market under particular situations, without directly emitting to the atmosphere (Figure 4). To put this into perspective, the process will allow for the amount of reused material to be increased; furthermore, it is very flexible, relatively simple, and is able to be exploited in plants with reduced dimensions. Another advantage of the technology is that it provides the opportunity to process Plasmix along with sewage sludge deriving from wastewater treatment – a material which is difficult to dispose of at present. Saipem has experimentally verified the ‘slurryfication’ capability on different samples of mixed plastic waste in order to allow a homogeneous feeding to the oxy-combustion reactor. Technical-economic feasibility studies are underway
Figure 4. Novel technologies for plastic scraps conversion: Oxycombustion.
together with a comparison with other potential technologies for the treatment of this feedstock. The slurryfication process is now being scaled up in collaboration with Corepla, an Italian national consortium, for the collection, recovery, and recycling of plastic packaging waste. The next steps will be about experimentally demonstrating the concept on a significant scale (approximately 5 MWth) and examining different CO2 conversion technologies for integration in the overall scheme. In addition to the oxy-combustion, other approaches to plastic recycling are currently under careful investigation in order to directly recycle the product of plastic waste treating to an olefins-producing unit or to fuels production units. In this respect, Saipem has an agreement with a technology provider in order to co-develop a pressurised gasification technology to produce syngas from waste. As regards to pyrolysis technologies, Saipem has recently entered into an agreement with Corepla and Quantafuel, a Norwegian technology provider, to jointly promote circular economy models for plastic waste, and to seek building chemical recycling plants throughout Italy. Work is in progress and Saipem is confident that its cuttingedge and robust EPC experience will be able to close the loop of waste plastic recycling and conversion, in a holistic fashion, by creating the right connection between the waste recycling world with the chemical (oil and gas) one.
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Figure 1. A ground view of São Gonçalo solar PV plant in Brazil.
Umberto Magrini, Head of Engineering and Construction at Enel Green Power, discusses the latest innovations driving the current solar revolution and why solar photovoltaics are set to be a long-lasting success story within the renewables industry.
olar photovoltaics (PV) are leading the energy transition through a significant and fast evolution of the technology’s main components, availability of more operating data, and reliable production modelling tools. The field of solar generation is also rich with innovations that allow the technology to become increasingly widespread.
PV module The continued implementation of silicon-based cell enhancements, such as passivated emitter rear contact (PERC) and half-cell interconnection module technology, has paved
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the way for higher average module efficiencies. The use of larger wafers (182 mm and 210 mm) has resulted in higher module power classes of 500 W and above, as well as a larger size area. Improvements in all fields result in an increase of module area efficiency, with today’s mainstream p-type mono-Si based modules reaching efficiencies of 21%, and increasing to 22.2 ‑ 22.5% within the next five years. The PV industry is currently in the final phase of p-type dominance, characterised by the use of p-type multi and p-type mono substrates. From 2024, however, all signs point to a dramatic shift to n-type substrates, with n-type based modules
including Heterojunction (HJT) providing the highest power modules with today’s efficiencies of approximately 21.5%, which will increase to approximately 23% within the next 10 years. Looking to the next PV module generation, the mass production of Si-based Tandem cells and modules is expected by around 2025, starting with module efficiencies of 22.5% with a high margin for improvement (up to 28 - 30% of efficiency). In the current solar scenario, most modules are monofacial, but the share of bifacial modules is expected to grow to approximately 55% in the coming years. In 2016, Enel first began using bifacial modules, starting operations at its La Silla solar plant in Chile. With this pilot project, Enel deeply analysed the advantages of the bifacial technology and customised the mathematical model for energy estimation and the geometrical aspects of the design. Following that experience, Enel started using bifacial modules in large PV plants such as São Gonçalo
in Brazil and Magdalena II in Mexico. For Enel today, with few exceptions, the bifacial module is the preferred solution for guaranteeing the lowest levelised cost of energy (LCOE).
Inverters Today, inverters and their control system are the real brains of solar PV arrays, representing a key tool for efficient solar power plant operation and management as well as grid services. The size of these inverters is continuously increasing, especially for ultra-large utility scale plants, while at the same time producers of string inverters are also offering higher power solutions, with the largest reaching up to 350 kW to compete in the field of large scale power plants. Interest in string inverters continues to grow in utility scale applications. While central inverters are, and will remain, popular in the industry, string technology has become
increasingly appealing for Enel over the past few years. Utility scale systems larger than 20 MWdc are still typically suited for central inverters but there have been instances where large scale projects – even as large as 100 MWdc – have considered string. Enel, after a small pilot in Brazil, immediately implemented string inverters in large PV plants such as Magdalena II. Today, centralised and string inverters guarantee very similar LCOE values, so the specific characteristics of the project determine which type of inverter is best suited. From a material point of view, Silicon carbide (SiC)-based semiconductors, although still not available at commercial level, are highly promising. SiC products offer higher power density and are more lightweight than traditional inverters. The thermal behaviour of SiC inverters means they do not have to reduce output to avoid overheating but can feed power at ambient temperatures over 50˚C. Less overheating translates to smaller fans for cooling inverters, which helps to reduce the total weight. The cost is currently the main issue with SiC inverters. While studies have shown that SiC inverters have lower LCOE and higher improved system efficiency, the solar industry has a strong focus on lowest initial cost, making, at least for the moment, SiC inverters less competitive than traditional ones. Micro inverters and solar optimisers, which are widely used in small scale rooftop applications, could see broader implementations in the near future, even for large scale applications.
Grid forming Inverters provide the interface between the grid and energy sources such as solar modules, wind turbines, and energy storage. When there is a large disturbance or outage on the grid, conventional inverters will shut off power to these energy sources and wait for a signal from the rest of the grid that the disturbance has settled and it is safe to restart, also known as grid-following. As wind and solar account for increasing shares of the overall electricity supply, it is becoming impractical to depend on the rest of the grid to manage disturbances. Gridforming inverters are an emerging technology that allow solar
and other inverter-based energy sources to restart the grid independently. The new roadmaps highlight recent innovations in gridforming inverter technology. They identify the challenges for researchers and operators of the small isolated grids or microgrids where this technology could be piloted. In the short-term, research opportunities exist for creating new grid-forming hardware, software, and controls; redesigning regulatory and technical standards; and developing advanced modelling techniques. Building on these, the authors envision a future where grid-forming inverters are integrated into electric grids of steadily increasing size and complexity over the next 10 - 30 years.
Inverter reliability As the solar PV industry matures and asset owners focus more on total system lifetime cost – and not just initial costs – inverter reliability becomes increasingly important. Inverters require more maintenance activities within a solar plant than any other system component because they are expected to operate over a wider set of environmental and electrical conditions for longer periods of time. Furthermore, inverters contain hundreds of internal components, operational subsystems, and circuits. Meanwhile, models constantly change as do operational requirements, which is evident from grid code updates and local jurisdictional requirements. Quality control, laboratory and factory testing, as well as controlled field testing, are the best alternatives to long-term field exposure for evaluating product reliability and performance.
Tracker PV support structures are split between fixed and trackers, with the latter being predominantly horizontal single axis supports. Trackers increase energy production by 15 - 25% compared to fixed, with an additional increase in production expected with the implementation of a backtracking control algorithm for irregular terrains and a diffuse radiation algorithm considering bifacial applications. Wind tunnel testing has become a key driver for tracker design optimisation and cost reduction, while the market is split between 1 Portrait (P) and 2P configurations based on the project’s constraints. As longer rows might be the answer for further optimisation, multiple slew drives are expected to introduce stiffness and ensure tracker reliability.
Database and data reliability
Figure 2. An aerial view of São Gonçalo solar PV plant in Brazil.
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The collection of solar data plays a prominent role in the design, financing, and energy forecasting of PV systems, with plants requiring reliable information about solar and climatic data, including their variability over time. Several properties are carefully investigated during the scouting of potential PV sites, such as grid access and land availability, but solar radiation is without question one of the first
selection criteria that has a huge and direct impact on energy production. Variability of the solar resource occurs not only seasonally, but it may change from year to year (inter-annual variability). This is one of the reasons behind the success of satellite-derived models with respect to the ground measurements. Satellite-derived models generally own more than 10 - 20 years of high-quality solar radiation data all around the world, with a good level of accuracy thanks to strong validation of satellite-based models and several solar data providers present in the market.
Physical and mathematical model of a PV plant The physical and mathematical models widely used in the development phase have been developed by several research centres within the PV sector and are fully validated. In addition, most of the input data used are from external data providers, such as solar resource information, and are certified by them. The rest of the input for the design is selected by using reliable data coming from suppliers of the main equipment and engineering department experiences matured over more than 10 years. The best simulation of a standard large scale PV plant can be carried out by using reliable mathematical and physical models that can calculate the losses related to the interaction between the intrinsic characteristics of the main components of the PV plant and the environment data. These models also allow for the addition of new and challenging levels of complexity considering innovative solutions such as bifacial modules, floating plants, multi-orientation layout, as well as mixed equipment configurations. Further improvements can be obtained by choosing different objective functions, which can also capture the evolution of market energy prices as well as the generated revenues and their added value.
Figure 3. La Silla solar PV plant in Chile.
Operation and maintenance future development To guarantee the profitability and the performance of a huge portfolio, efficient and effective operation and maintenance (O&M) is required. To do this, Enel is building its O&M solar strategy on three pillars: robotisation, data driven maintenance, and automation. Some examples of the applications already implemented include: the use of drones to identify panel and string failures; analysis of the strings’ I-V curves to identify faults by machine learning approach; and optimisation of the soiling management, with automated monitoring and scheduling of cleaning activities. These are just the first steps towards an automated solar O&M model. The industry as a whole is further developing analytics solutions for predictive maintenance approach. On top of that, more sensors in the field will be necessary upstream of the inverter itself: applying specific sensors in the field on PV trackers and inverters will provide more and more precise information in order to identify the inefficiencies affecting PV plants at component level, anticipating the maintenance activities and therefore avoiding having to fix the failures only after they have happened.
Figure 4. Magdalena II solar PV plant in Mexico.
Conclusions Solar PV has, since its inception, repeatedly surprised scientists and engineers, overcoming all growth expectations and demonstrating an outstanding capacity to break all previous technological taboos. Without question, solar technology has reached a level of maturity that makes it one of the cheapest sources of energy available at industrial scale in the world. The unique characteristics of being produced for direct conversion with no mechanical or thermal energy in the middle, modularity, which allows it to be easily utilised in a portable device as well as in a ground mounted giga plant, and ubiquitous presence, mean that a long story of success can, without a doubt, be predicted for solar PV towards a fully sustainable global energy footprint.
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Figure 1. Developing the ecosystem around solar energy will boost Brazil’s economy.
Jamie MacDonald-Murray, Lisarb Energy, UK, justifies why solar energy is strategic to Brazil’s sustainable recovery, and why diversification of the country’s energy mix is an important action.
atin America’s largest economy was already in a fragile state when the global pandemic added to its list of woes. However, despite being hit by a wave of corporate bankruptcies and soaring government debt, the latest data shows that the economy is growing at a faster rate now than when the pandemic struck at the end of 2019. Some economists are now revising their growth forecasts upward. However, there are still many risk factors that could hold Brazil’s economy back, including rising unemployment and inflation. The price of some essential goods, including food and energy, is increasing. Investment is widely recognised as a recipe to reawaken economic growth and, post-pandemic, Brazil can boost its economy by enabling investment in green energy infrastructure. In short, enabling the growth of solar will boost
jobs and help to limit the cost of energy. While energy demand is growing, the government recognises that it cannot build a strong economy without investing in reliable infrastructure, and for that it needs outside help.
Brazil must transition away from hydro Brazil is the world’s second largest producer of hydroelectric power, but it still has an energy problem. While hydropower accounted for 70% of the country’s electricity generation in 2018, its primary source of renewable power is becoming less effective than it once was. Brazil needs to urgently diversify its energy mix to counter the power outages that are becoming a feature of daily life. Many of Brazil’s hydro plants in the Amazon River basin are run-of-the-river, where electricity output is susceptible to rainfall levels and hydrological variation. As a result, droughts
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and reduced rainfall levels are threatening security of supply. In an attempt to mitigate power outages, gas-fired thermoelectric plants have been built as dispatchable back-up. Another issue is that due to their reliance on specific geographical features, the hydro plants are fundamentally in the wrong place. While many of Brazil’s hydroelectric plants are located in the north of the country, most demand is on the south-east coast. Large distances between sources of supply and demand regions create reliability challenges. Furthermore, many of Brazil’s older hydroelectric power stations, constructed in the 1960s and 1970s, now need major investment to modernise. And plans to add generation capacity by building new mega dams have been severely criticised by environmentalists, as they can submerge landmasses and threaten river ecosystems, water quality, and biodiversity.
Liberalising clean energy markets Brazil’s administration is pushing ahead with economic reforms. There are moves to liberalise and deregulate markets as well as to reduce bureaucracy. Indeed, the government has announced its tax reform plan, which is aimed at simplifying what is widely recognised as one of the world’s most complex tax systems. The International Renewable Energy Agency (IRENA) and the Latin American Energy Organization (OLADE) announced they will boost ties to put the renewables-driven energy transformation at the heart of Latin America’s economic recovery following the COVID-19 outbreak. IRENA’s recent ‘Future of Solar Photovoltaic’ report highlighted that the region’s solar energy capacity alone could grow by a factor of 40 by 2050 to more than 280 GW, as a result of an abundant resource endowment and strong enabling policies. ABSOLAR, Brazil’s solar photovoltaic (PV) trade body, forecasts that by 2050 solar PV will contribute 125 GW of generation capacity, or 38% of the country’s energy needs. In a further pro-business boost to the solar market, Brazil’s administration has also scrapped import duties on foreign manufactured solar equipment – a move designed to encourage
inward investment. Previously, solar modules were taxed at 12% and inverters at 14%. For UK businesses investing in Brazil, the removal of import duty makes it feasible to specify systems where the financial value of UK-manufactured parts and professional fees comprise at least 20% of the total project cost. Under these circumstances, projects qualify for debt finance covered by sovereign guarantee, which can reduce the overall cost of finance.
Embracing the energy transition With huge expanses of land in the north east, high levels of insolation, and lower levels of rainfall, Brazil’s geography is now better suited to solar PV than hydropower. In addition, the grid infrastructure is already in place in this region to accommodate growth in solar parks. With an abundance of sunshine and falling river levels, many see solar PV as the natural successor to hydroelectricity. Introducing new policies to support the green bounce will create jobs in clean energy and boost the wider economy by providing Brazil’s businesses with reliable, inflation-proof power. The financial returns from high-yielding solar parks in Brazil are already an attractive proposition for investors. Strong supporting policies for green energy will ensure that key financial centres like the City of London, UK, and New York, US, will continue to back Brazil’s green energy resurgence.
Business is driving demand for reliable, clean energy
Preserving cash is the key to survival for every business, and when revenue is harder to come by, that means careful expense management. For many businesses, buying energy typically ranks among their top three costs, alongside wages and office expenses. Aside from inflation, there are other pressures affecting the cost of energy in Brazil. First, energy demand is increasing. Domestically, consumers are buying more electrical appliances than ever before, and the use of air conditioning has increased dramatically. Sales of AC units tripled between 2005 and 2017 while electricity consumption has risen by 237% in the same period. These issues add up to increased pricing volatility in power markets, which creates uncertainty for businesses as they struggle to manage their expenses. Businesses want long-term, fixed-price energy contracts that can save them money as well as enable more accurate budgeting for expenditure. To regain control of their energy supplies, some companies have even invested in purchasing their own solar plants for electricity production so that they can avoid having to buy energy from utilities at market rates. However, the majority of businesses cannot afford to develop their own solar power plants. For them, power purchase agreements (PPAs) can deliver the clean, affordable, predictably Figure 2. Brazil is the world’s second largest producer of hydroelectric power. priced power that they need.
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PPAs address pricing volatility and ESG concerns PPAs are energy supply contracts that guarantee production and fixed prices, with no variation in tariffs. An energy customer agrees to buy an amount of energy from the developer, which is generated by a renewable asset. Typically, the contracts are for a period of 15 - 25 years. The developer funds the plant and allocates the energy production to energy consuming units agreed by the customer. The customer – also known as the offtaker – in turn guarantees the purchase of the energy across the agreed period. There are multiple benefits for businesses that buy their energy through PPAs. Over the life of the agreement, energy procured through a PPA is cheaper than buying it on the wholesale market. Due to the falling cost of solar modules, solar PPAs can deliver one of the cheapest sources of electricity. Currently, businesses are eligible for tax rebates for producing their own energy and additional rebates for using renewable energy as part of their supply. What offtakers also value in PPAs is that they can accurately forecast their future energy costs because the tariffs are fixed. As well as the economic benefits, switching to renewable energy is increasingly important for businesses that have set net-zero goals for decarbonisation. The offtaker’s finance team should know that there is no capital investment required on behalf of the business; the balance sheet will improve as operating costs come down with no increase in debt. There should be no fluctuation of energy
costs and once signed, PPAs are not subject to changes in government policy. Regular power outages are a constant reminder that Brazil’s energy landscape is a looming problem. Buying solar power through a PPA gives businesses back their security of supply. Increasingly, businesses are also motivated to procure clean energy by environmental, social, and governance (ESG) concerns. For operators of solar parks like Lisarb Energy, signing up offtakers using PPAs before a project starts ensures that there is a commitment to buy the energy produced, which enables finance to be raised to develop the project.
Re-energising the economy Developing the ecosystem around solar energy will boost Brazil’s economy by addressing some of the key issues the country faces as it emerges from the pandemic. The solar industry is already creating new jobs; ABSOLAR forecasts 147 000 new jobs will be created in solar during 2021 alone. Developing solar projects will reduce the cost of electricity for the population, increase business competitiveness by reducing their costs and providing access to reliable sources of power, as well as boosting government income. The growth of PPAs is encouraging investment in renewable energy projects by providing revenue certainty for projects in the absence of government subsidies. To sum up, solar energy is strategic to Brazil’s sustainable recovery; ensuring the industry’s success will re-energise the country’s economy.
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Figure 1. Total Lubricants’ on-site solar photovoltaic (PV) system in Singapore.
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Lorenzo Mancini, Total Solar Distributed Generation, Singapore, sheds light on the important role of rooftop solar and how it is helping corporates reach their renewable energy goals in Asia Pacific.
he RE100 is a global initiative bringing together multinational companies which have committed to sourcing their operations exclusively by renewable energy (thus RE100) by a given target deadline. The average target deadline across all RE100 is 100% renewable energy by 2028 – which in corporate terms, is the day after tomorrow. It currently has 260+ members (new companies sign up every year), spanning all industries and business. The initiative originated in the US, successively expanded to Europe, and progressively to the rest of the world, since most if not all the member companies have a global footprint and are eager to align their sustainability targets across the world. However, this proved to be easier said than done. In Europe or the US, the electricity market is liberalised and it is possible for a corporate buyer of electricity to sign an agreement with a renewable energy developer (either private or public) which will sell it the green energy generated by its solar or wind farm, utilising the existing electricity grid infrastructure to effectively deliver the electrons, and paying the electricity company a set fee for transmission and distribution charges. The agreement utilises a power purchase agreement (PPA) type contract, which has become increasingly standard and commonplace. In some cases – as is the case of large internet giants – corporates have sought to have solar or wind farms specifically built to cater for their energy needs, thus fulfilling a further additionality requirement, i.e. their actions have increased the overall pool of green energy generated. As more and larger solar and wind farms were built across the US and Europe, this mechanism has allowed many corporate giants to already declare their US or European operations 100% renewable. Target achieved, then? Not quite.
Renewable energy sourcing in APAC While many of the RE100 companies are financial institutions or telephone and internet companies which do indeed have the bulk of their operations in the
Western hemisphere, many more are manufacturing companies whose operations are spread worldwide, and who produce and commercialise a large (and increasing) share of their goods in Asia. According to the RE100 2020 Global Progress Report published in December 2020, 42% of RE100 new members in 2020 are from the Asia-Pacific region. The problem they face is that, apart from several exceptions (Singapore), the electricity markets in Asia are typically still government-owned monopolies which control both electricity generation and transmission and distribution (T&D). Historically, the same was also the case in Europe or the US – building the electricity generation, transmission, and distribution infrastructure of a country is an inherently uneconomical proposition, as it must guarantee the same level of service at the same price to all corners of the country, that only a state-owned enterprise can tackle and accomplish. Once the infrastructure is in place however, most if not all Western countries have seen the advantage of breaking down the electricity monopoly (much in the same way most countries have broken down the telephone monopoly and allowed private companies to compete), retaining the ownership and control of the grid only as a market enabler while allowing private generating companies (gencos) to compete on price to supply electricity to the grid company and to private companies. This liberalisation process is not a fast one, as it requires not only a sleuth of legislative and regulatory framework to be put in place, but also a substantial change in mentality on the part of the government-owned generating companies, which have never had to face the market before. How do you determine which percentage of the cost of electricity in US$/kWh is generation cost, due to the generating
Figure 2. Danone Aqua’s on-site solar PV system operations in Indonesia.
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company, and how much is T&D cost, and should be attributed to the T&D grid? Several Asian countries have embarked on this process, or at the very least have acknowledged they will need to do so at some point in the future, but very few – most notably Singapore, as mentioned – have made headway. When building an economic industrial powerhouse, as China has acheived in the past decades and Indonesia and Vietnam are doing now, with GDP growth rates of 7 - 8%/yr, the priority is keeping up with the increased demand imposed on the T&D grid which require upgrades to avoid blackouts and brownouts, not liberalising the electricity market. That is the case even in countries such as Vietnam where international agencies such as the US Agency for Economic Development (USAID) are lobbying strongly for the government to liberalise the electricity market. In this situation, it is not surprising that the RE100 members have identified Argentina, Australia, China, Indonesia, Japan, New Zealand, Russia, Singapore, South Korea, and the Taiwanese market as the most challenging markets for achieving 100% renewable electricity. Does that mean the ever-growing number of RE100 will have to shelve their sustainability ambitions in the Asia-Pacific region indefinitely? No, there is another possibility.
The answer is on the roof What if corporate ABC, keen on greening its operations, could generate its own green energy to power its manufacturing plant on-site, without going through the T&D grid? It would not be putting any additional burden on the grid, so there is no reason why the regulator should not allow it.
But what if corporate ABC does not have a free plot of land to install a solar photovoltaic (PV) system on? Well, what it most certainly has is a roof, and odds are that it is just sitting there empty, waiting to be colonised by solar PV modules. Finally, what if corporate ABC does not have the faintest clue on how to build and efficiently operate a solar PV system? Well, there is also an answer also for that – get an expert to do it. As corporate electricity consumers are committing more and more to renewable energy sourcing, global energy players are refocusing their operations and expanding their solar and wind energy investments to address the customer requirement. Rooftop solar (RTS) is an important part of this capability. The energy company will commit the full investment and install a PV system on the roof of corporate ABC. The energy company will operate the PV system (including any operation and maintenance which might be required) and will recover its investment and its profit margin selling electricity to corporate ABC at a price cheaper than the grid electricity price, on a long-term contract. Given the low price of electricity in SouthEast Asia, this has only become possible in the last couple of years thanks to the declining price of PV modules and inverters. The advantage of an on-site PPA model vs corporate ABC installing and operating its own PV system are several but the main one is strategic, i.e. corporate focus – it makes more sense for corporate ABC to keep focusing all its resources on its core business than dispersing them on a solar PV project.
Case study Danone Aqua, one of the largest manufacturers of bottled water in Indonesia, has taken numerous initiatives to reach clean energy and green environment goals. Along with Total Solar, Danone has completed the solarisation of three plants in Java, Indonesia. The first building of the Klaten plant was completed with Commercial Operation Date (COD) reached on 28 August 2020. The project size is 2900 kWp, with 8340 Canadian 350 Wp panels and 23 SMA 100 kW inverters installed. The estimated annual energy production of the project is 3.9 GWh, saving 3081 tpy of CO2. The second building of the Banyuwangi plant was completed and COD reached on 8 September 2020. The project size is 378 kWp with 1080 Canadian 350 Wp panels and six 50 kW SMA inverters installed. The estimated annual energy production of the project is 572.68 MWh, saving 452 tpy of CO2. The third building of the Mekarsari plant was completed and COD reached in May 2021. The project size is 2112 kWp with 5216 Trina 405 Wp panels and 33 Sungrow 50 kW inverters installed. The estimated annual energy production of the project is 2.7 GWh, saving 2133 tpy of CO2.
A solar boom Rooftop solar is seeing an unprecedented boom in SouthEast Asia in recent years as an important step towards the sustainability of manufacturing operations of multinational companies without imposing additional requirement on the grid operator. The on-site solar PV system is not intended in any way to replace the grid electricity supply but rather to complement it, thus to some extent also relieving the demand on the T&D.
Figure 3. Construction of rooftop system in the Philippines.
Figure 4. On-site solar PV with excess energy export capability.
The regulator has also seen the advantages deriving from rooftop solar as a fast and easy way to allow for corporates to have access to green energy, and has sought to incentivise its development typically by putting in place a net metering or feed-in tariff mechanism, whereby the grid operator agrees to buy from corporate ABC any excess solar energy generated on Sundays or Public Holidays and not consumed on-site. This is technically easily achievable by replacing the traditional electricity meter at corporate ABC’s site with a bi-directional meter capable of measuring incoming and outgoing energy flows. While the technical side of things is relatively simple – the PV technology is proven and tested, technical improvements are incremental in terms of efficiency and have already likely reached a plateau – the financial and business side of managing long-term (20 years is the typical duration for a corporate PPA project) is not straightforward and requires deep pockets and a long-term view. In practical terms, this means that although currently in many developing markets such as Indonesia, Vietnam, or the Philippines amongst the main on-site PPA solar developers are local engineering, procurement, and construction (EPC) companies funded by local banks, over time they will likely be edged out by energy majors which have decades-long experience of long-term, low rate of return project management. After all, who would be better to commit a roof on a 20-year contract; a company founded a couple of years before or an energy major which has been around a century, through thick and thin, revolutions, war, earthquakes, and tornadoes?
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Tadgh Cullen, Statkraft, UK, investigates the current state of play for energy storage in Europe.
020 may be looked back on as the year battery energy storage became truly viable in Europe and the UK. It was the year that saw many countries achieve a balance between the three fundamental requirements to make energy storage a success: increasing energy market volatility, effective single-buyer market design (explained next), and a growth in investor confidence. In the UK alone, 2020 was the year that surpassed a gigawatt of installed battery storage, with a further pipeline of 15 GW. Single-buyer markets are now either operational or in the consultation stages for many of the countries that are explored throughout this article. That means designing a market that incentivises investment into energy storage through short- to medium-term bankable contracts. This has, and will allow for, a quicker ramp-up in renewable energy penetration while minimising the need to curtail renewable generation due to market or technical reasons.
Ireland Ireland is in a unique position in Europe. It is an island with limited interconnections, has a 43% average renewable energy penetration, and is currently running a trial to increase the cap on the percentage of grid power being supplied by renewable sources to 75%. This is a significant challenge, and to manage this stability concern, Eirgrid – the National Transmission Network Operator – has designed a market that incentivises investment into energy storage by giving investors confidence that their investment in energy storage will make a guaranteed return in the first few years of operation. The market is designed to reward flexible and fastresponding assets that improve deviations in system frequency. This means that during periods of either too little or too much generation on the electricity grid, batteries will respond quickly to either consume or export energy to help rebalance the system. The fast frequency market is technology-neutral; however, its technical requirements mean that few technologies other than battery storage can partake. The new market ensures embedded flexibility in the electricity system while reducing the reliance on fossil fuel inertia-producing generators and allows for a continued increase in renewable energy penetration.
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UK The UK appears to be at the beginning of what will be a significant energy storage deployment. Legislation and government supported single-buyer markets appear muddled, however, markets tend to evolve to solve their own problems, and that is exactly what is being seen in the UK. An increasing pool of credit worthy third-party power purchase agreements (PPAs) are entering the market, offering contracted revenues to battery assets. These floor contracts, tolling or rental agreements allow for up to 60% of the required project revenue to be contracted, giving certainty in terms of revenue, allowing debt to be raised, and making battery storage projects fundable. It is a big step forward, and the UK is a world leader in terms of this unsubsidised market. But the country could be doing more and needs to do more to achieve its renewable energy targets.
The UK Government supported Contract for Difference (consultation document published March 2020) focuses on increasing renewable energy capacity without incentivising flexibility, which is going to become progressively important in an increasingly constrained market. The fact that a PV project will not receive income during negative pricing hours may not be enough to promote co-located PV and energy storage deployment, but may be enough to render standalone PV projects unattractive.
The Netherlands With the current Stimulation of Sustainable Energy Production (SDE+) subsidy regime in the Netherlands, there is no incentive for solar power to be dispatchable. It is simply a subsidy and offers no value to flexibility. However, the Netherlands, along with Belgium, Austria, France, Switzerland, and some German regions take part in a common frequency market which dictates that up to 100% of their frequency power requirement can be sourced from the common market, with the remainder being sourced locally. This market is much larger, and less likely to saturate as quickly as other frequency markets have done. However, being a daily contracted market in fourhour segments, there is great uncertainty in relation to the future clearing price, and therefore it is currently a high-risk investment. If this market evolves to offer longer-term contracts, and resolves the double taxation/charging issues, the uptake in investment could see a mass deployment of energy storage across central and western Europe.
Spain Figure 1. A battery site in Dörverden, Germany.
Figure 2. A battery storage facility in Killathmoy, Ireland.
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The Spanish renewable energy market is incredibly compelling. In 2020 alone, 3.2 GW of solar PV was installed, with a further 1 GW anticipated to be installed every year for the next decade. However, the picture is not so favourable when it comes to
storage. There are three balancing markets in Spain: Primary, Secondary, and Tertiary Reserve. The Primary Reserve, being the market requiring the fastest response time, is in theory the market most suited to energy storage, however, this market is unpaid and requires mandatory participation for energy generators. Historically, this approach has been incredibly successful (and cheap) as it has put a requirement on fossil fuel generators to turn up and down its generation to manage grid stability. The challenge is, as renewable energy penetration increases, the amount of Primary Reserve available decreases, reducing security of supply. To combat this (and without affecting the unpaid Primary Reserve), the Spanish government has opened a consultation process to create a new two-tier capacity market. If it proceeds as planned, zero carbon emitters will receive a 5 - 10 year contract, while carbon emitters would receive less favourable one-year contracts that will importantly prevent the incentivisation of new-build fossil fuel generation. The ambitious plan has a target to open the new market later this year and, if successful, could see a swift deployment of energy storage.
Italy Italy is a very interesting prospect in Europe for energy storage. The country is trialling a new innovative singlebuyer market. The Fast Reserve market will be piloted to operate alongside the existing primary regulation. The first auction closed late last year, with the successful projects contracted to begin participation on 1 January 2023. A
significant guarantee payment was required to participate, with penalties applied to this payment if milestones are not met. The new service will target very quick responses to frequency deviation and will offer four-year contracts. It will be a fluid market, with each energy storage project required to be available for 1000 hr/yr, with participation in other markets allowed. This market, coupled with an extremely volatile merchant market in certain zones, allows a battery storage project to have an attractive mix of contracted and uncontracted revenue, and should see the beginning of a significant role out of battery energy storage nationwide.
Where next for energy storage in Europe? It is inevitable that energy storage will continue to become an investable technology, and the signs are already starting to be seen that countries are coming to terms with how to incentivise flexibility within their energy system. With multiple countries taking different approaches, the next 12 months will be an incredibly interesting time for this sector. As the world ‘hopefully’ enters the post COVID period, countries will look back and realise the learnings of the last 18 months, in particular the knowledge that a significant reduction in carbon emissions is possible. It is apparent that populations now have greater clarity on the things that are important. It is important for every country to commit to the EU Green Deal and the fact is, there is a massive opportunity to clean up our electricity systems and build a system for tomorrow, not selfishly for yesterday.
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global climate push to decarbonise industries most in need of environmental remediation could turn hydrogen from a cottage sector into a behemoth with the help of government subsidies that attract investment to meet net-zero emissions targets. This revolution may provide a US$2.5 trillion investment opportunity between now and 2050 for utilities, equipment makers, and other businesses seeking to curb emission intensity. According to BloombergNEF (BNEF) annual demand growth for hydrogen could reach 7% per year, and hit 7% of global energy use by the middle of the decade. This article will take a look at which companies are best placed to benefit from this rapid growth.
Hydrogen investment to boom amid huge potential in climate fight Hydrogen is necessary for the world’s largest carbon emitters – the US, China, and Europe – to achieve their net-zero climate targets by 2050 - 2060, as the molecule can aid hard-to-abate industries to decarbonise. Investment opportunities are plenty, though subsidies are essential for the initial scale-up and to achieve cost reductions, since hydrogen production is very expensive. As a storage mechanism, hydrogen has several advantages over lithium-ion batteries, namely greater energy density. This is important, considering the need for long-term seasonal storage of intermittent renewable power and easy transportation to places where the energy is needed from sites with ample green resources. Hydrogen can also utilise most existing natural gas infrastructure, though modifications would be needed to handle large amounts.
Hydrogen investments look set to skyrocket Despite several false starts in the past decades, Bloomberg Intelligence (BI) believes that investments in hydrogen are set to surge. Between 2018 and 2020, investments averaged approximately US$1.5 billion/yr, according to BloombergNEF. This will likely increase to US$38 billion/yr between 2019 - 2040 and US$181 billion/yr from 2041 - 2070, according to International Energy Agency (IEA) projections.
Elchin Mammadov, Senior Industry Analyst in the UK, Bloomberg Intelligence, explores which companies could benefit from the incoming hydrogen revolution.
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Europe leads the way but others set to catch up
Figure 1. Global cumulative investments in hydrogen (US$ billion).
Globally, Europe is leading the way on the number of announced hydrogen projects – with 126 out of 228 – as a result of pro-climate policies in place across the continent, including net-zero emissions targets adopted by governments and companies. This is followed by Asia (46), Oceania (24), and North America (19). However, BI expects other less-densely populated regions with better solar and wind resources, as well as access to seaports, to catch up over time as the technology matures and the cost of production and transport decline. Saudi Arabia and North Africa, for example, have a high potential to be hydrogen suppliers for Europe. Similarly, Australia could start exporting hydrogen to Japan and South Korea, while Latin American countries such as Chile could supply the US.
Hydrogen boom reliant on subsidies
Figure 2. Anticipated grey hydrogen share decrease, 2019 - 2070.
The majority of that amount will initially go toward investments in ramping up the production of hydrogen, while future spending on distribution may only account for between 12% and 16% through to 2070. Looking ahead, hydrogen will have a better chance of broader uptake compared to past attempts thanks largely to governmentbacked green stimulus policies. The EU (as well as many of its member states), South Korea, and Japan have already developed hydrogen strategies, and the UK is set to follow later this year. The EU green hydrogen package envisages a cumulative €150 billion (US$183 billion) investment by 2030 deploying at least 6 GW of electrolyser capacity to produce up to 1 million t of renewable hydrogen by 2024, and 40 GW of electrolyser capacity to make up to 10 million t by 2030.
Early movers to gain edge as growth begins Companies across many industries are making early bets on hydrogen to gain a competitive edge before the market matures. Among energy, chemical, and metallurgic companies, Shell, Ørsted, Engie, Neste, Linde, and SSAB are making more progress in expanding hydrogen activities than Gazprom. Within the industrials group, Alstom has a head start over CAF and Siemens. Equipment suppliers such as Plug Power, ITM Power, and Faurecia should also benefit from the hydrogen boom.
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While the future for hydrogen is bright, governments will need to develop new policies and regulation. At least initially they will need to offer subsidies – such as Contracts for Difference, high carbon prices or low taxes – and faster deployment of low-cost renewable energy, in order to address the chicken-and-egg problem facing hydrogen producers, infrastructure operators, and potential consumers. To encourage regulated utilities to invest in hydrogen networks, authorities will have to allow grid operators to include hydrogen-related works in their rate base. Subsidies have been used to great effect across Europe to scale-up offshore wind and turn it into an established power generation technology. As costs keep falling due to economies of scale and increased knowledge, the industry should become less reliant on subsidies. The potential hydrogen revolution will require a similar approach to get it off the ground.
Hydrogen surge would be from a low base with uncertainty over future prices The next five years’ expected surge in global hydrogen investment will be from a very small base. Key drivers will likely be supportive government policies, decarbonisation efforts by companies themselves and, over time, the declining cost of the technology amid economies of scale and the learning curve. Wind and solar generation and electrified transport look set to continue to dominate green investments over the course of the remainder of the decade, but the share of hydrogen and carbon capture and storage (CCS) could increase by the mid-2020s from the 2018 - 2020 level of approximately 0.4% each. Yet, uncertainty on future carbon prices, government subsidies, economies of scale, and the learning curve means there is a huge variation in forecasts for hydrogen investment and consumption growth. Wood Mackenzie estimates
that a cumulative US$1 trillion of capital investments will be needed by 2050, while the IEA’s projections imply approximately US$2.5 trillion during that period. Similarly, there is also a wide variation in projections for hydrogen demand in 2050, with BloombergNEF being significantly more bullish with approximately 1.4 Gtpy in its maximum demand scenario and 0.7 Gtpy in its strong policy scenario opposed to 0.2 Gtpy projected by Wood Mackenzie and 0.3 Gtpy by the IEA.
Transport may eclipse industry, while heating may remain niche Industrial processes, including oil refining, account for nearly all of hydrogen consumed today, but this may decline to approximately one-quarter by 2050. By contrast, the proportion of hydrogen used by the transportation sector could rise by as much as 43% in the next 30 years, according to one of BNEF’s scenarios. BNEF also predicts that the electricity generation industry is set to increase its share in hydrogen demand to 31%, while only 8 - 9% of the fuel may be used for space and water heating in buildings by 2050. Of the announced hydrogen projects tracked by the IEA, just 1% is currently operational. Among the planned projects by capacity, the main investments would be in areas focused on industrial applications, chemicals, as well as injecting hydrogen into the natural gas grid. By contrast, the less popular projects are those that want to decarbonise power generation, heat production, and mobility.
Hydrogen theme basket Overall, BI tracks companies with direct exposure to the development of major market themes that cross industries and regions. The company’s dedicated ‘Hydrogen Theme Basket’ includes 43 companies that are expected to generate a meaningful portion of revenue by 2025 from the manufacture of fuel cells and electrolysers, as well as other activities related to producing, transporting, storing, or using hydrogen fuel to reduce global carbon output. Among the BI hydrogen theme basket constituents, Enapter, FuelCell Energy, Plug Power, and Doosan Fuel Cell have generated the highest return in the past year, while Pressure Technologies, Nikola, Snam, and Air Liquide were relative underperformers. Looking ahead, hydrogen presents significant growth opportunities for a wide range of sectors, including utilities (Ørsted, RWE, Snam), manufacturers (NEL, Plug Power, Alstom), refiners (Neste), transport (Nikola), metals and mining (Anglo American, ThyssenKrupp), and other companies seeking to curb emission intensity (Linde, Equinor).
Hydrogen stocks dive due to rising rates after stellar year, but value chain outruns global benchmarks After strong 2020 returns, companies included in BI’s hydrogen theme basket underperformed the MSCI ACWI Index of developed and emerging markets in 1Q21 amid a broader green market sell-off, due to rising interest rates and
Hydrogen supply set to turn from grey to green Hydrogen supply will likely surge in the next decade due to strong regulatory support and subsidies, which Bloomberg Intelligence (BI) believes to lead to economies of scale. Green hydrogen is set to displace the widely used grey one, while blue and turquoise hydrogen will require the deployment of carbon capture, utilisation and storage (CCUS) technology. BI understands that water supply constraints, costly components, and relatively low-energy density will all be key challenges for hydrogen in the coming years. The growing output of green hydrogen, which is produced from renewable electricity by electrolysis of water, will help displace grey hydrogen, which is made from coal and gas using the steam reforming process. The blue variant relies on capturing emissions in their gaseous form, while the turquoise hydrogen process is more energy intensive but produces carbon in a solid form. The commercialisation of CCUS technology at scale will be vital for the mass deployment of blue and turquoise hydrogen as both use natural gas (prone to methane leaks) as a feedstock. Currently, BASF and Aker Solutions are seeking to build pilot installations to produce turquoise hydrogen, while Equinor plans to develop blue hydrogen projects. Between two-thirds and three-quarters of green hydrogen production capacity could be deployed to displace grey hydrogen used in oil refining, ammonia and methanol production over the next decade. After that, BI believes green hydrogen will target new sectors, including metallurgy, heavy-duty transport, and the storage of surplus electricity. As a result, the share of low-carbon hydrogen is set to increase to 75% by 2040 from approximately 12% today, according to the IEA.
concerns over project returns. Shares of almost two-thirds of peers fell in 1Q21, dragged down by utilities, renewables, and hydrogen pure-plays. Regionally, North America and Asia fared better than Europe. However, though the hydrogen industry is in its infancy, shares of companies exposed to the technology have outperformed the MSCI All Country World Index (MXWD) since the start of the pandemic. This is partly due to a global climate push and the increasing momentum in ESG-focused investing. In the BI hydrogen theme basket, pure-plays (those making fuel cells and electrolysers) have outperformed other subgroups, with Europe leading returns versus other regions. The broader green market stock sell-off in 1Q21 took some of the shine off the hydrogen industry’s outperformance when compared to the broader market.
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Daniel Atzori, Research Partner, Cornwall Insight, UK, details the role of hydrogen in Italy’s green recovery, as the country’s economy recovers from economic stagnation.
n 30 April 2021, Prime Minister Mario Draghi submitted Italy’s Recovery Plan to the EU Commission. As the country embarks on its green revolution, this article will explore whether Italy will succeed in becoming a leading hydrogen player. The appointment of Mario Draghi, former Head of the European Central Bank, as Prime Minister on 13 February 2021 has provided the country with a unique opportunity to embark on a virtuous path of a sustainable recovery after having been heavily hit by the COVID-19 pandemic following decades of economic stagnation. According to projections by the Organisation for Economic Co-operation and Development
(OECD), Italy, whose GDP suffered a -8.9% loss in 2020, is expected to rebound 4.5% in 2021 and 4.4% in 2022.
The recovery plan The recovery plan for Europe is centred on the EU’s €750 billion Next Generation EU, which is the largest ever stimulus package financed through the EU budget. The largest chunk of the Next Generation EU fund will be composed of the Recovery & Resilience Facility (RRF), which in turn includes €312.5 billion of grants and €360 billion of loans. At least 37% of the resources need to contribute to climate action and environmental sustainability and 20% to the digital transition. EU countries
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needed to submit their draft national recovery and resilience from 15 October 2020, with final drafts sent by 30 April 2021. Italy is the largest recipient of the initiative, having been assigned €191.5 billion from the Next Generation EU Fund, plus €30.6 billion of the complementary fund, for a total of €222.1 billion. The so-called Piano Nazionale di Ripresa e Resilienza (PNRR), which the Italian government presented to the country’s Parliament in April, includes several far-reaching reforms in sectors such as public administration, justice, regulatory simplification, and competition. In accordance with the EU’s environmental priorities, the green revolution and ecological transition represent the largest share of the resources allocated by Italy, as shown in Figure 1. The total resources allocated to the green revolution and ecological transition amount to €69.96 billion when including Italy’s PNRR, React EU, as well as the complementary fund. These resources will be shared among the protection of land of water resources; energy efficiency and requalification of buildings; energy transition and sustainable mobility; sustainable agriculture and circular economy; as detailed in Figure 2.
Italy as a hydrogen hub? The Draghi government has created a new Ministry for Ecological Transition, as France and Spain have already done. The newly formed institution is led by physicist Roberto Cingolani, former Chief Technology Innovation Officer at aerospace and defence multinational Leonardo.
Figure 1. The recovery and resilience plan: Next Generation Italia (€191.5 billion). Source: Italian Government.
Figure 2. Italy’s green revolution and ecological transition. Source: Italian Government.
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The minister has clearly pointed out that Italy aims to invest in low-carbon hydrogen. In 2020, the previous government led by Giuseppe Conte published preliminary guidelines for a hydrogen national strategy. A consultation, launched on 24 November, closed on 21 December 2020. It is now hoped that the hydrogen national strategy, which is expected to be published shortly, will provide Italy’s energy sector with a clear direction of travel. Following Europe’s hydrogen strategy launch in July 2020, Italy has ramped up its efforts to develop a hydrogen economy. According to the PNRR, Italy will develop flagship projects in hardto-abate industrial sectors. In particular, the decarbonisation through hydrogen of Italy’s steel industry, which in Europe is second only to Germany, is seen by the government as a priority. The PNRR also aims to create hydrogen valleys, particularly in brownfield sites. The creation of hydrogen valleys will prioritise former industrial areas already connected to the electric grid, developing 1 MW - 5 MW electrolysers powered by renewable energy sources. In the first phase, hydrogen will be then transported to local industries either by truck or through existing gas pipes blended with methane. The government’s plan also recognises the importance of enabling the adoption of hydrogen in heavy-duty transport by developing approximately 40 refuelling stations, starting from the routes most frequently travelled by trucks, such as the Brenner Pass and the Turin-Trieste Corridor. Hydrogen mobility applications also have significant potential across the railway system. In Italy, approximately one-tenth of the railways are still operated by diesel trains. The government envisages the conversion to hydrogen of railway lines that are challenging to electrify and have high traffic, particularly in regions such as Lombardy, Apulia, Sicily, Abruzzo, Calabria, and Basilicata. According to the PNRR, the most advanced feasibility projects are situated in Valcamonica (Lombardy) and Salento (Apulia). For what concerns hydrogen railway infrastructure, the government intends to develop synergies with refuelling stations for heavy-duty vehicles in order to boost hydrogen’s use and demand as well as lower production costs. The project also envisages hydrogen production near existing refuelling stations, hence developing approximately nine refuelling stations along six railway lines.
The private sector Italy’s private sector is certainly showing keen interest in the hydrogen transition. In particular, Italian energy infrastructure company Snam is part of the Clean Hydrogen Alliance established at the European level to back the EU Commission’s Green Deal aims. The 2019 report ‘The hydrogen challenge: the potential of hydrogen in Italy’, edited by Snam with McKinsey’s analytical support, stated that hydrogen could provide almost one-quarter of Italy’s energy by 2050, with the highest potential in transport, buildings, and industrial applications. Long-haul trucking, in particular, was seen as one of the earlier sectors where hydrogen could be cost-competitive with fossil fuels. Moreover, blending hydrogen in the grid up to a 10% - 20% mix for building heating was acknowledged as another promising area. As Italy already boasts gas pipelines that connect North Africa with Europe, the existing network could be employed to import hydrogen from the southern shore of the Mediterranean, where levels of solar irradiation are significant. Also, Italy’s
domestic gas network is well-placed to link the country’s south, where renewables resources abound, with the north’s industrial heartlands. In 2020, Snam – this time in partnership with The European House Ambrosetti – published another report entitled ‘H2 Italy 2050. A national hydrogen value chain for the growth and decarbonization of Italy’, which restated Italy’s potential of becoming the European hydrogen hub, an ‘infrastructure bridge’ between Europe and Africa. The study estimated a hydrogen penetration level of 23% by 2050 in Italy, with the transport sector expected to absorb 39% of energy demand by 2050, with the residential sector following suit with 32%. In terms of hydrogen supply chain technologies, production value was estimated between €4.5 billion and €7.5 billion by 2030, and between €21 billion and €35 billion by 2050. In October 2020, Snam announced an agreement with ITM Power, a leading global producer of hydrogen listed on the London Stock Exchange on the Alternative Investment Market. The agreement included a €33 million investment by Snam in ITM Power. In May, Snam announced the launch of the Hydrogen Innovation Centre, Italy’s first centre of excellence of hydrogen technologies, to be situated in the city of Modena. Other hydrogen hubs are set to follow. But Snam is not the only Italian company looking at hydrogen. Energy giant Eni, the largest producer and consumer of hydrogen in Italy, is also a European Clean Hydrogen Alliance member. Eni is actively looking at producing blue hydrogen
by steam reforming with carbon capture and storage as well as waste-to-hydrogen. Eni is also working together with Enel on developing green hydrogen projects through electrolysers powered by renewable energy. What is more, in April 2021, energy company Axpo Italia and multinational group Rina signed a Memorandum of Understanding (MoU) on developing hydrogen’s industrial supply chain through new projects. Furthermore, another hydrogen-related MoU was signed in June by Axpo Italia and ABB Italia.
An opportunity not to be missed Today Italy enjoys a once in a lifetime opportunity to revive its ailing economy and reform its public administration, putting the country on a path of green recovery consistent with EU ambitions. However, overcoming problems that for decades have marred its investment attractiveness, as well as slowing down its decarbonisation, will not be easy. In recent years, a number of key Italian energy players have been ramping up their efforts to transform the country into a key hydrogen player. However, while the private sector seems eager to embrace the opportunities provided by the energy transition and, in particular, by hydrogen, it is hoped that policy commitments will be consistent and strong enough to make the green economic recovery a success. So far, the policy signals coming from Prime Minister Draghi have been encouraging but it is yet to be seen whether ambitious reform efforts will be successful.
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n the past few years, the call for greener technologies has grown, spurring investment and innovation in new methods of producing the energy the world needs to keep moving – from transportation to manufacturing to the gas used to heat homes. Chief among the growing green focus is hydrogen, a renewable energy carrier with the ability to provide a sustainable fuel for a host of applications. Hydrogen has the potential to be green and renewable in that it can be developed using renewable means, such as wind or solar, while not adding carbon emissions in the process. To get there is part of the journey, as it is not an instant transition. For traditional fuel producers to join in, the predicted hydrogen boom will require an investment in both infrastructure and finding ways to make hydrogen truly green, or at the very least, blue. Figure 1 shows the different colours assigned to the production methods used to create hydrogen – such as purple for nuclear hydrogen creation, brown for coal, and green and turquoise for renewable methods. However, for the purpose of this article the focus will be on blue, a method that uses fossil fuels but captures carbon emissions in the process. Whether in transportation or residential and industrial applications, large scale adoption of hydrogen fuel will also require safe monitoring tools and a significant education piece to share with the public at large. Pushing fossil fuels entirely from the landscape in the immediate – short-term – future is not realistic when many considerations are involved.
Switching over to hydrogen Getting to green hydrogen is the ultimate goal in providing truly clean energy. Still, intermediate steps can be implemented to build up a hydrogen-fuelled economy and help to reduce or offset the costs of changing over. Moving to vehicles fuelled by
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Brandon Bromberek, Emerson, USA, outlines the variety of hydrogen production options, and why this energy should be considered as fuel for the road to green.
Figure 1. A colour-coded graphic of hydrogen production, conversion, and utilisation.
Blue hydrogen as an intermediate step
Figure 2. The Emerson Micro Motion HPC015 with rupture disk safety feature.
hydrogen alone will be a complex step, with many elements and industries needing to align. It will not be a matter of just plugging a new device into a hydrogen line. Pushing the boundaries of our energy dependency and the legacy of fossil fuels in our daily lives and industry requires a detailed look at the infrastructure and how we have historically built our society around the many uses of fossil fuels. Hydrogen as a fuel source requires different storage and dispensing equipment as well as different safety precautions. One of the main benefits of hydrogen is that it is very compressible, making it possible to store large quantities of it, but to keep it compressed requires high-pressure storage devices. Dispensing or transporting hydrogen means the pipelines, meters, and dispensers must be robust enough to withstand the pressure.
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As stated earlier, green hydrogen production is the holy grail of alternative energy. Using wind and solar power to create hydrogen sounds ideal, but it is expensive. Using solar or wind also requires a significant investment in unique infrastructure. Some countries, however, are working on just such solutions as long-term alternatives to fossil fuels with the goal of bringing down the cost and increasing adoption of hydrogen in businesses and homes over time. There is another option – blue hydrogen – which already offers a significant reduction in harmful emissions but still uses fossil fuels to produce the hydrogen. Blue hydrogen can be seen as an intermediate step to help build and meet the demand for hydrogen at a reasonable cost, while countries build out the necessary infrastructure for full scale adoption. Referencing Figure 1, it becomes clear that there are a number of ways to create hydrogen. Creating what is known as blue hydrogen is achieved by reacting natural gas with high-temperature steam to create a mixture of hydrogen, carbon monoxide, and a small amount of carbon dioxide that can be captured to avoid it entering the atmosphere. If the carbon is not captured, the process is referred to as grey hydrogen. In both blue and grey options, fuels generally considered part of the emissions challenge are used to create hydrogen, which releases only water vapour into the atmosphere when used as a fuel. However, by capturing the carbon emissions produced, the process becomes cleaner than just using fossil fuels for combustion downstream, making blue hydrogen a very desirable and cost-effective step toward the greening of energy production and consumption. Blue and grey hydrogen
production makes up approximately 70% of all hydrogen produced today.
Technological and device requirements As mentioned, hydrogen is compressible. Kept compressed and under high pressure is the only way that the energy in hydrogen is practically usable. If it were not compressed and left at atmospheric pressure, a full industrial storage tank of approximately 850 l would be needed to power one car for approximately 100 miles. That is not efficient. When compressed, hydrogen becomes far more efficient, and only a fraction of that storage tank is needed to power one vehicle. Compression also means it can be transported more easily, either in tanker trucks or added to a natural gas pipeline and stripped back out at the destination point. However, early testing has shown that in some cases, enduse appliances meant to run off natural gas can still perform relatively efficiently on blends of natural gas and 20% hydrogen. This benefits some distribution networks that will not need to spend the time and expense to separate out the hydrogen downstream, and it becomes a way to reduce the need for natural gas. Transporting the hydrogen mixed in with natural gas means that the pipeline must be checked for corrosion, as a possible weak spot in the pipeline can potentially lead to catastrophic ruptures. Using non-intrusive corrosion measurement tools is recommended as well as ensuring those devices are wirelessly connected back to the main data collection point.
Measurement and dispensing of compressed hydrogen requires a flowmeter that can withstand the pressure of hydrogen and safely dispense the gas without danger to personnel or customers. The industry-accepted pressure standards for dispensing hydrogen are 350 bar and 700 bar. The safety standards that must be met are set out in the American Society of Mechanical Engineers (ASME) B31.3 and ASME BPVC KD-3 codes. The latest flowmeters for high pressure and hydrogen fuel applications now offer an added safety feature in the form of a rupture disk, which is a first line of defence in case of a primary containment breach. If the rupture disk is activated by a tube breach, the seal in the rupture disk will be broken to allow for the controlled release of pressure. During this event, the meter’s onboard diagnostics will send out an alert so steps can be taken to shut down the flow.
A vision for a hydrogen future The future is uncharted land, though there are many roads being forged that promise a greener and cleaner future that will still allow us to maintain the level of lifestyle we have become accustomed to, with global transportation, import and export of goods, as well as a daily commute. Many of the roads tentatively travelled right now are being built on partnerships between manufacturers pivoting to meet the demands of an extreme high-pressure fuel; producers learning to adopt new processes to meet a burgeoning demand; and investors eager to invest in the future. Blue hydrogen is the bridge to a greener future.
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Figure 1. The Cromarty Firth is suitable for accommodating the largest offshore wind components, such as turbine blades, tower sections, and foundations.
Christopher Smith, Port of Cromarty Firth, Scotland, explains how green hydrogen is altering the energy landscape of Scotland and the Highlands.
cotland is undergoing a rapid energy transformation which is dramatically altering the landscape, both environmentally and economically, of the nation’s energy consumption – and with it the UK and Europe. The catalyst is renewables, principally hydrogen. It has gathered pace since the Scottish Government released its ambitions around achieving a net zero carbon economy by 2045. This has galvanised an already advanced infrastructure, creating new pathways and laying the foundations for a clean energy economy that is massive in both size and scale.
Scotland’s move to 100% renewable Before the government crystallised its net zero ambitions, Scotland was well advanced in transforming its energy production to low carbon. The result has been that its electricity generation by last year stood at nearly 100% renewable – 97.4% to be precise, according to Energy Statistics for Scotland. Further analysis of this change in electricity generation showed that in 15 years there had been an 82% increase in low carbon energy, and an 8% rise between 2019 and 2020. Of this,
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60.3% was generated by onshore wind, 18.1% by renewable hydro, and 10.7% by offshore wind. Onshore, offshore, and floating offshore wind has led the shift towards decarbonisation, with significant cost reductions made over the last two decades. However, their success has also exposed a key element that needs to be overcome if further advances are to be made – and that is how to both store excess wind energy and create a regular supply if the wind is not blowing. One key solution is the creation of a hydrogen economy. Hydrogen produced from renewable energy is a carbon-free fuel that can be used in place of fossil fuels, which are currently responsible for the bulk of global greenhouse gas emissions. The chemical make-up of green hydrogen means it only emits water when burned, so it can be made without releasing carbon dioxide (CO2) into the atmosphere.
Figure 2. Onshore, offshore, and floating offshore wind is leading the shift towards decarbonisation.
Blue or green There are different types of hydrogen that can be used to aid climate goals, with the main forms being blue and green. Blue hydrogen is created when natural gas is split into hydrogen and CO2 either by steam methane reforming (SMR) or auto thermal reforming (ATR). This is very much the way hydrogen has always been created as an energy source (known as grey hydrogen) but the difference for blue is that greenhouse gases used in the process are captured through carbon capture usage and storage (CCUS) technologies that remove CO2 generated. Green hydrogen is produced by splitting water through electrolysis, producing hydrogen and oxygen. Hydrogen is used as energy while the oxygen is vented into the atmosphere or captured for use in industries such as aquaculture. The process is powered by renewable energy sources such as wind. This makes green hydrogen a cleaner option, as it avoids generating any CO2. According to the latest research from the UK Parliamentary Office of Science and Technology (POST), green hydrogen is currently more expensive than blue hydrogen to produce, but is expected to become cheaper in the 2030s. In the past year, the Scottish Government set itself another target – for Scotland to become a leading nation in hydrogen, generating 5 GW of renewable and low-carbon hydrogen by 2030. This would be enough hydrogen to power the equivalent of 1.8 million homes. The Scottish Government matched this vision with cash – £100 million over the next five years. The foundation for this vision stems from Scotland’s abundant offshore wind resource with the potential to be a vital component in the nation’s netzero transition. If used to produce green hydrogen, offshore wind can help abate the emissions of historically challenging sectors such as heating, transport, and industry, which are difficult to decarbonise using electrification alone.
Unlocking a clean power resource
Figure 3. The North of Scotland Hydrogen Programme is built around plans for an onshore electrolyser within the Cromarty Firth.
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Green hydrogen production from offshore wind could help overcome Scotland’s grid constraints and unlock a massive clean power generation resource, creating a clean fuel for industry and domestic households and feeding a rapidly-growing UK and European market. The Wupperthal Institute, the German research institute for climate, environment, and energy, constructed a model of what a future hydrogen market across Europe could look like. Its European Transnational Hydrogen Backbone outlined which countries would produce
‘excess’ hydrogen that could be exported to others with a hydrogen ‘deficit’ through a network of pipelines. One such country with a future capacity to be a key exporter is Scotland. To realise this, much work needs to be undertaken quickly. Already key contributors towards a hydrogen economy are ramping up their plans for further development. Among the most prominent contributors towards a hydrogen economy are: The Hydrogen Office in Methil, Fife, Aberdeen’s Energy Transition Zone, Orkney’s 100% Green Electricity and Big HIT, and the North Scotland Hydrogen Programme, which would see a green hydrogen hub on the Cromarty Firth.
The importance of the hydrogen valleys North of Scotland Hydrogen Programme feeds into a key component of Scotland’s hydrogen ambitions – to establish ‘hydrogen valleys’. They are geographical areas where several applications involved in the process of hydrogen combine into an integrated ecosystem delivering huge momentum in the market so a security of supply can be established, allowing those who want access to the clean energy to have the confidence to switch their infrastructure. The programme comprises a number of projects, the principal of which is the construction of a large scale onshore electrolysis facility. A kickstarter Distilleries Project is underway, with partners ScottishPower and Pale Blue Dot Energy, the Port
of Cromarty Firth, plus drinks firms Glenmorangie, Whyte & Mackay, and Diageo – researching the opportunity to establish a green hydrogen hub to provide distilleries in the region with hydrogen to assist in decarbonising their heating. This electrolyser will be powered by electricity from renewable sources. It will be onshore within the Cromarty Firth, one of the UK’s largest natural harbours whose deep waters are a central point for both offshore and onshore wind. Indeed, the significance in Port of Cromarty Firth as a hub for the electrolyser is due to its excellent proximity to 14 of the 15 sites identified for future offshore wind and floating offshore wind projects in Scotland, predicted to be worth £26 billion to Scotland over the next 50 years.
North of Scotland Hydrogen Programme Scaling up renewables such as offshore wind has the potential to deliver vast quantities of green hydrogen. Nigel Holmes, Chief Executive of the Scottish Hydrogen and Fuel Cell Association (SHFCA), explained: “Production of green hydrogen is a fantastic way of converting renewable energy into transportable and storable low carbon energy. In Scotland, we have the infrastructure and brains to make this work on a massive scale. “We can create and scale up projects, such as the North of Scotland Hydrogen Programme, building green energy port hubs which can supply local demand and other locations. Economies of scale for green hydrogen production will kickstart new projects that will be invaluable in achieving the Scottish Government’s target of 5 GW low carbon production capacity by 2030. “It is vital to remember the 2030 target is now less than nine years away. Green hydrogen production in locations such as Cromarty will be an important catalyst for development of low carbon industry clusters. It is important that they are not only built sooner rather than later, but that they give industries such as the Scotch whisky sector the confidence to realise their plans to become net zero.”
Existing infrastructure can go green Figure 4. The Port has excellent proximity to 14 of the 15 sites identified for future offshore wind and floating offshore wind projects in Scotland.
Figure 5. An electrolyser would provide hydrogen for transport – including special hydrogen-fuelled vessels.
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Another key element of the electrolyser plan is what happens to the green hydrogen following the electrolysation process. This again feeds into the Scottish Government’s hopes that Scotland’s extensive and existing port and pipeline infrastructure can be repurposed for hydrogen exports to the rest of the UK and Europe. The North of Scotland Hydrogen Programme makes use of the Port of Cromarty Firth’s current infrastructure to store and transport the hydrogen in large quantities. Hydrogen as an energy carrier has a relatively low volumetric energy density compared to fossil fuels, requiring a different approach. Moving hydrogen between ports in the UK using bulk scale carriers would balance supply and demand and enable the hydrogen market to expand more quickly. This means the Port would feed, through its deep, sheltered waters, a market that will allow hydrogen to be shipped to the rest of the UK and beyond. Closer to home, it will provide hydrogen for transport – including special
hydrogen-fuelled vessels to take service engineers from the coast to the offshore wind farms – heat and industry, with the distilleries likely to be the first customers. Nigel added: “The Port of Cromarty Firth and its partners have developed a compelling vision in a short space of time. That is because they realise they have the right location and the right ingredients to make hydrogen work. Green hydrogen is clearly the future, but at the moment it is expensive when produced at small scale. Early industry adopters, such as the food and drink sector, require established and reliable supply at a realistic cost. “The development of offshore wind-hydrogen Figure 6. The Port of Cromarty Firth’s deep, sheltered waters have for decades production with projects such as the ERM Dolphyn has provided the perfect base for companies to launch their operations. the potential to bring the cost of green hydrogen down to the target of US$2/kg by 2030. Port of Cromarty Firth is already an established hub for shipping fuels to However, for industry to establish the necessary markets across the world, and with this existing infrastructure infrastructure, it must be able to guarantee supply. As a result the Port’s team can made things happen quickly.” the Port of Cromarty Firth has also signed a Memorandum of Understanding with Norwegian firm Gen2 Energy AS to Hydrogen and Scotch whisky create a commercial pathway to import green hydrogen from Hydrogen will also allow established industries, key to the Norway into the UK energy market. prosperity of Scotland, to make the switch to carbon-free The partnership will provide a security of supply for the production methods. One such industry is whisky, and the electrolyser facility, and will guarantee green hydrogen to Scotch Whisky Association has already laid out the need to those who want access to the clean energy by mid-2023, so decarbonise fully by 2045 in its ‘Scotch Whisky Pathway to Net they have the confidence to make concrete plans to begin Zero’ report. switching their infrastructure. That is why the North of Scotland Hydrogen Programme also involves the distilleries of Glenmorangie, Whyte & Mackay, R&D for jobs and Diageo which want to source hydrogen so they can The North of Scotland Hydrogen Programme’s influence is not decarbonise the production of their whisky. restricted to hydrogen itself. There are many business and Shane Healy, Distilling Director for Whyte & Mackay – which personal opportunities that will also be realised. Opportunity has two distilleries on the Cromarty Firth (Invergordon and Cromarty Firth (OCF) was set up last year, made up of over a Dalmore) – says the industry is looking long-term to a balanced dozen partners from the private, academic and public sectors, approach using a mix of green fuel sources from hydrogen, including the Port of Cromarty Firth, University of the Highlands biomethane, and biomass, as well as green electricity to create and Islands, and The Highland Council, with the ambition the sustainable energy needed for its distilling processes. of the Cromarty Firth becoming a ‘Freeport’. One of OCF’s He said: “For our Highland operations, green hydrogen is first moves was to set up the PowerHouse, a global centre the best option as a long-term key green energy source, as of excellence in the research and development of floating we are close to the infrastructure of wind turbines in the North offshore wind and green hydrogen technologies. Sea and have abundant access to water. We are also looking Bob Buskie, Chief Executive of the Port of Cromarty long-term at a possible use of desalinated sea water to take Firth, said: “The opportunities presented by green hydrogen advantage of our proximity to the sea, to add to our fresh loch are vast and its importance to the Cromarty Firth, the water to make our green hydrogen.” Highlands, Scotland, and beyond cannot be underestimated. Shane said such a scenario is vital for the future of the These developments will bring skilled jobs and high-wage Scotch whisky industry in Scotland – a high value product opportunities to the Highlands on a level not seen since the oil enjoying significant demand around the globe. With quality boom of the 1970s. whisky taking years to mature, the need to reassure these “We have already developed a substantial track record customers that their product, which could be produced today in renewables and supported more offshore wind projects and may be matured for many decades, has been made using than any other Scottish location. But such is the size and carbon-free methods. scope of this operation that we cannot act alone. For our He said: “Whyte & Mackay has recently celebrated industry to fully capitalise on this breadth of ambition, we 175 years and we want be around for 175 and more years to need to collaborate, pool our resources, and ensure through come. For that to happen we must embrace carbon neutral partnerships that the infrastructure and technologies are methods, and build them into our infrastructure so that in the created in Scotland to meet this overwhelming demand for long-term, thinking decades into the future, we will be laying hydrogen and then export this expertise around the globe as our whisky down the line in an entirely sustainable way.” other countries decarbonise.”
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Gaby Amiel, Sennen, UK, explores how developing rigorous systems for digitised operations will be essential in tackling the complexities of a growing industry.
he offshore wind industry is poised for impressive growth over the next five years. Research from the Offshore Wind Industry Council (OWIC), published earlier this year, states that direct and indirect jobs in the sector will almost treble from 26 000 in 2021 to approximately 70 000 by 2026. The stage looks set for a remarkable chapter in the sector’s history books, but how can the industry grow without compromising on safety? Developing rigorous systems will be essential in tackling the complexities of a growing industry. Historically, the offshore wind industry has not faired badly when it comes to health and safety. Thankfully, it has not had any fatalities in recent years – but its safety record still lags behind oil and gas. In 2019, the Lost Time Injury
Figure 1. Rampion wind farm, Sussex, UK. Image courtesy of Zoltan Tasi.
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frequency rate for the European offshore wind industry was three times higher than offshore oil and gas.
Technology for growth Creating systems and technology that enable the sector not only to maintain its safety record but improve on it, must
be an integral part of the growth strategy. RenewableUK has said itself that there needs to be the right training and support in place in the transition towards clean energy, and that is absolutely right. This is especially true considering that each new offshore auction brings a lower cost of energy, putting the squeeze on overheads and requiring more efficient service delivery. Also, more and more projects are being built further out at sea which adds to the complexity. Leading operators are introducing sophisticated automation to improve safety compliance and protect project returns. Here are some of the key areas where technology can improve safety and efficiency:
Restrictions and alerts
Figure 2. Sennen screenshot showing HSE KPIs.
Figure 3. Screenshot of marine map showing cable overlay and vessel movements.
If there is a problem on site, a restriction is raised. This could be anything from a lift that is overdue for inspection, or an electrical fault. When a restriction occurs, workers must be alerted. Sometimes a notification is all that is needed but, in other cases, only those with specific skills and equipment can proceed. Proper restriction management requires painstaking administration work. Operators report that failure to notify restrictions in a timely way regularly causes interruptions to daily activity, wasting hundreds of thousands of pounds each year. Worse still, missing a restriction can put workers in danger and may have far greater financial ramifications. However, when equipment service plans are stored centrally, restrictions can be automatically created, issued, and acknowledged. An integrated work planning system will alert users automatically, preventing disruption or cancellation of work.
Safe systems of work Safe systems of work (such as wind turbine safety rules or high voltage safety rules) ensure that dangerous works are carefully controlled and managed. They are effective but highly cumbersome. Through careful automation, a digital system can track the expiry of qualifications and competency levels, control the start and end of works, and ensure all key checkpoints are observed. Moreover, it can do so with much enhanced speed and rigour.
Hazards and incidents
Figure 4. Portfolio overview.
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Reporting health and safety incidents to the HSE is a legal requirement. Every injury, hazard, and near miss must be logged, categorised, and processed. This can be stressful for health and safety managers
as they struggle to keep up with multiple or overlapping incidents. The reporting and investigation process is fertile ground for digitisation. If an HSE system is working well, incidents and actions on the ground are handled swiftly with a clear auditable record. For instance, one operator has reported an immediate 33% uplift in hazard reporting after roll-out of Sennen’s specialised HSE system.
The gains presented by technology go beyond the offshore wind industry. All renewable technologies have their own unique set of health and safety risks and, as each of those industries mature, they will need to examine their processes and discover smarter ways of working. This is an exciting opportunity to set the gold standard in digitised operations.
Ship shape at London Array
Every offshore site has a risk management system. Traditionally, a ‘risk register’ is compiled by scoring risks according to the danger they pose. This is stored in a spreadsheet and updated from time to time. It is labour intensive and prone to error. Digitising the risk register allows it to be updated quickly and easily. Risk should be viewed as a dynamic and evolving metric rather than a static, absolute measure. This is achieved by recording a baseline risk score and recording the impact of mitigations and aggravating incidents. With a timeline of risk, managers can observe trends, set targets, measure the effectiveness of actions taken, and motivate the team to implement safety improvements.
London Array is one of the world’s largest offshore wind farms. Its sheer size and make-up brings significant challenges, and ensuring the safety of the many contractors is mission critical. Sennen has created a system that acts as a control room to direct work happening on-site. Mike Young, Operations Manager at London Array, said: “I have a responsibility across vessels, turbines, and technicians. There are multiple teams, often performing highly specialist work and doing so in confined spaces. Being able to run all of this from the control room, or even remotely from home, is key.” At any one moment, there are regularly more than 100 people deployed and, at peak times, this figure can be more than 250. Effective co-ordination is thus crucial. Many of the turbines are in shallow water and this means operational constraints are that bit tougher. The control room needs to direct the work so that the wind farm produces as much energy as possible, safely. With Sennen, London Array can co-ordinate vessels and manpower so that they know exactly where they are at any point and are ready to respond to anything including turbine issues, changes in weather, vessel breakdowns, and emergencies. Personnel are only deployed if they have the correct qualifications. Safety and planning have also been greatly improved. London Array is on top of hazard alerts and able to respond instantly to any emergencies. Potential issues are sorted at the planning phase and not once out at sea. In 2020, while navigating the response to COVID‑19, Sennen has once again proved invaluable. London Array has been able to stagger teams and maintain small groups in separate bubbles to minimise contact risk but keep the work on track. Mike added: “Knowing that the personal qualifications are correct, and that a given vessel can get to a given location, or that there is enough room on that vessel for all of the team – knowing all this without having to check and re-check spreadsheets gives us a significant advantage when planning operations.”
Weather planning Earth’s weather systems are unpredictable at the best of times, so offshore maintenance always requires careful planning. With the next generation of wind farms being built further offshore, there is an even greater need for more accurate predictions of weather windows. Intelligent technology can really help here. The right system will give access to live metocean conditions visualised in different formats and it can automate predicted safe working windows, individual vessel characteristics, and safety considerations – such as speed of the current for diving conditions. O&M becomes more efficient and safer with fewer project interruptions as conditions can be predicted with greater accuracy.
Tomorrow’s needs As the industry enters a new phase of growth, it needs to be open to new ways of working using technology that will flex to tomorrow’s needs. Systems that reflect the reality of what is happening on the ground rather than static, outdated recording tools are going to be a crucial in delivering safe and successful growth. This approach is delivering for London Array which has adopted Sennen’s system to act as a control room to direct all work happening on-site. Safety and planning are key features. London Array is on top of hazard alerts and is able to respond instantly to emergencies. Potential issues are sorted at the planning phase and not once out at sea. Sennen develops cloud-based software that digitises and centralises every element of managing and operating renewable energy assets. Its goal is to enable operators to maximise asset value while ensuring safe working.
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enewable energy investment is becoming better and cheaper by the day. This, of course, is great news for the planet, as it will encourage companies, governments, and private investors to contribute to this green infrastructure over the coming decades, in a bid to increase green energy consumption. The International Energy Agency (IEA) recently stated that, although slim, there is still a possibility of reaching net-zero emissions by 2050. Yet reaching these kinds of targets will require a huge amount of investment, and enticing investors to tap into these projects ultimately depends on their success and the return on that investment (ROI). While competition is growing in the renewables sector, there are a whole host of different investment options to choose from. Multiple variables will drive the return of a renewable plant investment, which will define the outcome of the entire process. Here, the elements that will affect the ROI are explored.
Stakeholder alignment Alignment among all the stakeholders involved in the project is paramount to enable a good quality project.
Availability and cost of financing The project quality typically dictates the appetite of the lenders and the selection of a
savvy cluster of technical, financial, and legal advisors is a prerequisite. In particular, the selection of a good technical advisor or independent engineer is necessary to understand from the very beginning whether the project is aligned with the standards required for an operation that might last up to 30 or 40 years.
Access to bankable offtakers The sale of the energy and how it will be utilised by the end offtaker will command the technical design of the plant. The pay-as-produced power purchase agreements (PPAs) are starting to disappear or their value is decreasing, hence plant design needs to adapt to more intelligent ways of exporting energy. Nowadays, the software components of plant design are increasing their importance because renewables plants are starting to contribute to grid stability.
Excellence in project development processes The permitting risks must not be underestimated. To carry out a successful project it is extremely important that the local community is engaged, that the development has a low impact on the local environment, and that the technical project filed is designed for a real-life project. In addition to Matrix Renewables’ development expertise, its success comes from a special commitment to community values. The company recognises its projects have a long-term presence in the communities where they are located and seeks to foster long-term community partnerships to create a lasting, positive impact through the environmental and social policies it promotes. These
Luis Sabaté, Matrix Renewables, Spain, explains the technical and engineering aspects of ensuring a successful project and ROI, and why this is integral for encouraging future investment in renewable energy developments.
commitments are taken into consideration very early in the development process. Elsewhere, developers often file technical projects which, in the end, cannot be built due to the rapid and continuous evolution of the technology. A continuous monitoring of the technology market is needed to accommodate the available technology at the time the construction is planned.
Establishing a stable grid connection A stable grid connection application process goes hand in hand with permitting consent. An integrated and transparent approach with the transmission or distribution companies is a must. Developments must be designed with the right grid capacities which will save time for all parties involved and save on connection costs, which may help with infrastructure upgrades. This not only ensures the project interconnection but reinforces local infrastructure for the long-term.
Appropriate technology selection and optimised design of plants Matrix Renewables believes that innovation is the key differentiator among the different platforms existing in the market. The company wants to lead the early adoption of advanced technology which will, in turn, increase the efficiency of the invested capital. The location and the environmental conditions of the project determine the choice of the most appropriate technology. Decisions need to be made on a whole host of possible options, such as: FFWind turbine selection according to the site class.
FFPhotovoltaic (PV) module: Mono or bifacial, multi crystalline, mono crystalline, or thin film. Here an agnostic approach is highly recommended.
FFAC/DC inverter: Central or string inverters, outdoor or indoor solutions, capacity and performance.
FFFixed structure or tracker and tracker selection. FFStorage technology selection. FFInterconnection topology. Of course, the ultimate goal is to optimise plant performance (kWh or kW installed) by enhancing the maximum energy produced per unit installed. For this purpose, the design needs to ensure the compatibility of the different components, so as to gain synergies among the different equipment, taking advantage of available space. Projects must be designed to ensure the greatest efficiency, not just for today, but over the 30 or 40 years the plants will be in operation. Repowering or life extension concepts must be analysed to take into account the expected technology evolution over this time. Design must also bear in mind the required operating and maintenance procedures. This means thinking ahead and
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ensuring that the long-term procedures are compatible with plant design. A good example is robotic cleaning solutions which have evolved very rapidly, and there are many areas globally that could benefit from reducing soiling losses in PV plants.
Adequate selection of the EPC contractor Once the technology has been selected and the design has been optimised, the engineering, procurement and construction (EPC) company will play a fundamental role in the execution of the project. The selection of the EPC company must be undertaken using a thorough process. The variables which Matrix Renewables takes into account include the following: FFBankability: The EPC contractor must have an excellent track record and reputation in the industry. The largest EPC companies are not necessarily the best ones available in the market.
FFQuality and performance – track record: Plants that are already built must have a production profile history exceeding performance expectations. Quality standards are reviewed and assessed before the deliveries of the components start.
FFStrong engineering capabilities: As described earlier, the most efficient design has to be carried out by an industryleading engineering team which shall take innovation and advanced technologies into consideration, from both the hardware and software angles.
FFSupply chain power: Equipment pricing for wind, solar, and battery storage projects fluctuates regularly, impacted by geopolitical considerations, raw materials constraints, and technological improvements, among other factors. The dynamic nature of the equipment market, which largely drives the overall cost of a project, demonstrates the importance of savvy procurement to a project’s success. Expertise, relationships, and capabilities are critical to ensure realistic cost assumptions, to avoid fatal flaws, and appropriately price project energy output. Matrix Renewables and its EPC contractors have a robust and diverse supply chain that ensures a broad selection of wind turbines, modules, and batteries are available, delivering the highest level of project viability by eliminating solesource risk and using bankable technology.
FFConstruction timeframe: The EPC contractor must have a proven adequate speed of construction.
FFCost attractiveness: The right price should be paid to the EPC contractors to avoid the inherent risks of not achieving the cost levels needed to build and install the appropriate equipment.
Construction monitoring The ability to prevent and solve execution problems by the EPC contractors is directly proportional to the earliest
detection of the potential issues. Matrix Renewables always appoints a dedicated team to monitor the execution on a daily basis, ensuring a healthy tension between the sponsor representatives and the EPC contactor team. Typically, a support team is also implemented to assist with the quality controls and the issuance of the progress reports. Early engagement in problem solving means that solutions are found more rapidly and problems are easier to correct.
Availability and cost of guarantees and insurances to cover all the years of operation The main equipment installed and delivered to the renewables plant must have a long-term warranty package with the original equipment manufacturer (OEM). Some equipment usually has an original and standard limited product warranty, with the option to be extended throughout the duration of the plant. The main equipment to be considered is: wind turbines, solar modules, inverters, structures (trackers), and main electrical equipment (substation). Long duration warranty packages attached to an operations and maintenance contract (O&M) is becoming more common nowadays, especially in the wind industry. The extension of life options are currently increasing the lifespan of wind assets, delivering very interesting results to plant profitability.
Figure 1. Adequate selection of the EPC contractor.
Figure 2. Stakeholder alignment.
Selecting appropriate services during the operational phase Matrix Renewables’ trained asset management professionals develop customised O&M plans to ensure every project operates properly throughout its life. With a dedicated software – developed with one of the industry leaders – the company uses metering, sensing, and data analysis technologies to monitor, analyse, and respond to critical events that impact daily energy production. By analysing production data against a rich set of production metrics, the company continuously verifies the production performance against performance baselines and financial models. The team also tracks outages and degradation and diagnoses root causes with the support of an externalised team. Predictive and preventative maintenance is also prioritised, including frequent inspections and cleaning. These actions enable the output and revenue generated from projects to be maximised. Matrix competitively sources O&M providers and holds them accountable for satisfying any third-party requirements,
including lenders specifications, via well-established O&M agreements.
Conclusion Matrix Renewables’ project pipeline growth is driven by the strength of its M&A and development teams, heavily supported by its technical team which follows a disciplined and targeted approach. The company actively filters for investment opportunities that minimise or eliminate environmental and permitting issues and have strong, low-cost interconnection options. From a technical standpoint, a significant technical due diligence is invested early in the process to thoroughly screen projects for potential fatal flaws that would impede a project’s successful completion or may significantly erode the project’s financial returns: available land including setbacks restrictions, soil conditions, initial project layout, resource analysis, yield estimation, and an early technology selection are considered before an investment decision is made. These are all important fundamentals which Matrix Renewables believes lie in the optimisation of ROI in the renewables sector.
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Marco Frassinetti, EXERGY, Italy, discusses the rise of binary technology within the geothermal sphere and how it can be customised for a range of different projects.
ccording to the latest Renewable Energy Market Update published by the International Energy Agency (IEA) in May this year, the relentless growth of renewable energy demand was not stopped in 2020, despite the COVID-19 pandemic. Renewables were the only energy sources to expand and to set a new record with a capacity addition exceeding 45% from 2019, the largest year-on-year rise since 1999. Geothermal energy contribution represented approximately 200 MWe and raised the total geothermal power generation capacity installed worldwide to 15.6 GWe. A modest growth for the sector that was influenced by the pandemic situation. Turkey, although in an unclear policy situation due to feed-in tariff renewal, was still confirmed as the leading country for geothermal development: 168 MWe was started up in 2020, the whole capacity with binary cycle power plants. Binary technology has been the fastestgrowing technology in the last decade, featuring in more than 50% of new installations. This has been due to its advanced technology, being more responsive to environmental restrictions, and to the rising exploitation of low to medium temperature resources, for which binary systems reveal the best power generating solution in comparison to traditional dry steam power plants. Italian EXERGY International, a provider of Organic Rankine Cycle (ORC) solutions owning the second largest geothermal binary fleet worldwide, has completed three of the new binary systems commissioned in Turkey in 2020: the 26 MWe power plant for Greeneco Enerji, the 12 MWe for RSC Enerji, and 10 MWe for Kiper Elektrick. Greeneco Enerji geothermal installation represents the sixth unit of a multi-stage project, totalling 102 MWe, that involved the modular expansion of the power generation capacity following geothermal field development. In 2014, EXERGY was awarded the first contracts for the supply of two units, 12 MWe each, commissioned between 2015 and 2016. These were followed by four additional geothermal ORC units. For each project, EXERGY designed a tailored solution equipped with the innovative and proprietary technology known as Radial Outflow Turbine (ROT) to grant high performance, customised solutions, and increased profitability
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Figure 1. Greeneco Enerji geothermal power plants, Sarayköy, Turkey.
Figure 2. Akca Enerji’s 4 MW Tosunlar geothermal plant, Turkey.
of the power plants. For the first two 12 MWe units, EXERGY engineered and supplied two water-cooled pressure level cycles equipped with two ROT, one high pressure and one low pressure, coupled to a single, double-ended generator. For units three and four, the same design was employed but opting for an air-cooled condensing system in order to achieve zero water consumption and decrease the environmental footprint of the power plant. The last two geothermal units supplied between 2018 and 2020 were the biggest projects, consisting of a 28 MWe and a 26 MWe ORC system where EXERGY designed a solution with one pressure level cycle equipped with two big turbines of 14 MWe each and employing an air-cooled condensing system. The last unit has been in operation since October 2020. The total installation of 102 MWe capacity of baseload renewable energy of the Greeneco project allows 478 000 tpy of CO2 emissions to be saved and avoids the consumption of 153 000 t of oil equivalent necessary to produce the same power with a conventional fossil fuel resource.
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Launched for the first time in the ORC market in 2009, the ROT is EXERGY’s innovation that proved to be the highest efficiency turbine on the market, with performance certified by third party tests on some plants in operation. The key feature of the ROT configuration is its capacity to convert the energy contained in the organic fluid into mechanical power with high efficiency. In fact, when working with an organic fluid, the ROT configuration and characteristics entail several advantages: FFNatural accommodation of the working fluid expansion allowing a broader range of applicable fluid conditions.
FFMultiple pressure admissions possible on a single turbine disk giving a cost-effective solution to exploit low temperature geothermal resources.
FFMinimum 3D effects and turbulence meaning maximum efficiency achieved with straight blades, much simpler to manufacture.
FFLow speed turbine requiring no gearbox, meaning longer life of the bearings and higher reliability.
FFPatented Mechanical Group is easy to extract, resulting in fast and easy maintenance with no necessity of fluid drainage and overhaul maintenance on the turbine.
FFStandard mechanical design for each turbine frame. The latter advantage is key, as it allowed EXERGY to offer optimised solutions and scale-up technology very rapidly,
reducing supply time, and guaranteeing maximum efficiency without need for mechanical redesign. In fact, the particular configuration of the turbine allows for the separation of ROT designing and manufacturing into two complementary processes: a first mechanical designing process that is extremely redundant and standardised to assure the highest turbine reliability, and a second fluid-dynamic designing process that is customised for the specific resource conditions in order to extract the maximum possible power from the geothermal fluid. Considering the geothermal market requests, EXERGY developed three standard mechanical frames for turbine sizes up to 5 MW, 10 MW, or 25 MW. For every new turbine design, the correct mechanical frame can be selected according to the project details, and the machine reliability is assured even with a custom-made fluiddynamic design process. Today there are more than 40 ROT, of different sizes, successfully in operation in geothermal power plants worldwide, each with a unique and customised design in order to obtain the maximum efficiency from the available resource and thus guarantee the highest return of investment for the customer.
A world first In 2015 in Turkey, EXERGY’s turbine design allowed the execution of a world-first geothermal project: the first example of a binary plant equipped with two pressure-level cycles on a single turbine disk. The project was developed for Akca Enerji and it allowed the customer to profitably exploit a low enthalpy geothermal
resource with fluid temperature at 105˚C to generate 4 MWe of electricity. This configuration with two pressure levels on a single expander offered a higher plant performance, producing up to 20% more power than using a single pressure level system. This plant was awarded the European Geothermal Innovation Award in 2016.
Geothermal brine recovery Binary technology is an effective choice, not only for the development of greenfield low-medium temperature geothermal resources but also to better harness existing geothermal power plants by combining binary plants to traditional flash technology. One application of flash and binary technology is for brine recovery. Although efficient and reliable, dry steam power plants lose a significant part of the total thermal capacity in the liquid phase (brine). Retrofitting an existing flash plant with a bottoming binary cycle is an effective way to recover the thermal energy of the brine to generate additional electricity, thus increasing the power output of the plant and the productivity of the geothermal site without further environmental impact. EXERGY International has recently started the development of a geothermal brine recovery project in the Philippines for Energy Development Corporation (EDC), the world’s largest vertically integrated geothermal energy producer. Located on the Mindanao island, the new Mindanao 3 unit will be EDC’s first geothermal brine recovery plant to go online in 2022. It will help generate an additional 3.6 MWe of power
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Figure 3. Pico Alto geothermal power plant, the Azores.
harness a high temperature geothermal resource. The aim was to provide renewable electricity for the Terceira island and decrease the island’s dependence on diesel power generation. The high temperature resource would fit with the choice of a flash power plant but the binary solution was preferred as it is more flexible in adapting to the resource characteristic and to the environmental constraints. In this geothermal field the production wells were characterised by a cycling behaviour, causing flowrates and pressures oscillations, hence making the exploitation of the reservoir and the operations of the power plant fairly challenging. Other environmental and logistical constraints that needed to be taken into account were the high levels of iodine and salt effect on plant components, severe weather conditions during construction and site operations, and the remote location at 1500 km off the mainland – making the project even more difficult to execute. Due to the high enthalpy resource, EXERGY designed a first of its kind turbine in the company’s geothermal application, with a single level saturated cycle employing a type of working fluid typically used for heat recovery applications. A fast delivery time was possible for the characteristics of the ROT manufacturing process. The plant entered into operation in August 2017 and helped to decarbonise power generation on the Terceira island, reducing the electricity production from fossil fuels by 20% in eight months and increasing the share of renewable energy from geothermal by 13%.
Reliable renewable energy
Figure 4. 3D section of EXERGY’s Radial Outflow Turbine.
utilising the waste geothermal brine available from Mindanao 1 and 2 steam power plants in an existing geothermal field. EXERGY’s activities involve the engineering, design, and supply of the ORC system and technical equipment, including the cooling towers and the brine dosing system. Moreover, EXERGY’s task encompasses a substantial technical advisory service to EDC for the project execution. The engineered solution consists of a single pressure level cycle equipped with ROT. The overall project has a very tight time schedule, and the start-up of the plant is expected by 1H22. Once in operation, the ORC systems will help save approximately 16 000 tpy of CO2 emissions and 5000 tpy of oil equivalent consumed.
Taking on a challenge Other interesting geothermal applications of EXERGY technology are again located in Turkey, where in 2017 EXERGY installed one of the biggest ORC turbines on the market – 18 MWe in size – at the Kuyucak power plant for Turcas, and a second one at the Pico Alto project in the Azores islands. The latter was a particularly challenging task. Developed for EDA RENOVAVEIS, the utility of the Azores island, it involved the supply of a 4 MWe geothermal plant to
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The remaining geothermal projects in EXERGY’s portfolio are located in Italy and Turkey, with a total 27 power plants and approximately 440 MWe installed or under delivery capacity. These power plants, as with many other projects around the world, demonstrate how geothermal energy is an effective, reliable renewable energy source that can be efficiently harnessed by employing the most advanced available technologies. It also has the advantage of being abundantly present in many parts of the world, being a valuable choice for remote locations with difficult access to electricity. Moreover, in contrast to all other renewable energy sources, geothermal is the sole renewable that can satisfy baseload power generation without jeopardising the grid stability with unpredictable behaviour. Nevertheless, it continues to be disregarded, representing a very small share of the total renewable energy capacity addition year-on-year. As the IEA’s Executive Director Fatith Birol recently remarked in one of his interventions, geothermal “is one of the renewable resources that [is] being treated unfairly” and “is not on the agenda worldwide enough”. To develop geothermal activities further, it is fundamental that all the risks and the costs connected to the exploration phase are correctly addressed by policy makers, with adequate financing that can encourage investments during the early stage. With the international geothermal associations at the forefront to bring this theme to the attention of institutions and with oil and gas majors starting to show their interest and make investments in this sector, the geothermal community can maybe hope for a brighter future and a stronger development of geothermal worldwide.
Chum Wai Hoe, Welltec, Denmark, outlines how oil and gas expertise can be leveraged to plot geothermal’s hot future and manage challenges in geothermal systems.
t the end of 2020, total global installed geothermal capacity reached 15 608 MW. According to the International Energy Agency (IEA), an average 500 MW was added each year between 2014 and 2019, but only an additional 202 MW came online in 2020. That modest growth falls considerably short of the target set in the IEA’s Sustainable Development Scenario (SDS), where it called upon the geothermal sector to accomplish a 10% increase over the next decade. The IEA’s SDS outlines a major transformation of the global energy
system, showing how the world can change course to simultaneously deliver on the three main energy-related UN Sustainable Development Goals (SDGs). Policies tackling challenges associated with pre-development risks are needed to increase the deployment of geothermal resources for power generation. With increased development efforts, there clearly has been a faster growth in geothermal capacity over the last 10 years than several preceding decades combined. While
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the COVID-19 pandemic delayed the start of new plants last year, construction efforts are progressing, and it is expected that there will be new capacity additions of up to 1500 MW in the next two to three years. ThinkGeoEnergy estimates that by 2026, the overall increase can reach up to 4000 MW in additional power generation capacity. According to Alexander Richter – Founder and Principal of ThinkGeoEnergy – the geothermal sector is seeing an increased interest as part of renewable energy efforts worldwide. With
a demand for non-intermittent sources of renewable energy, geothermal is receiving growing attention as a baseload source of energy to help stabilise electricity supply when paired with wind and solar markets. With decarbonisation efforts high on the agenda in the heating and cooling sector, Richter sees an even more promising picture with regards to the development of geothermal projects. “We have seen an increasing interest in geothermal energy for heating purposes, particularly in Europe and China. With the lower temperatures required in the context of use for heating, geothermal energy can be tapped across a much wider geographical area than for power generation. But we also see wider attention on geothermal capability for electricity generation beyond the hot regions of the world. So, all in all, there is a certain momentum that will see a faster growth in geothermal development worldwide than in the past.” Furthermore, the use of geothermal heat in large scale greenhouses and related operations – as seen in the Netherlands and Turkey – is pushing geothermal energy to the forefront of the discussion. “Quantifying the expected growth is difficult, but we believe that drilling activities will pick up at unprecedented rates and we expect more development for heating projects than power projects in Europe and beyond,” Richter adds.
The geothermal well Figure 1. An all-metal Welltec Annular Barrier (WAB®) arrives on site in Japan.
Figure 2. Geothermal deployment in Japan.
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There are of course some key differences between a geothermal well and a petroleum well, such as the temperature and flowrate that needs to be endured, both of which are higher in a geothermal well. Temperatures for an oil well are considered ‘hot’ between 150˚C and 175˚C, while in a geothermal setting the same would be said in the range of 150˚C to 350˚C. The flow for a geothermal well is up to 10 times higher than that of an oil well, and this requires a larger diameter. Furthermore, geothermal operations are normally set up for beyond 20 years of use, which naturally influences design. In addition to the higher temperature, there are often higher pressures experienced at the wellhead requiring specific considerations to valve designs. As more progress is made along the energy transition journey, there are numerous companies in the renewable energy sector looking to utilise the experience and technology of the oil and gas industry. Despite any unique challenges in geothermal wells, skills and knowledge built up over many years are largely transferable, and Richter explained how this can be applied to drilling. “With the increased development of geothermal projects where there is limited space on the surface, comes an increased demand for directional drilling efforts – this can be the case for heating projects in urban areas or as an increased effort for enhanced geothermal systems (EGS). Experience and technologies [drilling] from the oil and gas industry can make a huge impact. At the same time, efforts to speed-up drilling and decrease drilling costs will continue to be key elements going forward. The geothermal sector requires larger investment in order to grow the market and increase the demand for sub-surface experience and services of oil and gas service providers. Oil and gas industry experience can
also be applied in terms of funding exploration, engaging with stakeholders, and paired with investment across the value chain of geothermal.”
The case for technology transfer Technology transfer is already taking place and can be seen in geothermal well construction. However, Richter believes that we will see more going forward, particularly in directional drilling and drilling related technologies. “This transfer of know-how, experience, and technology will require further collaboration and co-operation between the two sectors. Increased interest in the geothermal sector (from oil and gas) creates a momentum that sees strong exchange and will create opportunities for both. The scale will be dependent on the long-term commitment made by the oil and gas sector, as well as the economic and political environment.”
Figure 3. WAB – qualified and tested to the highest industry standards.
Applying hydrocarbon expertise
Going deeper for better results
As geothermal technology continues to develop, oil and gas completion solutions can offer the growing geothermal market the option to not only revive existing shut-in wells, but also develop new geothermal wells with a prolonged and reliable lifespan. Welltec has been adapting its expertise from the hydrocarbon sector and applying it to geothermal energy, enabling operators to optimise well design while minimising the risks and challenges associated with formation uncertainties and high temperatures. Oil wells can be extremely deep – to date, the deepest is at BP’s Tiber Field in the Gulf of Mexico at 10 668 m vertical depth. When considering vertical and horizontal drilling (directional drilling), the Sakhalin well in Russia comes in at a lengthy 14 900 m. The depth of geothermal wells varies dramatically depending on their region. In the Philippines and Iceland, the wells tend to be relatively shallow, often approximately 2 km, which is not very deep. When looking at places with no volcanic activity, such as Finland – where the hot rocks are nowhere near the surface – drilling can be required as deep as 6 km to reach sufficient heat. Geothermal wells employ both vertical and directional drilling. The primary requirement for a vertical geothermal well is a hydrothermal system with sufficient water or steam trapped in a permeable formation. In a country like Iceland, with its abundance of water and vigorous volcanic activity, drilling is undertaken vertically. However, with a vertical well there is less contact with the rocks. In some of the recent geothermal activities in North America, the heat from the rocks has been at the lower end of the required threshold, so a deviated well is needed to maintain contact – these wells have a lot in common with oil and gas operations. The optimal solution in these situations would be a horizontal well, but despite the obvious advantages and numerous efforts, horizontal wells have yet to become widely established in the geothermal setting. However, as geothermal energy looks to become more widespread, using deeper and more solid formations will likely come into play.
To fully utilise the capacity of geothermal energy, the use of improved systems at greater depths is required, as conventional geothermal systems are limited to a few geographical hotspots around the world. This has been contemplated for years in the form of hot rock or EGS. This is where completions experience from the oil and gas industry can play a pivotal role in the creation of horizontal systems with zonal isolation, and help fully take advantage of formation heat conductivity. It is not just in the technology arena that companies such as Welltec can share their expertise. The oil and gas industry has been highly regulated since its inception, and this is a trend that geothermal operators are now having to address. Despite differences between regions, the global experience of the oil and gas industry can help prevent undesired migration of fluids or gases through the lithosphere in a geothermal context; this is generally not permitted as a consequence of operations. A solution developed over many years in oil and gas wells is the ‘packer’. When relining a well, a packer is installed inside the casing and provides a base for cement to cover the previous casing that is damaged. These packers are specifically modified for geothermal application, first because it is vital that there be no trapped fluid, steam, or gas during relining, and second to mitigate for extreme thermal cycling over the life of a well. Another role for these packers – that conventional geothermal wells are already benefitting from – is cement assurance. This is when a packer is installed to isolate a loss zone or cold feed zone, again providing a base for the cement. This essentially creates a strata system at the point of the relevant zone to guarantee the integrity of the casing. With many similarities to the oil and gas industry, it is possible to draw on decades of experience to help manage these challenges in geothermal systems. Much like with oil and gas, geothermal wells require drilling in open hole, as well as a certain degree of cementing in order to achieve casing integrity, and that is where Welltec has earned its reputation in completions over the past decade.
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Suntrace and Innosea collaborate on floating solar project Innosea has been appointed to a consortium led by German Suntrace GmbH (Suntrace) and tasked with the development and tender support of a marine floating solar photovoltaics project (FPV) in the Maldives. Innosea will team up with Suntrace as well as Renewable Energy Maldives (REM) and two environmental and social consultants to work on this forward-looking project. The assignment encompasses technical support to the Maldivian government to develop floating solar in seawater near various islands within the archipelago. As such, Innosea will provide preliminary estimates of the potential for FPV in two regions of the archipelago, proposals on international best practices for FPV development, support to the upcoming tendering process, and co-ordination for the deployment of a 12-month site-specific data collection. The project is part of the Accelerating Renewable Energy Integration and Sustainable Energy (ARISE) programme – an initiative funded by the World Bank to accelerate the integration of renewable energy sources in the Maldives and in particular island states, to overcome challenges caused by climate change. The project also includes a 12-month current and wave measurement campaign to qualify site conditions and allow for further site selection and FPV plant design. Suntrace will provide technical and advisory services across all project phases from origination to operation.
JTC and Shell sign solar MoU JTC Corp. and Shell Singapore have signed a non-binding Memorandum of Understanding (MoU) supported by the National Environment Agency and Energy Market Authority to jointly explore developing a solar farm on part of Semakau Landfill, south of the Singapore mainland. If successful, the solar farm would reduce the country’s carbon emissions and meet its growing clean energy needs. The solar farm will also be the first large scale solar project in Singapore where a sanitary landfill is also used for clean energy generation. This project is aligned with Singapore’s target to increase solar deployment to at least 2 GWp by 2030. The solar farm is expected take up an area of 60 ha. and have a capacity of at least 72 MWp, sufficient to reduce CO2 emissions by 37 000 tpy. The energy produced can power up to 17 500 households for a year. Shell’s Pulau Bukom Energy and Chemicals Park is close to Semakau Landfill, located approximately 2 km northwest of it. Working together allows an innovative integration of an intermittent renewable source to Bukom. Tan Boon Khai, CEO of JTC said, “JTC is piloting new sustainable energy innovations with Shell to maximise the use of renewable energy solutions for our industries. This project is an example of how we are tapping available land to double up for solar generation to maximise renewable energy generation. “Such close collaborations is part of our SolarLand initiative to optimise available land for solar generation in support of Singapore’s clean energy switch.”
Gransolar Group awarded contract for Australian hybrid project Grupo Gransolar, a business group in the development, construction, and supply of photovoltaic (PV) plant components, has been awarded the sole contract to carry out the 5 MW Dalby Hybrid Power Plant EPC. Located in the Dalby region of Queensland, Australia, the BESS facility will feature 2.7 MWdc of PVs and a 2.5 MW/5 MWh energy storage system. According to the company, once connected to the grid, the project will supply power to Ergon, a grid service provider in the region. The plant’s technical solution is designed to provide maximum flexibility with the ability to access the maximum number of markets and revenue streams, including arbitrage
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and FCAS services. Grupo Gransolar supplies the plant controller/energy management system, which has already been tested in different electricity systems and is capable of operating under different grid codes and providing different applications such as energy arbitrage, ancillary services, and/or microgrid control, among others. Keeping with its commitment to creating jobs in the local communities where it operates, Gransolar reports that approximately 50 workers will be employed throughout the construction of the Dalby Hybrid Power Plant. The Dalby Hybrid Power Plant is expected to be operating at full capacity by early 2022.
GLOBAL NEWS Vattenfall starts construction of Hollandse Kust Zuid wind farm
Vallourec takes part in Hywind Tampen project
The construction of the 1.5 GW Hollandse Kust Zuid offshore wind farm started on 5 July 2021. The first vessel transporting foundations to the construction site departed on the same day. Over the next two years, the subsidy-free offshore wind farm will be built off the Dutch coast. The fossil-free energy generated by the wind farm will benefit both households, businesses, and industrial partners. The construction works for Hollandse Kust Zuid start with the installation of monopile foundations. Each foundation is designed specifically for the location where it will be installed. The heaviest and largest monopile weighs 955 t and is 75 m long, while the lightest and shortest foundation still weighs 735 t and is 62 m long. The monopiles will be installed in water depths varying from 17 - 28 m. An installation vessel transports the foundations to their offshore location and positions itself at the exact location. The ship’s crane then lifts the monopile into the water and lowers it until it reaches the seabed at a depth of 17 - 28 m. Once the foundation is in position on the seabed, a hydraulic hammer is used to drive the pile to the desired depth. Vattenfall is building Hollandse Kust Zuid together with its recently announced partner BASF. The wind farm will be located approximately 18 km off the coast of The Hague and Zandvoort, the Netherlands, with the furthest turbines located 36 km offshore. When fully operational, Hollandse Kust Zuid will be one of the largest offshore wind farms in the world. The 140 turbines have a combined installed capacity of 1.5 GW.
As the provider of engineering, procurement, and construction (EPC) services, Aker Solutions commissioned Vallourec to provide seamless hot formed hollow sections for Equinor’s Hywind Tampen floating wind project. Hywind Tampen is an 88 MW floating wind power project intended to provide electricity for the Snorre and Gullfaks offshore field operations in the Norwegian North Sea. It will be the world’s first floating wind farm to power offshore oil and gas platforms. For this cutting-edge project, Aker Solutions required pipe material direct from an approved and audited pipe manufacturer. Having already undergone mill and product auditing in 2014, Vallourec fit the bill. “Aker Solutions needed 13 different pipe sizes for the various boat landings and service decks they were building, and we were able to meet that demand,” said Stephan Scherf, Sales Manager of Global Onshore and Offshore Construction Projects at Vallourec. In total, Vallourec supplied 340 t of seamless hot formed hollow sections in square, rectangular, and round shapes, partly blasted, and coated and in accordance with NORSOK standard M-120, Material Data Sheets Y27 and Y07. The Vallourec Plug Mill in Rath-Düsseldorf, Germany and the Continuous Mill in Mülheim, Germany, produced the range of 13 sizes needed for the project. Vallourec has already supplied over 20 000 t of hot formed seamless hollow sections for offshore wind farm projects around the world.
Ørsted, Falck Renewables, and BlueFloat Energy forge new partnership Ørsted has announced a partnership with Falck Renewables and BlueFloat Energy to participate in the upcoming ScotWind leasing round. The consortium is set to apply for seabed leases in sites which lend themselves to the deployment of large scale floating wind technology in Crown Estate Scotland’s upcoming ScotWind leasing round. Since pioneering one of the first offshore wind farms in 1991, Ørsted has developed and built more offshore wind projects than any other company in the world. Combining this track record with BlueFloat Energy’s knowledge and
experience in developing, financing, and executing floating wind projects and Falck Renewables’ track record in global project development and community engagement in Scotland in particular, the consortium is well placed to deliver successful floating offshore projects. Unlike more traditional bottom-fixed offshore wind technology, where the turbine is mounted on top of a structure fixed to the seabed, floating wind projects use a floating foundation anchored to the seabed by mooring lines, allowing projects to be sited in deeper waters further away from the coast.
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GLOBAL NEWS ScottishPower Renewables launches biofuel pilot project ScottishPower Renewables has launched an innovative pilot project to reduce its carbon emissions by using waste vegetable oil to help power crew transfer vessels working on its flagship East Anglia ONE offshore wind farm in the UK. Supporting the company’s commitment to net-zero, the renewable vessel fuel, HVO30 – made from 30% hydrogenated vegetable oil and a marine gas oil fuel blend – will be used to power two crew transfer vessels provided by Great Yarmouthbased NR Marine Services. Compared to standard marine gas oil, HVO30 is predicted to result in approximately a 30% reduction in equivalent CO2 emissions from the two vessels. The renewable fuel is created from 100% waste vegetable oils and holds a proof of sustainability certificate from the International Sustainability and Carbon Certification (ISCC) system.
Versalis and Saipem team up on sustainable bioethanol technology Versalis and Saipem have signed an agreement to internationally promote PROESA®, Versalis’ proprietary technology used to produce sustainable bioethanol and chemicals from lignocellulosic biomass. Versalis and Saipem will provide integrated and technologically advanced solutions for the sustainable production of bioethanol. The PROESA process does not use crops intended for human consumption as a raw material, but rather produces second generation bioethanol (referred to as advanced biofuel in the EU) through a process of hydrolysis and subsequent fermentation of agricultural biomasses available in abundance, such as agricultural waste, wood chips, and energy crops. Versalis will manage the commercial aspects relating to the granting of licence rights of the PROESA technology and will provide engineering, assistance, and training services. Saipem will be responsible for all the stages of production plant developments, from design to construction. Furthermore, the two companies will collaborate with a dedicated joint team to further developments in the industrial process.
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Bedeschi to supply equipment for Albioma’s biomass transition Albioma has developed a unique partnership with the sugar industry over the last 25 years, for the use and combustion of bagasse (a fibrous residue from sugar cane), which significantly contributes to the energy autonomy of the French Overseas islands, which burn bagasse in their energy thermal plants during six months of the year (coal burning being used for the other six months). Albioma has now begun a new project at its thermal plant of Bois Rouge in La Réunion, which will have a significant impact on the environment by converting the existing boilers from using bagasse and coal to fully green energy combustion. This plant, which produces more than 20% of the island’s electrical power, will fully give up coal and replace it with biomass combustion by the end of 2023, thereby contributing to the increase in the renewable energy quantity of La Réunion’s total energy mix from 35% to 51%. Bedeschi’s scope of supply involves Albioma installations at the Port of La Réunion, which will allow the unloading and storage of imported wood pellets from vessels. Bedeschi services are realised on a turnkey basis. They include two eco-hoppers, belt conveyors for transporting wood pellets to the domes of 45 000 m3 each, with a flow capacity of 1200 m3/hr. Moreover, Bedeschi will supply underground conveyor systems with a capacity of 1000 m3/hr to load the trucks.
THE RENEWABLES REWIND > ARENA to fund RayGen’s ‘solar hydro’ power plant > COSCO and Kongsberg sign wind energy agreement >>IEA: Hydropower is the forgotten giant of clean electricity Follow our website and social media pages for more updates, industry news, and technical articles.
Wave energy companies secure project funding
Sustainable Marine’s tidal turbine rotors pass rigorous testing
Projects led by Apollo Offshore Engineering, Blackfish Engineering Design, and Quoceant have secured funding from Wave Energy Scotland. The projects will demonstrate technology to enable the quick connection and disconnection of wave energy convertors, reducing operating costs and improving offshore safety. The three companies will share nearly £1.8 million for projects that aim to bring down the cost of wave energy. Apollo’s PALM connector uses a passive locking mechanism that provides the connection and load transfer between the wave energy convertor and its moorings. This function is purely mechanical and requires only the input of a suitable deck winch on the installation vessel. Blackfish Engineering Design’s C-DART provides a remote installation system for a WEC or other floating system. The system allows quick connection and disconnection of a wave energy convertor to an offshore buoy, providing both a mechanical mooring and electrical connection. Quoceant’s Q-Connect design is a set of modular subsystems that can be combined in different configurations to provide quick, safe, and low-cost connection for wave and tidal energy devices. The system can cater for slack and taut moored devices on the surface or subsea.
Sustainable Marine’s new turbine rotors have proven they can survive for two decades in the field, following rigorous tests at a leading European marine energy centre. The firm joined forces with the MaREI Centre at the National University of Ireland, Galway (NUI Galway), through German engineering partner SCHOTTEL Hydro, to test its new ‘ultra-durable’ turbine rotors. The project was delivered under the Marinet2 – Horizon 2020 programme supporting offshore renewable energy testing across the EU. Sustainable Marine’s floating tidal energy system uses a common drive train and two different rotor diameters, measuring 6.3 m and 4 m, to suit requirements at different resource sites. Having completed extensive tests on the 6.3 m rotors at NUI Galway, the company returned to the Irish facility to assess the performance of its shorter 4 m rotors, specifically designed for stronger resource sites. The laboratory carried out accelerated lifetime testing, subjecting the rotors to conditions equivalent to 20 years of operation in the field, in just a matter of weeks. Sustainable Marine is currently preparing to deliver the world’s first floating tidal energy array in the Bay of Fundy, Nova Scotia, Canada.
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