Energy Global - Winter 2020

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26. Russia's hydropower revolution

03. Comment

Stanislav Degtyarev and Ivan Sliva, RusHydro, Russia.

04. The windy kingdoms

Susanne Andresen, Monika Golas, and Sonia Mlada Passos, Rystad Energy, Norway.

32. Doing the heavy lifting Peter Libert, Sarens, Belgium.

38. It's time to supersize

Tom Whittle, Taiwan, and Daniele Caruso, UK, Offshore Wind Consultants (OWC). Susanne Andresen, Monika Golas, and Sonia Mlada Passos, Rystad Energy, Norway, consider the steady expansion of renewable energy in Scandinavia, which is being primarily propelled by wind power.

44. A floating gold rush


Graham Stewart, Anni Piirainen, Kate Johannesen, and Adrian de Andres, Xodus Group, UK.

t a time when the energy market is more tumultuous than ever, Scandinavia is blazing a pathway towards energy transition with classic Nordic elegance; straightforward technologies deployed with stepwise minimalism. Establishing itself as an early leader, the region has essentially tripled its variable renewable energy capacity from solar photovoltaics (PV) and from onshore and offshore wind in the past decade, and it shows no signs of stopping. Undeterred by the ravages of COVID-19, renewable energy auctions will continue as planned in Norway, Sweden, and Denmark. The CO 2 intensity of total primary energy demand in all three Scandinavian nations has traditionally been well below the European average, and a recent study by Rystad Energy demonstrated that pioneering efforts to electrify oil and gas operations in Norway have resulted in



50. Getting wind of robots

Danny Constantinis, Executive Chairman, EM&I Group, Malta.



10. Wave energy, a heartbeat away Patrik Moller, CorPower Ocean, Sweden.

16. The mothership of baseload power Gregory Frébourg, Bruce L. Cutright and Regan Frébourg, GeoFrame Energy, LLC, USA.

54. A tale of two towers

Adam Kankiewicz and Frank Jakob, Black & Veatch, USA.

60. Where two worlds meet Luce Reboul, Voltalia, France.

64. A green new world

Branislav Safarik, COO, FUERGY, Slovakia.

68. Leave nothing to waste Dr. Ilkka Virkajärvi, Ductor Oy, Finland.

22. The solution lies deep in the well Joseph Scherer, CEO, GreenFire Energy Inc., USA.

72. Global news



The Strokkur Geyser erupting at the Haukadalur geothermal area in the south of Iceland. Energy Global is a digital magazine providing an international perspective across all spectrums of the renewable energy industry. Subscribe for free at

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ell here we are, Winter 2020, and the end of a long year of uncertainty and dreams to skip ahead to 2021. Yet amongst the year’s woes, the event cancellations, social distancing measures, travel restrictions and more, the renewable industry has not drastically faltered. Instead, the news from the industry each day has been of new technologies, project contracts signed, funding agreed, climate change agreements strengthened – the list of positive developments goes on. Considerably different to the year experienced by fossil fuel markets, which have suffered under the COVID-19 pandemic, the IEA has reported that renewables used for generating electricity will grow by 7% in 2020. In fact, installed renewable capacity will have increased 4% during the year, primarily driven by China and the US. One of the main contributors to this year’s growth is hydropower, with the commissioning of two large projects in China carrying the majority of the capacity (26 GW between the two projects), and confident expectations for continued additions in 2021 and 2022. A potentially significant change since our Summer 2020 issue is the change of presidency in the US. Joe Biden, the President-elect, has expressed a goal to put the US on course for net zero greenhouse gas emissions by 2050, as well as re-entering the country into the Paris Agreement. Moreover, Biden’s policies include the development of offshore wind, and with the US being one of the largest markets in the world for renewables, this will be a country to keep an eye on over the coming years. One area that our eyes have been focused on for a while, is Europe. In a recently published report by the European Commission (EC) to detail the EU’s strategy to harness the potential of offshore renewable energy, the leading role played by the EU in the offshore wind, wave,

and tidal industries is evident. The first offshore wind farm in the world was built in Denmark, and Europe has a first-mover advantage in bottom-fixed wind turbines, meanwhile EU companies hold 66% of patents in tidal and 44% of patents in wave energy. The EC has grand plans to further Europe’s offshore prowess, with an objective to increase the capacity for offshore renewable energy by almost 30 times by 2050. This comes at a cost (mainly investment in infrastructure of grids and ports) of €800 billion. It is all well and good having big dreams and objectives, but there are underlying challenges that cannot be ignored. As with any industry, not just renewables, there are issues concerning the labour force, with skills gaps and skills available in the right locations being problematic – reportedly, up to 32% of companies in the renewables sector are experiencing skills gaps. However, the EU’s plans to scale up its offshore renewable energy do come at an ideal time, as it could greatly assist in the post COVID-19 recovery. And with the ‘word of the year’, as categorised by Collins Dictionary, for 2020 being ‘lockdown’, a new focus of ‘recovery’ sounds far better. In this issue of Energy Global magazine, our technical articles cover a variety of renewable energies, including a report on the Scandinavian region, hydropower projects in Russia, reasons for expanding the use of geothermal energy, and the technology behind floating offshore wind, plus many more. As an unusual 12 months draws to a close, the Energy Global team would like to thank you all for your support since we launched in the summer, and we look forward to continuing to provide you with current and informative market news and developments as we move into 2021. Wishing all our readers a healthy and prosperous holiday season.

Susanne Andresen, Monika Golas, and Sonia Mlada Passos, Rystad Energy, Norway, consider the steady expansion of renewable energy in Scandinavia, which is being primarily propelled by wind power.


t a time when the energy market is more tumultuous than ever, Scandinavia is blazing a pathway towards energy transition with classic Nordic elegance; straightforward technologies deployed with stepwise minimalism. Establishing itself as an early leader, the region has essentially tripled its variable renewable energy capacity from solar photovoltaics (PV) and from onshore and offshore wind in the past decade, and it shows no signs of stopping. Undeterred by the ravages of COVID-19, renewable energy auctions will continue as planned in Norway, Sweden, and Denmark. The CO2 intensity of total primary energy demand in all three Scandinavian nations has traditionally been well below the European average, and a recent study by Rystad Energy demonstrated that pioneering efforts to electrify oil and gas operations in Norway have resulted in




the lowest upstream CO 2 footprint in the world. Yet much opportunity for renewable development remains if the region is to solidify its place as “the most sustainable and integrated region in the world”, as Scandinavian prime ministers jointly stated in the summer of 2019. Utilising Rystad Energy’s global renewable energy data, the curtain is pulled back to see what stories will unfold over the next five years in Denmark, Sweden, and Norway.

Strong development pipeline in Scandinavia to further accelerate Rystad Energy estimates the operating capacity of all variable renewable energy sources in Scandinavia will surpass 17 GW by the end of this year – almost a four-fold increase from the region’s 4.5 GW of capacity in 2010. An expansive development pipeline (meaning projects across all stages of development) will ensure that production will continue to soar. Rystad Energy forecasts that

Scandinavian capacity will nearly double again over the next five years, reaching approximately 33.5 GW in 2025. In terms of sheer capacity, Sweden will lead the way. The country already has an impressive lead, with just under 8 GW of currently operational capacity from over 330 assets. The country’s operating capacity will nearly double to 15 GW in 2025, growth which primarily comes from projects already – or soon-to-be – in the construction phase of development. This means lower risk, and greater certainty the development pipeline will come to fruition. By 2025, Norway will follow its neighbour, Sweden, with an estimated 10 GW of operating capacity from onshore and offshore wind. The country will see the greatest expansion over the five-year period relative to its Nordic cousins, with variable renewable energy skyrocketing to more than three times its present size (approximately 3 GW). It should be noted that this growth represents a step change in terms of renewable energy technology in the country, as Norway has traditionally been known for hydropower and currently boasts around 32 GW of hydroelectric capacity. Much of the new growth will come from onshore wind projects that are currently in the application stage; risks to the pipeline could therefore yet materialise. Finally, Denmark will expand its variable renewable energy capacity to almost 8 GW by 2025, a gentle increase from its currently operational capacity of 6 GW. Given that the country is approximately one-tenth the size of its Nordic counterparts geographically, this is impressive growth and surely a reflection of the country’s unquestionable pedigree as a pioneer in the global wind market.

Figure 1. Renewable energy capacity growth in Scandinavia since 2010.

Figure 2. Scandinavian renewable energy capacity growth by development status.



Wind to blow away all other technologies New renewable capacity additions in the next five years will be overwhelmingly dominated by wind – primarily onshore wind – a fact that comes as no surprise given the windy weather patterns in the region. In Norway, onshore wind will comprise more than 98% of new additions in the next five years, with the remaining capacity coming from offshore wind, especially the 88 MW Hywind Tampen floating wind development in the North Sea. Nevertheless, offshore wind in the country has recently generated quite a bit of buzz; in June, Norway announced that it will open the Utsira Nord and Sørlige Nordsjø II areas for offshore wind development, potentially adding 4.5 GW of offshore capacity. Aker Offshore Wind has already publicised two concepts targeting these areas, Sønnavindar and Vestavindar. While these developments are not expected to materialise before 2025, the tender round will open as soon as 2021

and several projects could come online by the end of this decade. Similarly to Norway, 98% of new renewable capacity in Sweden will also come from onshore wind, most notably from the vast three-phase Markbygden 1101 cluster. Upon completion, the development will feature an impressive 1101 turbines and will be the largest wind farm in Europe. The first phase, the 650 MW Markbygden ETT subproject, achieved operational status in January 2020. Over 1.5 GW is currently under construction or in the pre-construction phases – almost 340 turbines, including the largest sub-project within the cluster, Önusberget. Owned by Luxara, the 750 MW Önusberget wind farm will make up a large share of the third phase of the Markbygden 1101 cluster. Figure 3. Wind resource and asset overview for Scandinavia. Only approximately 2% of Sweden’s variable renewable energy capacity will come from offshore wind or solar, although the country has a robust backlog of offshore wind projects. However, despite developer assurances, Rystad Energy’s research indicates that these projects will not materialise until after the company’s analysed time period, post 2025. Nevertheless, Sweden’s offshore wind market will be interesting to watch in the longer-term. On the solar side, the share of solar in the country’s energy mix will continue to increase. This includes the country’s largest ever solar park, the 20 MW Strängnäs development in eastern Sweden, which is expected to complete commissioning in 2021. As seen in Figure 3, both Norway and Sweden have a relatively high onshore Figure 4. Denmark renewable energy market share shift. wind index. This benchmark indexes the wind resource of a region relative to that governmental body’s gross domestic solar PV and, predominantly, offshore wind. Significant product (GDP). This allows Rystad Energy solar PV additions will be seen in the southern and western to visualise areas that are both exceedingly windy and areas of the country, growing from approximately 219 MW have the capital to put that resource to work. Figure 3 to 987 MW of capacity. This includes the 200 MW Holstebro illustrates that the entire length of Norway is dotted with development, expected to start up in 2021, which will municipalities exhibiting the highest onshore wind index be Northern Europe’s largest solar farm to be installed levels, with the west coast particularly crimson. Similarly, without subsidies. The 155 MW Vandel 3 solar project is Sweden’s eastern and southern regions are dabbled also expected to come online in 2021, completing the in deep orange and red, showing great wind resource three-part Vandel solar farm. prevalence. As one would expect, these are the regions But it is offshore wind that will really make a splash Rystad Energy anticipates will see the most onshore wind in the coming years, expanding from approximately development in the next five years. 1.7 GW of capacity in 2020 to nearly 4 GW in 2025. Exciting It can also be seen that Denmark stands out as offshore projects to watch include the huge 605 MW the most diverse Scandinavian country in terms of Kriegers Flak development, which will start up in 2021 technologies to be deployed. By 2025, the share of onshore and will be operated by Vattenfall, and the 240 MW wind in Denmark’s variable renewable energy mix will fall Jammerland Bugt development, which is being developed to just under 40%, as market share gains will be made by



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by European Energy and is expected to start up in 2024. Additionally, the tendering process for two offshore award rounds has been sped up, and is now scheduled to take place in 2021. The Thor tender will offer 800 ‑ 1000 MW and the Hesselø tender will offer 800 ‑ 1200 MW, and are expected to be completed in 2021 and 2022 respectively. The country’s growing offshore wind capacity comes as no surprise – the Danish archipelago has a proud history of wind innovation and has dominated the wind turbine market for years, along with its neighbour Germany. Indeed, the top six turbine manufacturers to supply the wind surge in Norway, Sweden, and Denmark are all either Danish or German. Danish player Vestas Figure 5. Top turbine manufacturers supplying the Scandinavian market. is in a league of its own in this regard and is expected to supply turbines for a significant 9 GW of the wind growth in the region, almost exclusively within onshore wind developments. developments with 400 - 800 MW of capacity. In Denmark, German manufacturer Siemens Gamesa comes in almost 14% of the country’s wind capacity will come second and has established itself as the foremost offshore from such large scale installations, and more than 15% of wind turbine supplier in Scandinavia (Figure 5). Rystad renewable capacity will come from large scale installations Energy estimates that it will supply turbines for almost in Sweden. Indeed, Scandinavian wind is growing rapidly in 2 GW of offshore wind capacity in the region, including scale, a phenomenon which is emblematic of the broader the previously mentioned Hywind Tampen offshore wind global trend. farm and Kriegers Flak wind farm. The company also announced recently that its record-breaking 14 MW turbine The simple elegance of Nordic energy: it’s will be commercial in the mid-2020s, with projects in in the source and the sentiment Taiwan, the UK, and the US naming the turbine as their The Scandinavian nations are certainly endowed with preferred unit. It is therefore not hard to imagine that the an abundance of natural resource, a boon which was company will supply an increasing amount of capacity harnessed in the past through hydropower and small scale in Scandinavia as the offshore market there continues to wind and will now be put to work predominantly through expand. increasingly large scale wind developments. Yet the region is also unique in its overwhelming political support of the energy transition. This year, for instance, Norway became Projects begin to scale as economics one of the first nations to submit an updated climate become more attractive target under the Paris Agreement, doubling down on Globally, it is evident that renewable developments are efforts to reduce emissions by 55% by 2030, relative to 1990 increasing in size to gigawatt-scale installations thanks to numbers. Sweden is even more aggressive, with a stated economies of scale and technological advancements. This goal to decrease emissions over the same time frame is especially relevant for wind, both onshore and offshore, by 63%. Not to be outdone, Denmark has set its goal to as material innovation has allowed for taller turbines decrease emissions by 70% by 2030. and larger rotor diameters, leading to greater capacity – In a joint statement in 2019, the Nordic Council of Prime turbines with 5 - 10 MW of capacity have now become the Ministers described a vision for a “green Nordic region”, norm. With this increase, so too have wind farm capacities promising to “promote a green transition of our societies increased, leading to larger facilities that are able to and work towards carbon neutrality and a sustainable benefit from reduced CAPEX per watt. In other words, circular and bio-based economy.” Indeed, greasing the technological advancement has led to economies of scale, wheels of the Scandinavian energy transition with positive which begets more energy per dollar invested. sentiment certainly appears to have quickened the pace This shift is already underway in hotspots around the of change; new renewable energy capacity in Denmark, world and is quite apparent in Scandinavia, especially Sweden, and Norway increased by 145% in 2019 – a huge so for onshore and offshore wind. By the end of 2020, all and tangible stride towards achieving the countries’ of Norway’s wind capacity will come from developments emissions reduction goals. With no signs of slowing less than 400 MW in size. Only approximately 6% of wind down, it is not unreasonable to expect Scandinavia to capacity will come from projects at or over 400 MW in lead the world in creating a truly green energy system by Denmark, and 8% in Sweden. In contrast, by 2025 more harnessing the power of the wind. than 13% of Norway’s wind capacity will come from



Patrik Moller, CorPower Ocean, Sweden, details a novel wave energy technology using buoys, which is based on the pumping principles of the human heart.



orPower Ocean’s story began in 2009 when inventor and cardiologist Stig Lundbäck pondered the pumping mechanism of the human heart. Stig noted that the heart only pumps in one direction, using stored hydraulic pressure to provide force for the return stroke. He speculated that this process could be replicated in an ocean environment where a device, in the form of a buoy, could store pressure to generate energy from wave power. Shortly afterwards, scaled demonstrations were built over a period of two years showing the viability of the system. By 2012, a techno-economic review was carried out by a group of experts covering hydrodynamics, mechanics, and power generation, before the project was formally accepted by the InnoEnergy incubator programme. Following this breakthrough, CorPower adopted a structured five-stage product verification process in line with recommendations by IEA-OES and the Equimar project. The process published as ‘Guidelines for Development and Testing of Ocean Energy Systems’ incorporated lessons learned from previous wave development efforts. Similar stage-gate development processes were later adopted by entities including ETIP Ocean and funding bodies such as Wave Energy Scotland. By 2013, a scientific collaboration was established with WavEC Offshore Renewables in Lisbon, Portugal, and NTNU in Trondheim, Norway. These partnerships accelerated the initial system design concept, pairing up with the phase-control technology known as ‘WaveSpring’ developed at NTNU. The design principles behind phase-controlled point absorbers build upon more than 40 years of research, and over time CorPower has developed the concept into a robust industrial solution verified through several stages of testing. In the following years, CorPower’s devices were continuously refined while maintaining core technology that mimicked the energy storage aspect of the human heart. Developed in the form of heaving buoys, the Wave Energy Converters (WEC) float on the surface but remain connected to the seabed through a tensioned mooring system. The upward force of a wave swell pushes the specially designed buoy upwards and the stored pressure provides the restoring force driving the buoy downwards. This results in equal energy production in both directions. The device harnesses energy from both the rise and fall as well as the back and forth motion of waves. When stimulated, the light, composite buoy initiates a power take off, in the form of a drive train located inside which converts the mechanical energy into electricity.

Design concept: Storm proofing and energy efficiency Historically, wave energy devices have either broken in storms or simply not produced enough electricity to make it a viable business prospect. CorPower is addressing these two main challenges head on, firstly by using new technology to protect its devices, making them transparent and resilient to the most aggressive storm waves. This function is similar to wind turbine technology where blades will pitch to protect from overspinning in fierce conditions. This sort of protective function has been missing in wave energy to date. The second key development is advanced phase-control technology, which strongly amplifies the response to regular waves in terms of the motion and power capture. For instance, in a 1 m wave, CorPower’s buoys may move 3 m up and down, due to the resonance phenomena. Its devices have been shown to produce five times more electricity per ton than any



Figure 1. A CorPower Wave Energy Converter (WEC) straddles the side of an offshore support vessel at the EMEC Scapa flow test site in Orkney, Scotland.

other known wave technology. On average the devices generate 10 Mwh per ton of equipment installed in the ocean – which is in line with leading floating wind developments.

Key components: Four significant features FFPneumatic pre-tension system – this system creates transparency to storm waves while reducing material costs by 40% compared to a conventional gravity-balanced WEC, in turn reducing CAPEX. The pre-tension system provides downward force on the buoy, replacing the mass that would otherwise be needed to balance the buoyancy at midpoint. As a result, the natural period of oscillation of the WEC is reduced, providing a period of oscillation which is shorter than all ocean waves. The natural state of the machine is the detuned mode where the device has little response to incoming waves.

FFWaveSpring phase control technology – this drives annual energy production (AEP) by 300% for a given buoy size. WaveSpring provides a negative spring function to the system, giving it an inherently resonant response over a wide bandwidth. Optimised phase control is provided without information on incoming waves. The WaveSpring function is deactivated in storms, thereby detuning the device to give significantly reduced loading and improved survivability. In storm-protection mode the WEC is highly


transparent to waves. In operational mode the WEC response is amplified and the operation is close to optimal from a hydrodynamic point of view.

FFCascade gearbox technology – this technology ensures robust conversion of the amplified linear motion into rotation with low losses. The wave energy absorbed into linear motion along the buoy axis is converted into electricity by the mechanical drive train located inside the buoy. A key component is the Cascade gearbox, which efficiently converts linear motion to rotating motion. It has a design principle similar to a planetary gearbox, dividing a large load onto a multiple of small gears – which allows highly efficient and robust conversion of linear motion to rotation. The gearbox industrialisation has been developed in partnership with Swepart Transmission, a major global gearbox manufacturer.

FFComposite hull technology – this is designed to eliminate corrosion issues from salt water and provides the WEC devices with long-term durability.

High structural efficiency CorPower’s relatively small and low-cost WEC device has been designed to harvest large volumes of energy due to its high structural efficiency. The devices are engineered to generate

the same AEP from a buoy with one-tenth volume compared to conventional point absorber WECs. In terms of dimensions, the devices measure 9 m × 19 m and weigh 60 t – dwarfed by the size of other wave energy prototypes, some of which are thousands of metres in dimension and weigh several thousand tonnes, yet have the same capacity. Securing large amounts of electricity from a small device significantly reduces CAPEX, while the compact lightweight devices are also less costly to transport, install and service, bringing down OPEX. The device concept is optimised for 10 MW clusters, where the electricity is collected from an array of WECs into a collection hub. Each 10 MW hub delivers grid quality electricity with standard 33/66 kV electrical connection commonly used in offshore wind, with a single control and data acquisition interface over fibre and radio-link to the hub. A programmable logic controller located inside the devices enables them to operate autonomously. CorPower has a clear path to a LCOE below €30/MWh. From first pre-commercial installations in 2024/2025, the LCOE is projected to drop below €100/MWh after 150 MW installed, and €60/MWh after 600 MW installed by 2030.

Figure 2. CorPower’s HiWave-3 demonstration project involved a large scale (1:2) WEC system which was designed, manufactured, and tested in two steps between 2015 and 2018.

Five-stage product verification process The structured five-stage product verification programme is recognised as best practice in the sector and involves a step-by-step validation of survivability, performance, reliability and economics, ensuring the business case is supported by the physical and economical metrics in each stage from small scale models (2012) to full scale array product (2023). The purpose of this process is to address risks in a managed way early within the product development process, while costs are still limited due to the smaller device scale and team size. This provides a clear path to reach a bankable product with

Figure 3. Delivery of the CorPower C3 WEC in Orkney, Scotland, for the HiWave-3 demonstration project performed by a consortium including CorPower Ocean, Iberdrola Engineering, EMEC, WavEC Offshore Renewables, and the University of Edinburgh.

Figure 4. CorPower C5 WEC devices measure 9 m × 19 m and weigh 60 t.



measure power production in every sea state and compare the rates with data predicted by simulation models, which remain highly accurate. The team experienced a steep learning curve throughout the first three stages between 2012 and 2018. Since then, CorPower has been developing its first commercial scale system called the C4 buoy. In addition, the firm has successfully secured approximately €32 million in funding with the total outlay for phase four and five activities pegged at €55 million, effectively bringing the technology to market.

Portugal expansion and future roadmap

Figure 5. CorPower’s latest C5 WEC technology has resulted from a decade of product development and three decades of research on wave hydrodynamics.

the least time, money, and risk. It marks a sharp contrast to accelerated timelines and rapid scaling that has pushed many other ocean energy projects to failure. A key part of the strategy has involved dry testing each machine in controlled, simulated wave loading on-land, to fully debug and stabilise the machines prior to ocean deployment. The WECs are set to undergo a further rigorous certification process with DNV-GL and independent third-party performance validation from internationally renowned entities including EMEC and WavEC. To date, CorPower has completed three stages of the verification process, which began with small scale testing in Portugal and France. A half-scale system was constructed during stage three before demonstrations began in the Orkney Islands, Scotland, in partnership with utility outfit Iberdrola. During the half-scale demonstration, CorPower carried out dry testing in a bespoke rig in Stockholm, Sweden, where it developed the inside of the wave energy devices, notably the drive train. The firm spent a further six months debugging and stabilising the system, through simulated wave loading in a large scale test rig on land, before moving it to Scotland for ocean testing. Throughout that process, CorPower was able to verify the survivability of the system, using patented technology designed to make the devices transparent and protected from storm waves. Technicians were further able to


In 2020, CorPower announced a major €16 million expansion in Viana do Castelo, northern Portugal, where it aims to complete the final demonstration phase branded Hi-Wave 5. The broader project will see the development of an R&D, Manufacturing, and Service Centre laying foundations for future high-volume operations. The firm is currently in the process of fabricating its first commercial scale system before undertaking dry testing in a bespoke test rig with simulated wave loading in Stockholm, prior to ocean deployment during the second half of 2021. The full-scale device will need to demonstrate it can survive the toughest storms in the exposed Atlantic Coast site in Aguçadoura, northern Portugal, for around 12 months. The team will then complete one more design update before unveiling the final commercial stage technology in the form of its C5 machines. A total of three C5 machines will be installed in the ocean in 2023, running for a little over a year to secure type certification. CorPower is ultimately planning to become a leading original equipment manufacturer (OEM), building devices, completing final assembly, and also offering operations and maintenance contracts to customers who will be operating the wave farms.

The wider clean energy mix This new class of WECs is expected to be highly competitive with existing ocean technologies within the coming decade and with wind and solar by 2030. While wind and solar play significant roles to decarbonise electricity systems, their intermittency and low predictability result in volatility in the electricity markets. Already today, markets with high penetration of wind and solar see negative electricity prices when it is windy or sunny over larger regions, and price spikes when production is insufficient to meet demand. Wave farm owners will have a generation asset producing electricity that can be sold at higher average prices with an LCOE on par with other renewables, offering a higher margin business. Wave energy provides a balancing source that enables high penetration of wind and solar at the lowest possible system cost. It also works hand-in-hand with hydrogen production, with a wind/solar/wave electricity mix offering a more constant operation with higher profitability for electrolyser operators. In the lowest cost zero-carbon scenarios, renewable hydrogen will be used primarily for industry and transport, while wave energy and other complementary electricity sources help balance the electricity system without requiring as much long-term storage capacity. Ultimately, wave energy will have a key role in the lowest-cost route to reach 100% renewables.

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enewable generation technologies are generally thought of as power generation derived from a source that is continuously replenished or sustainable. Wind, solar, and geothermal all rely on sustainable sources of energy; solar uses the radiated energy of the sun, wind harnesses the energy carried by the movement of air masses, and geothermal converts the thermal energy flow from the Earth’s interior to produce electrical power. Wind, solar, and geothermal have fundamental differences that control their costs, their yield, their online availability, and their required infrastructure. Furthermore, there are geographical limitations for each source. The crucial difference between these three renewables is that wind and solar rely on intrinsically intermittent sources of energy and must include methods for voltage and


Gregory Frébourg, Bruce L. Cutright, and Regan Frébourg, GeoFrame Energy, LLC, USA, highlight the unique advantages of geothermal energy and discuss the necessary steps needed to encourage the use of this underutilised power source.



The reasons for this year-round sustainable power source not being more widespread or simply more popular usually stems from a lack of understanding of geothermal generation and development. From the public’s perception, geothermal resources lie hidden deep underground in the mysterious subsurface where they require extensive studies and knowledge to be discovered and characterised, as opposed to the easy, simple, surface measurements for wind and solar developments. However, by using analytical methods and technology derived from the oil and gas industry, where risk mitigation and cost optimisation have been part of everyday operations for over a century, geothermal power can be developed successfully with very little risk.

Limitations of wind and solar generation

Figure 1. Capacity factor for geothermal, solar photovoltaics, and wind.

Solar and wind power generation are great within their operational boundaries. They are efficient and affordable when their source of energy is available. Their operation does not generate pollutants locally and their noticeable presence in the landscape is often tolerated by the population as a visible reminder of progress, where society inches towards a sustainable use of resources and respect for the environment. Every medal has two sides, and these benefits come with costs which are, more often than not, ignored or downplayed.


Figure 2. Comparison of surface requirements per installed megawatt between wind, solar and geothermal.

power stabilisation and alternate generation sources for when they are unavailable. Battery storage or fossil fuel generation are the most common complements to wind and solar, but the costs of these other required generation methods are frequently ignored to the detriment of understanding their fully loaded costs. Geothermal power generation is continuously available and does not require alternate sources or voltage stabilisation components, and when properly designed, can provide both baseload generation and load following generation. Energy storage or supplemental generation sources are not required with geothermal power.


While recent technological advances have significantly reduced costs and increased solar photovoltaic (PV) panel efficiency, it still requires a large surface area. Solar panels have an inherent limited online availability, producing at best six to eight hours of power per day when the sun is relatively high in the sky and not obscured by clouds. It does not produce energy at night (Figure 1). To provide significant power capacities, large swaths of ground must be cleared and kept barren to avoid interference with the operations. Surface requirements per installed megawatt of solar power are nine to 45 times larger than for geothermal (Figure 2). Furthermore, passing clouds have an instant, negative impact, dropping power output from a solar panel by 80% ‑ 90% in seconds. To provide baseload power, solar needs storage systems and sufficient reserve generating capacity to both maintain a useful output and to recharge whatever storage system is selected. Solar panels also need certain, sometimes rare, elements to increase their efficiency, requiring critical mining facilities to produce and refine the necessary raw materials. Local negative environmental impacts can be significant, especially when mining takes place in countries with lax environmental policies.

Wind The larger the wind power output needed, the larger the turbines and/or their number must be. Turbines must be properly spaced to minimise interferences and maximise the yield: surface requirements per installed megawatt

of wind power are between 22 - 1200 times larger than geothermal (Figure 2). Suitable wind output is only available approximately 29% ‑ 44% of the time, during which microvariability in wind speed ranges between 15% - 80% over periods of less than 30 sec. (Figure 1). The operating range of wind speeds is often relatively narrow, outside of which the individual wind turbines must be curtailed to protect their generators from overspeed damage. Environmental concerns around wind power are high: neighbouring communities often oppose wind farms on visual and noise grounds, and rotating blades represent a significant danger to birds. An increasing number of studies suggest that wind farms also influence local climate, but to what extent is still being studied. Wind turbines also require rare earth elements to dope their magnets and increase efficiency, creating a negative environmental impact from mining for these materials.

Battery storage for wind and solar Interest in battery storage to help intermittent renewable power sources to provide baseload power to the grid has increased recently as the price of batteries has declined. Battery storage facilities are charged when the renewable source allows it, and supply power during the times the renewable source is absent or cannot meet the grid demand requirements. However, battery storage cannot supply power indefinitely. It has a finite capacity and requires recharging, which comes with up to 30% associated losses. The larger the demand for stored power is, the larger the generating source for its recharging must be. Battery storage uses chemicals sourced by environmentally aggressive extraction methods. The initial costs are followed by significant maintenance costs. Performance and efficiency degrade over time and batteries, cells, and electrolytes need to be replaced. Real world numbers call for four times the installed solar or wind farm’s power capacity to become baseload using batteries, quadrupling the surface, environmental, and cost impacts.

Figure 3. Estimated levelised cost of electricity (EIA, 2019).

True costs Solar and wind are the most affordable power generation means when they produce, which is at best, 29% - 44% of the time (EIA, 2019). However, once levelised costs are calculated, and the fully loaded associated costs without tax incentives are included, their cost per kilowatt-hour is significantly greater than geothermal (Figure 3). Omission of tax incentives is a crucial point, as many solar and wind developments rely on these incentives to be competitive or profitable. If wind and solar are considered at the utility scale and as a primary generation source, then for every kilowatt-hour provided by wind and solar, the installed capacity must be increased by a factor of four: three times the installed capacity to provide the power needed to recharge the storage system, usually batteries, and then increased one more time to cover the energy lost in the recharge and discharge cycle of the batteries. Then, the cost of battery storage must also be included, which currently averages approximately US$0.25/kWh.

Figure 4. The difference between installed capacity vs produced power for the 65 geothermal power plants producing less than 90% of their production goal.

Geothermal developments Geothermal developments are not exempt from their own shortcomings. Unsuccessful ventures (usually by inexperienced developers) have given the geothermal industry a risky reputation, often defended with the fallacious argument of the random and mysterious nature of the subsurface. To identify and understand the reasons for past geothermal failures, an in-house analysis of 195 online plants with existing and verified power production data was performed by GeoFrame Energy. All types of geothermal generation systems were reviewed. Some plants were decades old and modernised, others were the



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most recently erected plants with good power production records. The plants were evaluated to assess whether or not they were performing at, above, or below their design capacity. Their resource, design, and development were thoroughly investigated.

Results: The good and the bad A third of the plants showed power production at least 10% below their original installed capacity and, for the purposes of the analyses, were considered a failed development. This lowered performance stemmed from several factors, some of which are not mutually exclusive and are related to both natural and human origin. Reservoir engineering, well design, and well placement all contributed to mismatched plant design and were the most common problems found. Interestingly, no correlation existed between the size of a development and its success (Figure 4). Incorrect or incomplete resource characterisation at the initial stage of development was the most common and detrimental reason for failure. Improper reservoir characterisation led to missed generation output and required additional production wells or the recompletion of wells to meet the performance goals of the project. Overestimated resource capacity, underestimated scaling and corrosion of wells, and extensive downtime associated with well operation and maintenance significantly impacted plant performance. In some cases, the plant was able to be brought up to its nameplate capacity, but in many others, the plant never reached its intended goal for production. Modifying or adapting well plans and completions as wells are being drilled and data is gathered, is not an uncommon practice among developers. When these on-the-fly modifications are implemented because of encountering significantly different subsurface conditions, additional costs and delays result that might have been avoided by a more thorough reservoir understanding. This approach also necessitates the engineering of the well network a posteriori. It was not rare to find projects with several non-productive wells drilled in successive attempts to establish a single good production well. The resulting well network can become a burden of complicated connections between inefficient wells interfering with each other and subsequent decreases in plant efficiency. Multiple mobilisations of drilling operations also significantly increased costs over and above a well thought out and continuously implemented drilling plan. Misinterpretation of good reservoir studies have led to costly adjustments to projects. Well locations selected for ‘expedient’ reasons, rather than to optimise reservoir performance, have led to excessive drawdown and accelerated resource depletion. Salvaging the resource then requires implementing solutions which should have been there to start with, involving drill rig remobilisations and expense. On the positive side, GeoFrame Energy analysis found that two-thirds of the plants were operating at or above

90% of their design capacity (Figure 4). The key to the successful plants were:

FFExtensive and accurate knowledge of the resource. FFProduction and injection well layouts that optimised well locations based on reservoir properties while minimising the resource gathering system.

FFCareful management of scaling and corrosion factors. FFMatching the plant design and generating capacity to the reservoir capabilities. All of these factors are linked together by the importance of using a comprehensive integration of geologic, hydrogeologic, and geochemistry information to support the engineering design of the geothermal plant. There were no shortcuts to success.

Risk mitigation The analysis shows that geothermal developers can easily minimise the development risk following what in hindsight seems like exceedingly straightforward steps. Minimisation of risks requires careful geological study, accurate resource assessment and modelling, adequate well placement and completions, careful well network planning, adapted generation capacity, and sustainable resource management. All the aforementioned steps are the least expensive of costs involved in a development and can certainly be performed before construction begins. Developers need to look at what can go wrong and where, as well as finding one or several solutions for the foreseeable problem. Setting up contingencies for different outcomes is an adequate response to any planned issues without requiring the need for additional remediation funding. Providing that the geothermal system is well understood and characterised, insurance policies can be negotiated for fees that are much more affordable than the financial consequences of an uncontrollable issue. Finally, humility and a healthy dose of realism should be applied so that the resource is developed within its sustainable capacity.

Conclusions Geothermal power is not only cost competitive with wind and solar, but it is the only baseload capable of sustainable power generation type without requiring power storage. While two-thirds of geothermal plants in the review were operating adequately, the reputation of the industry as a whole suffers from the poorly performing projects. The inherent risks of geothermal development can be minimised early on in the project by careful resource and sustainable reservoir management practices, and by including suitable contingencies within the budget. The less that is left to chance, the more predictably successful the project becomes.



Jose USA in


eph Scherer, CEO, GreenFire Energy Inc., A, describes how the latest developments n geothermal technology are poised to expand access to geothermal energy.


or over 100 years, water-based geothermal systems have generated clean, reliable, and continuous electric power from the earth’s inexhaustible heat energy. But, until today, this success has been limited due to the factors that constrain legacy hydrothermal technology to only approximately 2% of the world’s resource.1 Conventional projects with hydrothermal technology require a rare combination of high permeability and vast amounts of water. Drilling to find such conditions is risky with the result that many wells fail to produce sufficient flow, and even successful wells degrade over time. New Closed-Loop Geothermal (CLG) technology aims to expand not only the range of geothermal resources that can be brought into production, but also the ways that clean, continuous geothermal energy can be used. New CLG technology is a major step forward because it overcomes the twin obstacles of insufficient subsurface permeability and lack of water that limit the scope of hydrothermal projects. Instead, CLG uses a sealed well that continuously circulates a working fluid that absorbs and transports heat to the surface. These wells ensure the efficient circulation of the working fluid so that high permeability of the surrounding rock is not required. CLG wells take advantage of advances in drilling and well completion that revolutionised the oil and gas industry. Water availability is no longer a problem because closed-loop wells also make the use of alternative working fluids, such as supercritical carbon dioxide (sCO2), possible. These fluids have the additional advantage of creating a strong thermosiphon, thereby reducing the parasitic power loss created by pumping water through the system. In addition, because no fluid is injected into or extracted from the geothermal resource,



environmental permits are substantially less expensive and less time-consuming to obtain.

Benefits of new energy systems New CLG technology is designed to solve permeability and water issues and enable a more attractive and flexible business model for geothermal energy.

Scalability New CLG technology can be applied across the full range of geothermal possibilities, from fixing a single unproductive well in an existing field to developing large greenfield projects of 50Â MW and up. CLG also aims to substantially boost the power output of existing fields. This is because CLG can extract more heat out of the same resource than conventional technology, which is limited to extracting only as much heat as can be collected through natural fissures. CLG wells can not only extract heat from the moderate depth areas of the resource that lack permeability, but can also go hotter and deeper to extract high temperature heat from the very deep regions that are inaccessible with legacy hydrothermal technology. Scaling up an existing geothermal resource can provide a high return because it leverages the large existing fixed investment in exploration, permitting, infrastructure, and transmission.

Reduced risk and time to revenue Drilling wells with legacy hydrothermal technology is slow and risky because of the need to intersect fissures with sufficient heat and water flow; this leads to the high rate of failure. In contrast, new CLG wells only require sufficient heat to produce power. In fact, CLG well retrofit projects can be thought of as the Plan B for failed conventional wells. The seven years, on average, required to identify, explore, permit, and then develop conventional geothermal projects has been a huge impediment to investment. Because CLG requires much less geophysical analysis and is much easier to permit (because nothing physical is injected or removed that might contaminate water or cause seismic events), a CLG project has a much shorter development schedule. In addition, geothermal well retrofit projects benefit from using existing wells, the characteristics of which are very well understood, so retrofit projects can be completed in as few as six months. Figure 1. Single well with a concentric tube heat exchanger configuration.

Competitive costs with flexible output New CLG wells can be drilled in close proximity without thermal interference, which can reduce the cost per well. Equally important, CLG systems can be engineered to provide the flexibility to control power generation when needed and supply precise amounts of heat and power for different applications. One of the most intriguing examples is the more efficient production of green hydrogen, using the well itself to house the CLG reaction chambers. The heat, pressure, and electricity generated by a CLG system can substantially reduce the cost and increase the safety of bulk hydrogen production. Another example is that lithium, a strategic element for batteries, can be extracted from lithium-rich geothermal brine using the ability of CLG to simultaneously control the flow of both working fluid and brine.

Environmental advantages Figure 2. Closed-loop concentric tube-in-tube deviated well configuration.


New CLG systems have small footprints, minimal impact on wildlife, require little or no water, and do

not cause seismicity or subsidence. It could be argued that CLG is the most environmentally attractive form of renewable power generation.

How does the new system work? Develop new closed-loop wells

its commercialisation for clean power generation and high value industrial applications.

References 1.


There are two general configurations for new CLG wells. The simplest is a vertical well into which a tube-in-tube assembly (an insulated concentric tube, such as a vacuum insulated tube) is inserted. Heat is absorbed through the well casing from the resource by conduction and convection and then into the working fluid. Figure 1 shows a deep vertical well with the concentric tube configuration circulating sCO2. Figure 2 illustrates the second option, where the well bore kicks off directionally at the top of the hot geothermal target zone, increasing the surface area for heat transfer by angling through the target temperature zone. GreenFire Energy Inc. conducted a field scale demonstration of this type of CLG technology at Coso KGRA in Coso, California, US, in 2019 (Figure 4).2

GEISER, B., HILPERT, M., and MARSH, B., ‘Geothermal: The Marginalization of Earth’s Largest and Greenest Energy Source,’ PROCEEDINGS, 43rd Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA (2016). SCHERER, J., HIGGINS, B., MUIR, J., and AMAYA, A., (GreenFire Energy Inc.). ‘Closed-Loop Geothermal Demonstration Project.’ California Energy Commission. Publication Number: CEC-300-2020-007. (2020).

Rehabilitate existing geothermal wells New CLG technology can restore productivity to failed geothermal wells with substantial savings in time, money, and risk. A World Bank study concluded that approximately 22% of all geothermal wells worldwide have failed for a variety of reasons. Many were dry holes when first drilled. Other sources of failure include inadequate brine production, high noncondensable gases (NCG), low wellhead pressure, and corrosive brine. Although some wells can be cured using various workover techniques, these are usually expensive, risky, and involve additional drilling. CLG well retrofits generally involve inserting a specifically engineered downhole heat exchanger (DHX) into the existing well to produce power. A variety of retrofit solutions are available, depending on the specific characteristics of the well, resource, and surface system. One such retrofit solution is illustrated in Figure 3, where the working fluid circulates from the steam turbine back to the bottom of the DHX and extracts more heat on its downward path from the flow of co-produced geofluid rising in the outer annulus between the well casing and the DHX.

Figure 3. A CLG well retrofit.

Conclusion New CLG technology is poised to significantly expand access to geothermal resources for clean, reliable, and continuous electric power. The technology can develop field scale projects for new closed-loop wells, and rehabilitate existing geothermal wells. With the capability to deliver scale, to reduce time to revenue, and to decrease costs and risk, new CLG technology has the economics for growth. Now is the time to adopt new CLG technology and accelerate

Figure 4. GreenFire Energy CLG demonstration in Coso, California, US, 2019.



Figure 1. Boguchanskaya power plant on the Angara River in the Krasnoyarsk Territory, the largest hydropower plant (HPP) in Russia commissioned over the past decade.


ydropower plays an important role in Russia’s electricity industry. Hydropower plants account for 20% of the total installed capacity and 17% of the country’s electricity production. The highly manoeuvrable capacities of hydropower plants ensure reliable and efficient operation of the power system, prevent the burning of large volumes of fossil fuels, and stop emissions of approximately 190 million tpy of carbon dioxide being released into the atmosphere. Over the past 10 years, eight large and mid-sized power plants with a total capacity of 4.3 GW, as well as a number of small hydropower plants (SHPPs), have been commissioned in Russia. The construction of one large hydropower plant (HPP), one pumped storage power plant, and a number of SHPPs is underway, which are outlined in this article.

Russia’s largest recently-commissioned hydropower plant Boguchanskaya HPP is the largest hydropower plant in Russia that has been commissioned over the past decade (Figure 1). It has a capacity of 2997 MW, and the average power generation is 17.6 billion kWh/y. The construction of the power plant on the Angara River in the Krasnoyarsk Territory began in 1974, but was suspended in the 1990s due to a lack of funds. In 2006, the construction was resumed jointly by RusHydro and RUSAL companies. The first unit was launched in 2012, and the plant was brought to full capacity in 2014. The plant is part of the production complex with a large Boguchansk aluminium smelter, which reduces aluminium production costs. Boguchanskaya HPP’s structures include a rock-fill dam with an asphalt-concrete diaphragm that is 1861 m long and 77 m high; a power plant building with nine hydroelectric units; as well as two


Stanislav Degtyarev and Ivan Sliva, RusHydro, Russia, provide a detailed look at the role of hydropower in Russia’s electricity industry, focusing on a variety of hydropower plants present in the country.


in 2019. Currently, the power plant’s capacity is 310.5 MW, and its construction continues, which is scheduled to be completed in 2023. The design capacity of Ust-Srednekanskaya HPP is 570 MW, and electricity production is 2.56 billion kWh/y (Figure 6).

Hybrid hydro-solar generation

Figure 2. Zaramagskaya power plant on the mountain river Ardon in North Ossetia, the highest-pressure HPP in Russia.

Nizhne-Bureyskaya HPP in the Amur Region is the largest hydropower plant in Russia, which was completely built in the postSoviet period. The power plant functions as a counter-regulator to Bureyskaya HPP, the most powerful power plant in the Far East of Russia. The construction of Nizhne-Bureyskaya HPP was started by RusHydro in 2010, the first units were commissioned in 2017, and in 2019 the plant construction was fully completed. Nizhne-Bureyskaya HPP is a pioneer of hybrid hydro-solar generation in Russia: solar panels are located at the plant’s site as well as floating solar power on the surface of its reservoir. The capacity of Nizhne-Bureyskaya HPP is 320 MW, and its electricity production is 1.67 billion kWh/y (Figure 3).

Hydropower plus pumped storage

Figure 3. Nizhne-Bureyskaya power plant on the Bureya river in the Amur Region, a pioneer of hybrid hydro-solar generation in Russia.

spillways, including the first spillway in Russia with special steps to dissipate the energy of falling water.

High pressure hydropower Zaramagskaya HPP-1 is another project, and its history dates back to the USSR times. The construction of this plant in Russia’s North Ossetia began in 1976 and was also suspended in the 1990s. The construction was resumed by RusHydro in 2006, and the launch took place in early 2019. The long construction period was caused, among other things, by the unique characteristics of the power plant. The water head totals 609 m, and it is the highest-pressure hydropower plant in Russia. A tunnel with a length of more than 14 km makes such a head possible. The power plant has two pelton turbines, the largest of this type in Russia (Figure 2). The capacity of Zaramagskaya HPP-1 is 346 MW, with electricity production of 842 million kWh/y.

A remote power plant Ust-Srednekanskaya HPP is being constructed in the Magadan Region, one of the most distant regions of Russia. The power plant is designed to supply electricity to new gold mining facilities and improve the reliability of power supply for the entire region. The construction began in 1991 and proceeded at a slow pace until 2008. After Ust-Srednekanskaya HPP was taken over by RusHydro, the construction process sped up, which made it possible to commission the first two units in 2013, and the third unit


The only power plant in Russia that combines a regular hydropower plant and a pumped storage plant plant is located in KarachayCherkessia. The construction of the power plant began in 1976; the initial project provided for the transfer of part of the flow of three other rivers to the Kuban River through a system of canals and tunnels with a total length of more than 30 km. The first two units were commissioned in 1999 and 2002. For environmental reasons the amount of transferred water was reduced and only two units were eventually installed – instead of four as was originally planned. To make full use of the facilities, a decision was taken to transform the HPP into a pumped storage plant plant through the installation of two pumped storage units (with a total capacity of 140 MW) and the construction of an artificial lower basin located on the other side of the river. RusHydro launched the project in 2010 and completed it in 2016. The capacity of Zelenchukskaya HPP-PSPP is 300 MW in turbine mode and 156 MW in pumping mode. Electricity production is 577 million kWh/y.

Reducing an electricity deficit Gotsatlinskaya HPP is another hydropower plant built by RusHydro in the North Caucasus of Russia. The construction of this plant started in 2006 and was completed in 2015. The water head at the two units is created by means of a 69 m high dam with an asphalt-concrete diaphragm. Two spillways secure the safe operation of the plant. The capacity of Gotsatlinskaya HPP is 100 MW and the average electricity production is 350 million kWh/y. The commissioning of the power plant made it possible to reduce the electricity deficit in Dagestan, which amounted to more than one billion kWh/y and was covered by supplies from neighbouring regions.

A hydropower complex A whole hydropower complex, consisting of three successively placed hydropower plants, is located in Kabardino-Balkaria. The first and most powerful power plant is Kashkhatau HPP, which, in addition to generating electricity, takes water from the river, cleans it from sediments, and directs the treated water to other hydropower plants. Kashkhatau HPP is a diversion power plant – the water

Figure 4. Zelenchukskaya HPP-PSPP in Karachay-Cherkessia, the only power plant in Russia that combines a regular hydropower plant and a pumped storage power plant.

head is created using a tunnel and a channel with a total length of 6.5 km. The construction of the power plant began in 1993 and was completed by RusHydro in 2010. The capacity of Kashkhatau HPP is 65.1 MW, and the average electricity production is 241 million kWh/y.

Low costs and environment conscious Zaragizhskaya HPP, built in 2011 - 2016, is the lower stage of a hydropower complex in Kabardino-Balkaria on the Cherek River. The power plant features the maximum degree of environmental friendliness – it does not have a dam, and the water head is created using a diversion canal more than 3 km long. The use of water already purified from sediments made it possible to abandon the construction of an expensive sedimentation tank and significantly reduce the costs of building the power plant. The capacity of Zaragizhskaya HPP is 10 MW, and the average electricity production is 114 million kWh/y.

Environmentally friendly Yegorlykskaya HPP-2 is a further example of the most environmentally friendly hydropower plant. To create the water head, the power plant uses a dam, which was built in the Stavropol Territory on the Yegorlyk River in the 1960s, and where the energy of the water was uselessly dissipated at the spillway. The construction of Egorlykskaya HPP-2 started in 1995 and for a long time was carried out at a slow pace. After it was taken over by RusHydro, the construction was significantly accelerated.

Figure 5. Zelenchukskaya HPP-PSPP, the only Russian power plant that combines a regular hydropower and a pumped storage power plant.

The power plant was commissioned in 2011. The capacity of the Egorlykskaya HPP-2 is 14.2 MW, and the average electricity production is 31 million kWh/y.

Hydropower near Moscow Zagorskaya PSPP-2 is the largest hydropower facility currently being built by RusHydro. This is pumped storage power plant located in the Moscow region. The new power plant is located next to Zagorskaya PSPP and it will use the same lower basin.



Figure 6. Ust-Srednekanskaya power plant is under construction in extreme natural conditions: permafrost thickness reaches 300 m while winter temperatures go down to -60˚C.

The construction of the power plant began in 2007 but was suspended in 2013 after a subsidence beneath the plant’s building. In 2019, unparalleled in the world, a project was launched to level the plant’s building through pumping special fluids under it. The levelling project is scheduled for completion in 2022. Following this, a decision to complete the construction of the power plant will be taken. The capacity of Zagorskaya PSPP-2 is 840 MW in turbine mode and 1000 MW in pumping mode. The average electricity production is 1000 million kWh/y.

The programme to support renewables The construction of two Krasnogorsk SHPPs is the largest project being implemented by RusHydro within the state programme for supporting renewables. This is a hydropower complex on the Kuban River in Karachay-Cherkessia, which comprises two HPP buildings using one dam. As well as generating electricity, the reservoir of the new power plants will act as a counter-regulator to the upstream Zelenchukskaya HPP-PSPP, the largest hydropower facility in the region. The construction of the Krasnogorsk SHPPs started in 2019, and their commissioning is scheduled for 2021 - 2022. The total capacity of the Krasnogorsk SHPPs is 49.8 MW, the average electricity production is 167.6 million kWh/y.

Design of small hydropower plants The use of existing hydraulic structures to create the water head is a rational way to design new small hydropower plants. This approach makes it possible to reduce construction costs, increase the efficiency of water resources use, and avoid adverse environmental impacts. One of such power plants under construction is UstDzhegutinskaya SHPP – it uses the dam of a hydrocomplex on the


Kuban River built in the 1960s providing water intake to the Bolshoi Stavropol Canal. The construction of this small power plant was started by RusHydro in 2017, and its commissioning is scheduled for 2020. The capacity of Ust-Dzhegutinskaya SHPP is 5.6 MW, and the average electricity production is 25.6 million kWh/y.

SHPPs Another small hydropower plant, being attached to existing structures, is Barsuchkovskaya SHPP. To create the water head, it uses the dam of the levelling reservoir of Kuban HPP-4, which has existed since the 1960s and is used for water management needs. The construction of this power plant started in 2018 and it is scheduled for completion in 2020. The capacity of Barsuchkovskaya SHPP is 5.25 MW, and the average electricity production is 24.7 million kWh/y.

Conclusion Russia’s hydropower potential is estimated at 850 billion kWh/y. By now it has been developed by approximately 20%, which opens up prospects for the construction of new hydropower plants, especially in Siberia and the Far East. The Russian government has made decisions to support the construction of small hydropower plants backed by a mechanism to guarantee the investment payback. Today, several small plants are under construction in the North Caucasus and the North-West region, and a number of new projects are being designed. Additionally a large scale process is underway to replace equipment at operating hydropower plants, in particular, the capacity of RusHydro’s HPPs has increased by 452.5 MW in nine years due to the replacement of hydroelectric units with more efficient ones.

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Peter Libert, Sarens, Belgium, describes the lifting and handling logistics of installing large wind turbines.


he floating offshore wind (FLOW) sector is the newest technology in the eolian world of renewable energy. FLOW is expected to unlock 80% of global offshore wind resources located in waters deeper than 50 m. According to the European Technology & Innovation Platform on Wind Energy (ETIP Wind), this means that it has the potential to supply more electricity than the entire world consumes today. One of the main challenges of installing offshore wind energy is the depth of the water, making it difficult to install offshore wind farms, which require shallower coasts. Thanks to floating




Figure 1. In Belgium, a Sarens crane installing the first wind farm in the world with turbines developed especially for offshore.

Figure 2. In 2019, Sarens transported the 107 m GE blade – a world record of the longest blade of a turbine.

Figure 3. At the end of 2017, Sarens transported the 89 m long Adwen blade – the world record of the longest blade of a turbine that year.


technology, the industry would solve this problem and could unleash its full marine energy potential. The difference between turbines that are installed onshore and those that are installed offshore is that offshore wind turbines are not limited in size or weight, as there are no restrictions at sea. Both the wind turbine elements and offshore foundations are built in a factory close to or on the quay, then loaded onto a barge and installed at sea. Sarens installed the first wind farm in the world with turbines developed especially for offshore: the Thorntonbank phase I in Belgium. Six turbines were installed, which in 2008 produced a power of 5 MW each – at that time already surpassing today’s mainstream onshore wind turbine. Onshore wind turbines are close to reaching their peak because of limitations in size and weight for logistic reasons. Tower elements and nacelles must be transported over the highway, meaning that these can never be higher than the height of a bridge they need to drive under. Blades must be able to take the turn of roads and streets. It is difficult to find locations in highly populated areas where access for blades of more than 50 m long is feasible. Sarens has installed around 20 000 onshore wind turbines to date, starting in the 1980s when they had a capacity of 50 kW, steadily growing up to today’s 4 ‑ 5 MW mainstream onshore wind turbine. Since there are no limitations at sea, the growth in size and production power never stopped. Today’s mainstream offshore wind turbines produce 9.5 MW, with one prototype already producing 12 MW, and even bigger turbines announced for the near future. At the end of 2017, Sarens transported the world record for longest blade: the 89 m long Adwen blade, and in 2019 Sarens once more transported a new world record: the 107 m GE blade.

The importance of foundations There is another difference between onshore and offshore. In order to be able to construct a wind turbine at sea under controlled conditions, a foundation is necessary. A steel monopile (MP) or steel jacket is utilised, standing on the seabed, on which the wind turbine can be built under similar conditions as on land. The wind turbine stands on its foundation, immobilised on the seabed and a crane standing on a barge equipped with jack-up legs similarly stands on the seabed, also not moving – this way assembling the wind turbine in the same way as under onshore conditions. The heaviest foundations today are 1750 t up to 2000 t with a height of 90 m and more. These are necessary for the +10 MW class wind turbines in water depths of approximately 50 m. The technical challenge is the production of these foundations and loading them onto a transport barge. The Sarens Giant Crane SGC120 has been performing this in Newcastle, UK, for multiple offshore wind farms for many years.

Transporting monopiles For transporting MPs, which have been the most popular foundation type for the last decade (typically 1500 t but in the near future weighing 2000 t), Sarens uses self propelled modular trailers (SPMT). A key part of the foundation is a transition piece (TP). This is the link between the subsea foundation and the wind turbine, and it provides the necessary height so that the highest storm wave never touches the bottom of the wind turbine. TPs have been growing constantly, reaching 500 t and 30 m high today. As these need to be stored and transported vertically, Sarens developed a transporting and installation tool called TP Handler. This whole process is repeated with all the turbines for the offshore wind farms, and most of them have 50 ‑ 80 turbines. From September 2020 until summer 2021, Sarens will install one of the largest in quantity; concerning the 89 wind turbine generator systems (WTG) of the Fryslan offshore wind farm in the Ijsselmeer, the Netherlands. For this project, Sarens uses two barges, each equipped with spud legs stabilising the barges, and on each barge a CC6800 crane. In phase 1 it will entail hammering the MP foundations, and in a second phase installing Siemens Gamesa WTGs. The Ijsselmeer is an inland sea that is only reachable by locks. For providing stability to the CC6800 crane, capacity 1250 t, a barge with a minimum width of 30 m is necessary. But the locks are not so wide. Sarens operates six twin barges that can be split, allowing each barge to pass through the narrow locks, and after the lock these are brought back together to provide a stable 30 m wide working platform.

barge, the Sarens TP Handler, mounted on SPMTs, took over. In this kind of job, the TP Handler picks up the load and it is off. Manoeuvering faster than a crawler crane could for this job, it transports the wind farm TP to the lay down area and gently puts it down on concrete foundation blocks. Next, the barge rotates to let the crane reach the remaining TPs. These wind turbine parts were destined for the North Sea. The TPs came from Antwerp, and the MPs were manufactured in Rotterdam. Each TP needs to be paired with a corresponding MP before transport to the offshore wind farm. The barge took the turbine parts to the wind farm for installation. The MPs arrived for load-out first. Each weighed approximately 1088 t, and Sarens’ CC8800-1 and CC6800 cranes lifted them in tandem. Long slings were attached to the crane hook so it could lift the MP without causing damage. No metal came in contact with it during load-out. One by one, the remaining MPs were brought in and carefully loaded out onto the barge. With the MPs secured it was time to load out the TPs. The CC8800-1 lifted the first as crew members carefully guided it into the grillage. Once all three were onboard and secured, they

Figure 4. Sarens’ self propelled modular trailers transporting a steel monopile.

Cranes Another job Sarens recently carried out was in the Port of Rotterdam in the North Sea, where the company was performing load-ins and load-outs of MPs and TPs for an offshore wind farm. To achieve this, two of the biggest crawler cranes in the world were used: the CC8800-1, capacity 1600 t; and the CC6800, capacity 1250 t. The 480 t wind turbine TPs arrived from Antwerp by barge and Sarens loaded-in on the quay. Once they were off the

Figure 5. Sarens TP Handler transporting a transition piece in Rotterdam, the Netherlands.



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Figure 6. A Sarens Giant Crane SGC120 loading the foundations of a wind turbine in Newcastle, UK.

departed for their final destination on the North Sea. Sarens is on site for several months, performing load-ins and load outs similar to these.

Conclusion In summary, some of the main advantages offered by an offshore wind farm compared to an onshore one include: FFNo limitations in dimensions and weight = more power production per WTG.

FFNo logistic limitations in transport and installation. FFHigher wind speed at sea combined with more wind hours result in far higher yearly MWh production.

FFNot affected by the ‘not in my back yard’ (NIMBY) effect from the local population. In addition, technically speaking, floating offshore wind farms have the following differences with fixed ones: FFFixed is only possible in shallow waters up to maximum 50 m.

FFMany seas all over the world do not have this type of shallow water, thus only floating foundations will be possible.

FFFixed need expensive installation ships in the open sea. FFThe floating foundation is presented close to the quay in a harbour where the WTG can be assembled onto it by using a classic Sarens land crane, which is far cheaper than this expensive installation ship; same for major repairs or dismantling.

FFFloating foundations need two to three times more steel than fixed foundations, so are more expensive. In terms of technical capacity, the Sarens equipment is not at all close to its limits for lifting and transporting wind turbines or foundations. In oil and gas, nuclear and civil construction, loads that are 300% heavier have been handled for decades, compared to today’s biggest offshore wind turbine foundation. Sarens has the know-how, the engineering capacities, and the equipment available for much heavier loads. In traditional industries a project will be one reactor or one bridge, so time planning is important but not essential. However, a typical offshore wind farm like the Fryslan project concerns 89 wind turbines, which means that the profitability of installing this project is not influenced by technical specifications, or lifting capacity, but by well organised logistics and installation speed.



Tom Whittle, Taiwan, and Daniele Caruso, UK, Offshore Wind Consul from realising the cost reduction opportunities tha


here is currently an increasing interest and investment globally in floating offshore wind. The Carbon Trust forecasts 70 GW of floating wind by 2040, with up to 10.7 GW feasible by 2030.1 The acreage of seabed available to economically exploit fixed bottom offshore wind is restricted to relatively shallow water depths, generally up to 60 m deep. Going to floating wind allows a huge area of seabed globally to be exploited to produce large scale renewable energy. The main barrier to date has been the cost of this technology. Fixed bottom offshore wind has recently gone through a huge transformation from an expensive, niche technology, to one of the merchant forms of electricity generation with a fast-growing global market.2


ltants (OWC), detail how floating offshore wind projects should benefit at novel floating wind-specific designs can bring.

Floating wind has the potential to use industrialised, large scale production techniques to reduce the cost of the floating platform, including mooring and the anchoring system. To do so, many technical challenges have to be overcome, especially on floating foundations and dynamic cables.

Trends Floating technology is a focus of investment in both mature fixed bottom offshore wind and new markets across Europe, Asia, and the US. A leading floating technology platform developer, Principle Power, now has backers including EDP Ventures, Repsol Energy Ventures and Aker Solutions, all of whom are actors in the offshore wind



Figure 1. Floating wind platform variants, from left to right: buoyancy stabilised (barge, semi-submersible), ballast stabilised (spar), and moorings stabilised (TLP). Image courtesy of Ideol & V. Joncheray.

project development space.3 RWE and oil majors such as Shell and Total are also backing the technology in multiple markets.4,5 The number of new floating wind platform design variants have ballooned in recent years, with each designer claiming the optimum, most cost-effective solution based on design for efficient manufacturing, stability, most easily localised supply chains, or novel designs which aim to reduce the size and material weight of the platform via passive yawing structures, downwind wind turbines or multi-turbine structures. The industry is at a point where senior figures are calling for a narrowing of the field of designs to allow project developers and wind turbine original equipment manufacturers (OEMs) to focus on solving the technical issues within a narrower set of boundaries.6 Overall, there are still opportunities to optimise platform design for mass fabrication of floating platforms and reducing material weight, as well as solving issues such as installation and maintenance challenges that are most likely achieved with a new platform design. As the industry is new, the technical challenges associated with designing and constructing floating offshore wind farms are still being identified and digested, which leaves room for further innovation.

Floating wind platform designs There are three main variants of floating wind platform designs. The buoyancy stabilised configuration (e.g. a semi-submersible or barge type) uses the buoyancy of the platform to resist the overturning moment of the wind turbine. This design can use simple and (relatively) low-cost catenary moorings and anchors, and is relatively simple to install. However, it can have larger wave induced motions than other configurations, which the turbine must accommodate. Barge designs of this


type present a large waterplane area, compared to the semisubmersible type designs, and these may incur more significant wave induced motions, and may also need larger, stronger moorings and anchors due to increased forces on the platform from storm waves and strong currents. Another design is the ballast stabilised configuration, or ‘spar’ type, an example of which is used in the Hywind project in Scotland. This uses the weight and low centre of gravity of the structure to resist the overturning moment. This gives a stable platform for the turbine with low motion, and can use simple catenary moorings. A constraint of this design is the deep draft, which needs a deepwater location for the turbine to be installed. For example, the Hywind project installed the turbines onto the platform in a fjord in Norway. The third variant is the moorings’ stabilised design. This uses the moorings to provide stability and to resist the overturning moment. An example of this type is the tension leg platform (TLP), which is a design that has been used in the oil and gas industry to good effect. This design is generally the most stable, with the lowest motions for the turbine to accommodate, and can be the lightest in terms of material weight. However, they have more expensive and specialised moorings and anchors. This design also presents challenges related to installation and disconnection from moorings, which can be a highly weather sensitive operation. Of the three types of design, the TLP is the only one that has not yet been tested offshore in a wind energy application. There are also novel approaches, such as multi-turbine platform designs – for example Hexicon’s two turbine design – or passive yawing designs such as that from Saitec. There is also variability in the materials for constructing all types of platforms, with steel being the most common choice. However, concrete designs have also been considered to allow potential

mass production at a competitive price, while also allowing local suppliers to participate where a suitable steel fabrication facility is not present in the project country.

Challenges for floating wind There are a number of technical challenges to floating wind that are unique. One is the operation to replace or overhaul major components, e.g. the wind turbine gearbox. For floating wind, the water depths are too deep for a jack-up vessel to operate. Using a floating crane vessel to perform this operation with a floating wind turbine is very difficult, due to the relative motions of the crane and turbine at height, and a practical solution using a floating crane vessel has not yet been found. This means that for this operation, the floating wind turbine must be disconnected from its moorings and electrical power cables, and towed to a suitable port where the work can be performed. The disconnection and towing of a turbine to port is time-consuming and costly, considering not only the direct costs of the operation, but also the lost revenue due to the time that the turbine is out of operation. With turbines up to 15 MW in capacity, this lost revenue can be substantial. This technical challenge means that the distance from a suitable port is a key driver in the cost effectiveness of a project. It also means that floating platform designs with complex and weather sensitive procedures for installation or disconnection from moorings are disadvantaged in this respect.

Cable challenges Floating wind development will also introduce a significant challenge in the design of submarine power cables. The floaters

are connected via a unique power umbilical that hangs from the base of the platform to the seabed, transmitting the electricity generated to shore. The power umbilical structure is entirely exposed to the dynamic loads of the environment which characterises the project area, including the actions of the waves, current flows, and platform induced motion in response to the wind/turbine interactions. The power umbilical exposed to cyclic environmental loads will be subjected to several stress components acting along its structure. The combination of these stresses exerted over a period of time can cause fatigue damages to the power umbilical, with the potential, if not well designed, to ultimately lead to cable failure. Making the design of the dynamic cable and its supporting accessories more difficult is the variation in weight and drag of the cable over the lifetime of the wind farm, due to changes in the thickness and density of marine growth. This varies from location to location, starting with nothing and potentially having to manage hard growth up to 350 mm thick. This has a drastic effect on the dynamics of the power cable. The main driver for fatigue loading on the dynamic cable is the motion of the floating turbine itself. Harsher wave environments and platform designs with a larger waterplane will be more challenging from a fatigue design perspective. Tidal currents are also a factor. They are responsible for generating vortex induced vibrations (VIVs), which are vibrations induced by fluid that oscillates after interacting with the dynamic power cable structure. These VIVs contribute to cyclic loading and the reduction in fatigue life of the cable.

Figure 2. Equinor’s Hywind Scotland wind farm uses a spar type floating structure. Image courtesy of Woldcam/Equinor; artist: Ă˜yvind GravĂĽs.



Figure 3. Windfloat Atlantic at quayside. Image courtesy of Principle Power; artist: Dock90.

From a structural standpoint, the axial and bending stiffness of the dynamic power umbilical affects its motion response to the dynamic loads.7 Designing a cable with large bending stiffness can reduce the cable motion; however, it might cause high localised stress to occur over the sheath surface, resulting in cracks. Several research studies conducted using finite element analysis (FEA) modelling suggest that an increase in the current velocities result in a rise of cable insulation fatigue damage, along with current direction being a contributing factor.8 The composite construction of power umbilicals, along with the harsh environment and complex cyclic loading regime, make this crucial component very challenging to design for floating wind applications.

Conclusions The cost reduction required for floating offshore wind development globally is only possible to achieve with large scale projects. The technology is also relatively immature. There are full scale and commercial projects recently completed or close to construction, however these are utilising traditional technologies from the oil and gas and marine industries, and are not yet fully realising the opportunities for cost reduction that more novel and floating wind-specific designs can bring. The cost of developing and demonstrating the more novel technologies and designs is high, and brings additional risk. These technologies and designs need to be tested and proved at a smaller scale to give comfort to investors when taking the plunge on a multi-billion dollar capital cost investment. However, the high cost of demonstrating the technology can


not be borne by developers. Some governments are supporting the testing and development with subsidies, but it is difficult for them to do this if it is not beneficial. It is therefore those companies with deep pockets who have bought in to the potential of floating wind that are investing in the development of the technology. The development of wind turbine generators with 15 MW+ of generation capacity will require dynamic cables with larger cross sections and higher voltage ratings (72 - 100 kV) to be introduced on a global market scale. The growth of power transmission requirements will inevitably increase the uncertainty around the critical design factors affecting the behaviour and reliability of the dynamic cables in the next decade. More in-depth research is needed in the short-term, along with a joint effort from both academia and the industry to address long-term asset reliability solutions in an emergent market that will play a fundamental role in the energy transition.

References 1. 2. 3. 4. 5. 6. 7.


Carbon Trust, ‘Floating Wind Joint Industry Project – Phase 2 summary report’, July 2020. UK Government, Department for Business, Energy & Industrial Strategy, ‘Contracts for Difference (CfD) Allocation Round 3: results’. Principle Power, ‘Principle Power Welcomes Investors to the WindFloat Atlantic Project and Announces Shell as a Technology Partner’, 16 November 2015. Renews, ‘RWE team puts floating wind to the test’, 24 February 2020. Bloomberg, ‘Total Enters Giant Korean Floating Wind Projects’, 1 September 2020. RADOWITZ, B., ‘Floating wind must narrow field of designs to speed growth, says Equinor and MHI Vestas’, REcharge, 7 September 2020. YOUNG, D.G. et al., ‘Assessing the mechanical stresses of dynamic cables for floating offshore wind applications’, Journal of Physics: Conference Series, 1102 (2018). THIES, P.R., JOHANNING, L., and SMITH, G.H., ‘Assessing mechanical loading regimes and fatigue life of marine power cables in marine energy applications’, Proceedings of the Institution of Mechanical Engineers, Part O: Journal of Risk and Reliability, Vol. 226, No. 1 (2012), pp. 18-32.

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Graham Stewart, Anni Piirainen, Kate Johannesen, and Adrian de Andres, Xodus Group, UK, assess the bankability of floating offshore wind and explain how this industry will be key for the UK’s green strategy.


n October 2020, the UK Prime Minister set out new plans to ‘Build Back Greener’ by making the country the world leader in clean wind energy – creating jobs, slashing carbon emissions, and boosting exports. The UK already has the largest installed offshore wind capacity in the world, with 9.8 GW installed, and this is expected to rise to 19.5 GW by the mid-2020s. The announcement included plans for £160 million to be made available to upgrade ports and infrastructure to increase the country’s offshore wind capacity, which currently meets 10% of electricity demand. The UK government also pledged support to double the capacity of renewable energy in the next contracts for difference (CfD) auction, which will open in late 2021. The last commitment focused around creating a new target for floating offshore wind (FOW) to deliver 1 GW of energy by 2030, which is over 15 times the current volume worldwide.




While bottom fixed offshore wind (BFOW) has matured and is now fully commercial despite having limitations in certain water depths and geologies, FOW is now seen as the answer to exploiting deepwater sites with abundant wind resources. The costs and uncertainty associated with FOW technology remain high (Figure 1). However, not so long ago, fixed offshore wind structures were considered a risky

investment but the technology and cost pricing has matured and is now deemed very competitive. It is anticipated that a similar progression will be seen in the FOW space, resulting in a rush for the best development sites. In recent years, many wave and tidal projects have struggled to progress from concept to development due to costs and uncertainty. To avoid similar issues with future FOW projects, Xodus has launched a working group on the bankability of the technology. The industry collaboration was created following the award of a three-year research project on the costs around FOW. The study, led by the global engineering consultancy through the IDCORE programme, is in partnership with the Universities of Edinburgh, Strathclyde and Exeter, as well as the Scottish Association for Marine Science (SAMS). The study, entitled ‘Improving the bankability of floating offshore wind projects’, has identified six key issues surrounding the journey from concept to commercialisation. To address these issues and enable best industry outcomes, Xodus invited developers and technology suppliers to engage with the study from the outset:

FFTechnological unknowns: With very few ‘live’ FOW

Figure 1. Xodus Group has developed a sophisticated LCOE GIS modelling tool to compute and visualise the costs of fixed and floating offshore wind in UK waters.

operations across the world, there are understandably numerous technological unknowns. In addition, the development of new turbines is typically not well understood and with so many foundation designs and parameters to consider, choosing what is the most technically and economically feasible can be complicated.

>> Firstly, on the design side, there is a choice between a proven design or taking a chance on an unendorsed turbine, which may prove considerably cheaper. Certification will help here. Either way, it will need to be industrialised for serial production, which is key for rapid deployment. >> As some foundation designs are better suited to certain environments, there needs to be significant research towards how the mooring will work, as well as a better understanding of the interaction between the floater and the turbine. Consideration of which transmission system to be used is important, as is the potential to use novel technology such as dynamic cables. >> With significant time devoted to the planning stage, there is huge potential to reduce the current cost of foundations.

FFSupply chain: Using Scotland as an example, there are

Figure 2. The so-called ‘gold mines’ of floating offshore wind.


currently no Scottish ports able to carry out the work, so this would need heavy investment – £200 million at least – to be comparable with other European ports. While the supply chain does not have the specialist experience at the moment, this will only come with a pipeline of projects. It must be remembered that this will also impact CfD local content requirements, the location of turbine installations, and overall costs.

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A floating gold rush The project is seen as key to ensuring FOW can be a serious contender in the energy mix going forward and will result in a tool designed to assist in key decision making for FOW projects. It will also create guidance to assist with project finance decisions and to reduce uncertainties in FOW energy yield assessments. As well as tackling the challenges and risks that project developers have in acquiring finance for floating wind projects and developing a methodology to use floating LIDAR data for bankable energy yield assessments, Xodus is also exploring the impacts of floating structures on modelling wind resource and incorporating the impact of metocean conditions on site Figure 3. The ScotWind leasing round has offered an insight into the potential for floating wind in considerations. Scotland. Within the Scotwind leasing round, significant emphasis will be placed on FOW due to the number FFPolicy: Although the UK government has set a target of of sites currently not economically viable for BFOW. A high 1 GW for FOW over the next decade, some uncertainty level of developer interest is anticipated in a number of these remains around what support will come from upcoming areas and the expectation is that an increased push will be CfD announcements and timescales. There is further made to lower the levelised cost of energy (LCOE) of FOW ambiguity around the grid, which would need to be in the upcoming years. The potential of a separate strike upgraded sustainably if large scale projects are to price for FOW in upcoming CfD rounds is therefore likely to happen. accelerate this development, as well as any co-development and investment initiatives for floating wind coupled with the FFLower availability: Recent research suggests that floating fledgling offshore hydrogen production industry. turbines will have a lower availability due to the nacelle The Aberdeen-headquartered company has also movements, meaning that technicians will be unable developed a tool that incorporates geographical to carry out procedures in rough seas. There is also information systems (GIS) with sophisticated LCOE modelling some scepticism around the tow-to-port procedure for to compute and visualise the costs of fixed and floating maintenance and whether it can be an improvement on offshore wind in UK waters. in-situ repairs. Developed by in-house modellers and GIS specialists, the device is being used to provide a high-level and holistic FFFinancial: Will it be possible to gain project finance, even understanding of where the ideal ‘gold mine’ FOW locations if there is a suitable CfD? Will there be enough room for are, and where a rush for investment and development are all of the different projects? As capital cost will be high, expected. it is vital to reassure investors at every stage of a project. With many different applications, it can be used for Taking the energy yield assessment as an example, much early site identification but also for micro-siting and to will depend on where the data comes from, as these sites understand the competition of the leasing or CfD round from are likely to be distanced from conventional data sources. different areas or developers. It has been used to model a This will be a regular issue around the bankability of generic project based on current technology and industry assessments. expectation. This consisted of turbines rated at 10 MW and a 500 MW total project capacity with a commissioning year FFConsenting and leasing: It is important to work with an of 2030. experienced team for this process as there are bound to Project CAPEX considers the distance of each site from be new conflicts with other sea users, such as the fishing the closest onshore substation with enough generation community. A comprehensive environmental impact headroom, as well as the distance to a suitable installation assessment will be required to gain consent. However, the port. Installation costs also vary with metocean and ground length of time to get projects up and running is a major conditions, while array and export cable costs depend on issue for potential and impatient investors. water depth at the site. The energy yield is calculated from


local wind conditions and includes a factor for availability dependent on metocean conditions. OPEX is also dependent on metocean conditions, along with distance to port suitable for operations and maintenance (O&M). To understand where the most commercially lucrative areas for FOW development are located, the model was filtered to exclude fixed foundations, and by LCOE, to include only the lowest values. The results are shown in Figure 2. These areas have the lowest LCOE for FOW due to a more optimum balance being achieved across the range of parameters. The characteristics that are expected to define an ideal floating site can be grouped as:

Table 1. Site specific pros and cons Site



Good wind resource leading to high

Shallower bedrock in places could affect

energy yield.

anchor installation and export cable burial.

Located in relatively low onshore TNUoS tariff zone, likely high available capacity for grid connection. Irish Sea

Deeper water leads to increased array cable lengths.

Close grid connection points, leading to shorter export cable length. Less extreme wave heights in comparison to other gold mine sites. Close to O&M ports, reducing vessel transit times and lowering costs. Good wind resource leading to high energy yield.

Long distance from installation and O&M ports, increased costs due to longer vessel transit times. High mean wave heights, leading to greater

FFResource: The site should have high wind speed to achieve high energy yield.

FFTransmission: Annual offshore Transmission

North and

Close grid connection points, leading

South Cornish

to shorter export cable length.


zone, likely high available capacity for grid connection.

grid connection point is important to reduce cable lengths.

connection should also have enough available capacity for connection without triggering extensive reinforcements of the network. The model has been developed through the analysis of more than 40 different calculated layers, while CAPEX and OPEX estimations have been made through careful overlaying of these tiers. This balance of parameters is summarised specific to each of the areas identified in Table 1. As the most progressed concept suited to a reasonably wide range of water depths, the results are based on a semi-submersible floating platform type. There will be some variation in the results if the model is applied to other floating platform types or specific designs. Floating wind still has a long way to go before it is commercially competitive against BFOW, however developers are now faced with a dilemma. Costs are bound to reduce as developments increase, but waiting around until costs come down could mean forfeiting the most promising locations to competitors. Only the results of upcoming leasing rounds will tell whether developers will take decisive action on this technology as part of a more environmental and sustainable energy mix of the future.

weather and access difficulty for O&M, and

Shallower bedrock in places could affect anchor installation and export cable burial.

Suitable bathymetry.

FFInstallation: Proximity to the coast and a FFO&M: Onshore substation for grid

leads to greater probability of waiting on hence lower availability.

Located in low onshore TNUoS tariff

Network Use of System (TNUoS) costs should be as low as possible.

hydrodynamic loading of foundations. Also

Excellent wind resource leading to high

Located in area with higher TNUoS charges,

energy yield.

fairly constrained grid. High mean wave heights, leading to greater

Close to installation and O&M ports

hydrodynamic loading of foundations. Also

North East

reducing vessel transit times and

leads to greater probability of waiting on

English Coast

lowering costs.

weather and access difficulty for O&M, and hence lower availability.

(North of Dogger Bank)

Close grid connection points, leading to shorter export cable length. Deep bedrock. Suitable bathymetry. Excellent wind resource leading to high

Located in area with high TNUoS charges and

energy yield.

constrained grid. High mean wave heights, leading to greater

Close to installation and O&M ports,

hydrodynamic loading of foundations. Also

Scottish East

reducing vessel transit times and

leads to greater probability of waiting on


lowering costs.

weather and access difficulty for O&M, and hence lower availability.

Close grid connection points.

Varying bathymetry, deeper locations have increased array cable lengths.

Deep bedrock. Excellent wind resource leading to high

Located in area with TNUoS charges and

energy yield.

constrained grid.

Close to O&M ports, reducing vessel

Long distance to grid connection point in

transit times and lowering costs.

some areas. Long distance from installation ports,

Mainly deep bedrock.

increased costs due to longer vessel transit times.

North/North West of Scotland

High mean wave heights, leading to greater hydrodynamic loading of foundations, also leads to greater probability of waiting on weather and access difficulty for O&M, and hence lower availability. Some shallow bedrock areas could affect export cable route. Deeper water leads to increased array cable lengths.




enewable energy is an increasingly important element of the world’s energy mix. Wind farms are a common feature of most onshore landscapes, but the future for wind energy is firmly offshore and in particular for floating assets in deeper water where the winds are more reliable. These floating assets are large in size and increasing in numbers; with more than 70 000 MW output predicted by 2040. These structures are clearly different to other non-mobile floating offshore installations (FOIs) such as semi-submersibles, tension leg platforms, and FPSOs. They are affected by complex forces of the wind, rotating blades, current, and sea state. They are also different in that they are unmanned and mass produced with multiple units of the same design in a given array. But there are also many similarities – they have buoyancy tanks, mooring systems, and topsides structures, and they will be affected by marine growth, fatigue, and corrosion. Similarly to FOIs, they are designed to stay on-site, with high levels of reliability, for many years, and will be required to have operational life extensions far longer than the original design lives. Right now, the focus of the industry is to get into ‘production’ rather than to worry too much about


Danny Constantinis, Executive Chairman, EM&I Group, Malta, presents robotic and digital asset integrity technologies for floating wind.


Figure 1. Inspection class ROV and hull cleaning.

are already proven and accepted by regulators and the class societies. Clearly there may be many other challenges specific to wind energy, for example the need for extensive hull cleaning and topsides structural and blade integrity, which can be developed noting that cost, remote inspections, and using risk-based inspection (RBI) strategies may be of value. HITS is collaborating with wind energy JIPs to find areas of common interest. For background information, several of the technologies supported by HITS are described here. EM&I is an asset integrity organisation that is a member and project manager of HITS and, encouraged by HITS, has developed a number of methods to reduce cost and risk.

Replacing divers for underwater inspection

Figure 2. Repair cofferdam installed using ODIN®.

what will happen in the longer term, and again this was the case in the early pioneering days of many innovative industries. The question is: is there anything to learn from existing marine/offshore technology that might make managing the integrity of these assets, both long and short-term, easier? The Hull Inspection Techniques and Strategy Joint Industry Project (HITS JIP) was set up eight years ago to look at optimising the integrity of floating structures, predominantly those producing hydrocarbons. The HITS JIP members include regulators, class societies, operators, and service providers. They set the parameters, and encouraged and monitored the development of a number of ground-breaking robotic and digital technologies which have helped to revolutionise the asset integrity strategy for floating assets. HITS objectives included: FFMinimising diving operations (inspection, cleaning, corrosion protection, etc.).

FFMinimising confined space entry. FFMinimising tank cleaning for inspection. Many of the technologies for hull and mooring system integrity may also be applicable for floating wind assets and


In order to reduce the requirement for divers, with 10 - 15 person teams taking up valuable persons on board (POB) or costly dive support vessels (DSVs), EM&I designed a method of inspection from within the hull and, using smaller, inspection class remotely operated vehicles (ROV), conducting the external surveys using a two to three person team only. Integrity and inspection class ROVs carry a number of tools including cavitation cleaners which remove marine growth without damaging coatings. Other tools are also available for inspection and minor repairs, but a different strategy is used for more substantial hull repairs using ODIN® access ports. These are essentially a means of introducing tools from hull to sea or vice versa without the need for divers.

Diverless hull repairs When looking at better ways to undertake underwater repairs, one solution was to find a way to fix a cofferdam (a box fixed to the side of a hull to enable repairs to be carried out from inside). Cofferdams are normally positioned by divers fixing bolts to the side of the hull or mechanically strapped into place. As a result, the company developed a method by drilling holes into the hull from inside (using class approved ODIN access ports and specialised winches) without allowing any water ingress – securing the cofferdam into place from inside the hull by wires. It is also possible to use similar methods to inspect and repair valves and sea chests on other floating installations, such as FPSO vessels, spars, tension leg platforms (TLPs), and mobile offshore drilling units (MODUs) without divers – these methods may well be adapted to floating offshore wind installations.

Inspecting mooring chains without divers Another HITS objective was to automate ways of cleaning, inspecting, and possibly repairing mooring chains. ROVs have proved capable of cavitation cleaning at moderate depths of approximately 100 m and inspection down to 2000 m or more. Consequently, EM&I’s technical group is currently developing LORISTM, a robot based on a logging industry tool, developed for cleaning, inspecting, and potentially repairing mooring systems. Pool trials are underway and sea trials are planned for 2021.

Figure 3. Mooring chain inspection and LORISTM prototype during pool trials.

Avoiding confined space entry Tank and confined space entry is Figure 4. Remote laser scan and camera images. considered by many to be one of the most hazardous tasks which FOI crews undertake, with spaces being difficult to enter and exit safely, and evacuation in the Non-intrusive electrical equipment event of an emergency being a major threat. inspection The solution, developed by EM&I with encouragement of Another project is currently using non-intrusive methods the HITS JIP, uses laser scanning and remotely operated optical for inspection of electrical equipment. Typically, electrical CCTV systems which meet class and regulatory requirements equipment needs to be switched off, and the system isolated at a distance, instead of close-up inspection by people. The before detailed inspection is possible. This is costly and leads laser scanning builds a 3D image, in a point cloud. A typical to operational disruption. scan takes approximately eight minutes, where it could take In order to avoid these disruptions, the ExPertTM was several days with people in the tank for a traditional tank developed, an approach using techniques adapted from the inspection. medical world, to inspect electrical items without opening The NoManÂŽ system with optical and laser scanning is them so that common faults can be detected. able to inspect the tanks on an FOI with a two-man team in a matter of days, rather than having 10 - 12 people onboard for Oil and gas technology applied to three to four weeks, conducting the dangerous work involving floating wind farms tank entry. There are proven strategies for assuring integrity on hull, Technology is advancing rapidly. A laser scan can now mooring system, and other components on marine structures identify distortion in the structure and find and measure using robotic methods which may be suited to or adapted to corrosion pits and areas of coating breakdown. The data unmanned floating wind arrays. can also be converted into stress models, to identify areas of Early engagement with design teams will mean that weakness and reducing integrity. changes to enable these capabilities can be incorporated into A large challenge when evaluating tank integrity is steel floating wind assets at the design stage, generating a high thickness measurement, particularly in areas of corrosion. return on investment while enhancing asset integrity. Traditional methods of non-destructive testing (NDT) currently This approach has helped to fast track a number of new involve tank entry. technologies in the oil and gas industry. A synchronous scanning method, presented to the HITS Given the involvement of classification societies and other members, enables thickness measurement with equivalent regulators early in the development process, the methods can accuracy to ultrasonic or mechanical measurements. be demonstrated and validated to gain regulatory approval The data can be transmitted to engineers and surveyors to for both current and potentially extended lifecycles. help achieve remote inspection and analysis, yet still allow the These methods have the advantage of having fewer surveyor to direct the inspection to specific areas of the tank people exposed to high risk, but also reduces offshore that require special attention. activity.



Adam Kankiewicz and Frank Jakob, Black & Veatch, USA, explain how utilising bifacial solar technology with the addition of battery energy storage systems can provide complete solutions for solar facility owners.


enewable electricity generation using solar energy is accelerating into the mainstream as technology maturation and innovation drive increasingly favourable economics. Solar generation’s displacement of traditional power generation is further enabled by the evolution of next-generation solar configurations that combine bifacial photovoltaic (PV) module technology and the hybridisation of PV with battery energy storage systems (BESS). Furthermore, these two towers of nextgeneration solar will yield even greater efficiencies together than either solution alone.

Bifacial solar adoption will drive solar baseload generation Bifacial PV technology has quickly established a strong and growing foothold as the solar PV technology of choice. This is due to the economic benefits of the higher electricity production from a module that incurs almost no additional balance of system cost. Also, as solar projects become more complex due to limitations of available prime sites, bifacial technology will offer a technological solution to maintain the amount of required generation but using less land resources and fewer associated development costs. Solar module technology and efficiency are advancing in leaps and bounds. Bifacial solar module technology is rapidly gaining momentum and offers the most recent step change boost in production, yielding 3% - 8% increases in annual generation over standard monofacial technology. Bifacial module technology also builds on the dependable performance of current monofacial module technology configurations but gives solar facilities a ‘backside boost’ in energy as the rear side of modules capture diffused and scattered light (Figure 1). Bifacial panels are becoming more commonly used and affordable. The cell technology used on bifacial panels is nearly



Figure 1. Bifacial photovoltaic solar provides the same benefits as monofacial photovoltaic solar with an additional ‘backside boost’ in energy production.

the same as used on monofacial panels, making the transition from monofacial to bifacial relatively simple for manufacturers. Nearly half of the production of top solar module manufacturers is currently bifacial.

Solar facility design is becoming more sophisticated Figure 2. An example of enhanced bifacial modules shedding snow at a much faster rate than the monofacial modules.

Figure 3. The surface albedo effect has the biggest influence on bifacial gains. The graphic shows modelled performance of a bifacial PV plant configuration on a Michigan, US, site with both snowy and non-snowy surface conditions.


Bifacial photovoltaic performance is driven by several influences that can be engineered to optimise the solar facility. These bifacial gain factors include configuring the solar facility by adjusting the surface albedo or reflectance of the surrounding ground surface, the row pitch (spacing between modules), the height of the modules, and the amount of backside shading. Most of these are new co-optimisation factors coming into play that historically have not been relevant when designing a solar facility. This is changing how next-generation solar facilities are planned and developed. Surface albedo is the single biggest influence on bifacial gains that can be achieved. It is driven by ground reflective characteristics and varies hourly and seasonally. Ideally, performance modelling should not be reliant on traditional satellite or broad ranging National Renewable Energy Lab (NREL) data sets alone. Surface albedo should, rather, be observed during on-site solar prospecting campaigns and target characterisation of the as-built surface albedo conditions, creating a more accurate overall data set and dialling in the effectiveness of performance modelling. Higher module height also increases bifacial gain as it allows more of the diffuse light to reach the backside panel and is in turn influenced by the surface albedo effect. Together, what these influences mean is that operations and maintenance

plans for the facility must also be adjusted. Over time, ground cover foliage growth will reduce the albedo effect, negating the module height gains. Wider row pitch also increases gains while torque tubes and wire management impact the backside bifacial module shading. Row pitch gains must be balanced against available land space, while two-module-in-portrait racking configurations must be balanced against wind stability concerns. Finally, certain seasonal conditions can also enhance performance. In wintery and snowy conditions, surface albedo increases and results in higher production with bifacial configurations. Additionally, sunlight scattered onto the back panel also works as a pseudo-defroster to help shed snow from the front of the modules (Figure 2). Wintertime bifacial gains can be significant in certain circumstances, with snowy conditions outperforming non-snowy conditions (Figure 3).

other variable renewable energy sources is inevitable. So too is further adoption of new types of electricity loads such as electric vehicles, which, alongside variable generation sources, put stable grid operations at risk. No longer is load the only variable. Now generation is variable as well, and is increasing as the amount of renewable electricity generation grows. As the dynamics and complexities of the grid evolve, it is critical that the power industry design systems of generators that work in harmony across the grid. Distributed energy resources increase the occurrence of generation and load imbalance where the alternating current (AC) frequency of the

The case for hybrid PV with battery energy storage systems The future of solar also includes energy storage. Or, to put it more accurately, as the solar PV based share of electricity production increases on the grids, better storage solutions are needed and desired by both facility owners and grid operators to extend the availability of renewable-based electricity on the grid throughout the day. Consider California in the US, a state well-advanced on its goals to achieve 100% clean energy by 2045. There, recent blackouts occurred when commercial, industrial, and residential customers’ use of air conditioners peaked during the late afternoon hours of a massive heat wave, just as the available power from the sun was waning. This demand and generation shift resulted in a huge load on the grid and, with neighbouring states also experiencing similar high levels of demand, California’s Independent System Operator ordered selective rolling blackouts to prevent a system-wide crash. While the blackouts raise significant reliability concerns, lessons learned provide invaluable insight into how to ensure more resilient grids in the future. While the surge of demand that caused the California blackouts was high, it was not extraordinary from a historic perspective. What was missing was sufficient, flexible supplies of electricity that could be brought on line quickly to deal with demand fluctuations on the grid. Typically, with electric grid systems, peaker plants (generally gas-fired) fulfil this function. As decarbonisation goals gain pace and the share of gas-fired electricity production declines, the industry must acknowledge that alternative back-up systems such as pumpedstorage hydropower and BESS must be more actively and comprehensively considered and integrated into the mix.

Why is battery energy storage increasingly attractive? Throughout the world, as we advance and drive to net-zero carbon emissions, the increasing adoption of solar power and

Figure 4. The chart shows the declining cost of lithium-ion energy storage (green) vs its current and projected level of adoption (blue). For 2020, storage costs are less than 75% of what they were in 2010, and projected to be half of what they are today by 2025.

Figure 5. Without battery systems, energy and revenues are lost at solar facilities. Clipping occurs when the variable generation over the day (black line) exceeds the ILR (dark green line). Curtailment occurs when grid operators order owners to scale back production (dashed blue line). Together, both lead to energy and revenue loss in the absence of any storage systems.

Figure 6. Modelling of benefit ratio vs ILR for different amounts of storage and duration. Above the line demonstrates where the extra costs of adding storage delivers positive benefit and helps inform decisions across varying factors such as the type of coupling (AC vs DC), the ILR, the BESS/PV power ratio, and the amount of storage duration.



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grid can deviate from its nominal operating point. Fast, flexible sources of electricity are needed to address grid imbalance and restore the grid to normal operation. BESS are also gaining favour today because their capital cost is as inexpensive as it has ever been, declining year over year. BESS share the same lithium-ion cells used in mobile phones and electric vehicles; economies of scale from these huge and growing industries help lower the cost for battery storage used in power systems. In the last 10 years, the cost of lithium-ion energy storage in terms of US$/kWh has fallen by more than 75%, while it is projected that the cost 10 years from now will be half of what it is today (Figure 4).

Storage plus solar: Improved grid resilience and commercial gains One of the obvious challenges of solar power generation is that solar electricity is not produced after the sun sets, and that production varies over the course of any day. The motion of the sun and variable cloud cover are the major factors at play. Electricity clipping can occur when too much solar energy arrives at the module and surpasses the inverter loading ratio (ILR) (Figure 5). In addition, when renewable generation conditions are optimal at the owner’s facility, they are often optimal elsewhere at competing renewable energy facilities connected to the grid. When production is too high across multiple renewable energy sources on the grid, the risk of transmission congestion means grid operators mandate a curtailment of production. This leads to a reduction in electricity production and reduced revenue. The nature of solar generation leaves operators of these facilities faced with the challenge of making a variable resource consistent and dependable in order to make it meet consumers’ needs and maximise owners’ returns. BESS can offer a way to achieve this. As we might say, generation transforms solar energy into electricity and transmission moves electricity to customers, whilst energy storage moves electricity through time – from now to later. Therefore, BESS can overcome the clipping and curtailment of excess electricity, storing that energy and then selling it back as firm, dispatchable electricity later in the day when loads are higher (Figure 5). This excess stored electricity can even sometimes be sold when the value of electricity is at premium, potentially generating even greater revenue for the power producer. Battery systems better balance the grid and commercial revenue. Looking at Figure 5, with a BESS in place, the solid gold line below the axis shows the excess energy stored from both clipping (black vs dark green lines) and curtailment (dark green vs dashed blue lines). The thick solid gold line later in the day shows the solar facility delivering electricity to the grid when it is needed, and possibly where the price is higher. While declining in cost, BESS is still a significant capital investment. Owners must make important determinations on the scale and configuration of BESS adopted in terms of both power rating and energy storage duration (see Sidebar). This depends largely on the ILR of the facility because, as more direct current (DC) capacity is added, the opportunity

for storing clipped energy for use later in the day increases (Figure 6). Therefore, with careful engineering, owners can optimise performance and determine the duration for storage and the optimum amount of time-shifting of solar through the use of both techno-economic modelling and historically measured field data.

The two towers of next-generation solar together As more solar generation facilities are adopted, our understanding of how to harness the sun more effectively and how to manage our power systems more reliably is increasing. The grid systems which provide electricity are becoming more complex and our management and utilisation of the grid needs to adapt with these developments. Moving from monofacial to bifacial solar technology and then adding battery energy storage systems offer complete solutions that will not only help resolve grid stability concerns but also offer productivity and revenue gains for solar facility owners. The future of solar together with storage is bright.

Figure 7. The two main types of battery energy storage coupling with solar PV.

Two types of solar plus storage Hybrid solar – where solar facilities are paired with an on-site battery storage system – can generally take two forms: FFThe simplest is AC Coupled, where the solar array is set-up as usual sending power to the grid, while the battery system has its own bidirectional inverter that can charge and discharge the batteries from solar PV or from the grid. In this configuration, clipped energy on the DC bus of the solar array would not be captured but curtailed energy would be.

FFDC Coupled storage is a configuration where the battery system is connected to the DC bus of the solar array through a DC-DC converter (i.e. charge controller). The converter is used to adjust the voltage of the solar array to the operating voltage of the battery. This allows for capturing of both clipped and curtailed energy.





lacing agriculture at the heart of the energy transition, Voltalia is pursuing the objective of associating the world of energy and agriculture through its strategy, activities, and projects, to find new solutions to current and future challenges. The company develops virtuous models of operating collaboration between agricultural and photovoltaic (PV) production, by combining the uses of the same land, and jointly builds these models with the various players in the agricultural sector – respecting the various deadlines of all involved. Through its ground-mounted solar power plants, multiple actions have been implemented, with projects in the communes of Brignoles and Le Castellet in France. In these locations, grazing agreements have been established with local shepherds, and also a partnership with a beekeeper has been reached, so that he can set up his hives within the fenced enclosure of the park. The shepherds also take advantage of the secure areas provided by the solar parks so they can graze their herds in optimal conditions, which allows a space of tranquillity from the dangers of predators.

Luce Reboul, Voltalia, France, considers the combination of agriculture and photovoltaic production, to maximise land use whilst obtaining renewable energy.



Figure 1. Canadel solar power plant located in Brignoles, in the Var department, France.

This mode of operation is based on a win-win principle, because on the one hand, the shepherd and his herd benefit from a fenced enclosure ensuring security, but also from free fodder areas, and on the other hand Voltalia limits the use of mechanical mowing, and its carbon impact. Complementing the production of renewable energy production, complete agricultural activities are found on spaces that were not initially intended for agricultural use. In addition to the production of green electricity, these projects have consequently enabled areas to be reopened to agriculture.

Indeed, through these projects, Voltalia is keen to transmit conclusive and robust summary reports, within the scope of the agronomic monitoring that it has carried out with partner agronomic research organisations and entrepreneurs. To be able to guide change in agricultural practices, Voltalia aims to be a player in the creation of a database that can be used by the various agricultural sectors. The reference agricultural technical institutes will thus benefit from feedback on the agrivoltaic solutions that are increasingly present in our environment.

Connecting agriculture and innovation

These agrivoltaic installations consist of systems that make it possible to couple secondary PV production to a main agricultural production, by allowing a provable operating synergy. These innovations concern PV systems equipped with tools and monitoring services to optimise agricultural and electrical production. The current concept consists of setting up a PV structure above agricultural areas, high enough (for example 4.5 m at the lowest point, under a trellis), to allow the passage of agricultural machinery, without restricting the farmer from working his land. The tracker modules are drivable, in order to optimise the agricultural production, if necessary.

For several years now, Voltalia has also been increasingly committed to the development of an innovative agrivoltaic solution to support farmers in the emergence of a new agricultural model that is more sustainable and more respectful of the environment. These projects, developed during national calls for tender, allow Voltalia to be part of a recognised research and development approach. Importance is given to the initiation of innovative and experimental projects whose production systems vary from one farmer to another (arboriculture, horticulture, market gardening, etc.).


Installation of the agrivoltaic concept

The primary objective is to protect cultures from climatic changes and hazards, which are becoming more and more frequent and devastating. Several projects with operating systems have already been designated awards of this call for tenders, and one of them is currently under construction. Some examples are outlined next regarding current operating systems that have been highly successful.

anti-hail nets and/or an irrigation system; the acidity of the grape varities will be preserved and optimised; fruit ripening will be controlled and sugar and alcohol levels regulated; soil evapotranspiration will have better management; the effects of wind can be limited and water requirements signficantly reduced; and virtuous wine production can be developed by mixing hand-picking and green energy production.


Long-term objective

An agrivoltaic field project with an installed capacity of 3 MW on approximately 4.5 ha. was selected as the winner. Located in the commune of Saint-Etienne-du-Grès, France, this project is being carried out in collaboration with a farmer specialising in the production of salads. The research themes include assessment of the pedoclimatic context under the agrivoltaic structure, as well as monitoring the growth and development of salad varieties that are ‘sensitive’ to high temperatures. The project is of interest to the farmer because his salads will be protected from the burn of the sun; he will be able to produce heat-sensitive salad varieties even in the summer time; water needs and irrigation costs will be reduced; and that a fixed irrigation system that does not need to be dismantled will be in place.

Through these various projects, Voltalia continues its commitment to the creation of an agrivoltaic reference system and the company has a real desire to bring viable and sustainable solutions to the agricultural world by creating efficient models that can be duplicated and adapted on a case-by-case basis. Through these projects, Voltalia is committed to the energy transition, but also to the agricultural transition, and it participates in the development of references for the agrivoltaic sector. Reinforcing its aim to become a sustainable land developer, Voltalia is actively working on the development of larger scale agrisolar parks and is focusing its reflection on livestock farming systems and field cultures (cereal cultures). The objective of these parks is to perpetuate agricultural activities in place on the territory, which are often in decline and suffer from various problems – including increasingly recurrent extreme climatic hazards, lack of takers in view of difficult working conditions, waterrelated problems, economic difficulties, and more. These parks can also make it possible to reopen abandoned agricultural areas, which are often deserted and reinvested by the forest. Through these projects, Voltalia redevelops these lands and allows young farmers, for example, to set up at a lower cost.

Arboriculture Another project with an output of 3 MW and installed on approximately 5.2 ha., located in the commune of Salon-de-Provence, France, concerns the implementation of the agrivoltaic solution and will be carried out on an arboricultural production system. The farmer will produce peaches, apricots, and cherries. The research topics are based on the evolution of production yields thanks to the protection of fruit trees and their respective productions during climatic episodes (hail, rain, wind, etc.), as well as the diversification of production (old varieties). The project is of interest to the farmer because his orchards will be protected against the increasingly frequent climatic hazards (hail, drought, heat wave, etc.); the effect of wind will be limited; water requirements will be reduced; and production workshops diversified.

Viticulture A partnership with a winery near Narbonne, in the Aude, France, has been concluded in the context of the development of an agrivoltaic project. It will cover a power of 3 MWp and a surface area of 4.6 ha. of vineyards to be replanted. As with all the other projects, agronomic monitoring is being set up with partner research organisations, and the project will be based on a control area cultivated under the same conditions but not covered by agrivoltaic trackers. The project is of interest to the farmer because the vines will be protected against the recurrence of climatic hazards (hail, drought, heat waves, etc.) and damage to crops will be limited; there is the possibility to integrate

Future research and development Voltalia plans to set up an experimental station in 2021 where research and development work will be conducted in partnership with recognised technical agricultural institutes in France. Initially, the objectives will be to study the behaviour of bovine herds on a small scale PV power plant (approximately 5000 m2), in order to study animal wellbeing and to adapt the design of the agrisolar power plants accordingly, and secondly, to conduct a monitoring of the plant cover. A control zone without panels will be set up in the continuity of the station, in order to make comparisons between results. These experiments will take place over several years, but initial results are expected in the first year. For this experiment, Voltalia has partnered directly with a breeder so that it can be carried out under real operating conditions and meet the actual challenges of agriculture. Beyond the production of green electricity, there are many issues to consider: secure these agricultural activities, develop solutions for the climate crisis, help the young farmers to access to the land, and create solutions to improve the production performance. These challenges are dealt with and managed in co-operation with all the actors of the agricultural sector.




Branislav Safarik, COO, FUERGY, Slovakia, explains how the transition to renewables could be the key to economic recovery and a more sustainable post-pandemic world.

espite all of the negatives brought about by the pandemic, it is clear that the environmental sphere is the silver lining. As a society, we have learnt we are capable of making changes to our lifestyles and adapting our daily processes. As a result, short-term environmental improvements have been seen, offering a peek into a more sustainable world. With a greener future within reach, there has perhaps never been a better time to take the decisive leap forward. There are reasons to believe that making renewable energy the fundamental part of economic recovery post-pandemic is a great way to do that. By actively replacing fossil fuels with renewables, a “decrease in carbon emissions from the energy sector by as much as 70% by 2050� could be witnessed.1 However, the benefits go way beyond. According to the International Renewable Energy Agency, the post-COVID-19 economic recovery could be driven by renewable energy through encouraging global GDP gains of almost US$100 trillion between 2020 and 2050 across the globe. With 2020 marking the first time in over 130 years since renewables have overtaken coal in US energy generation, it is clear that the whole energy structure is already shifting.2 The energy industry that will emerge postCOVID-19 will be radically different from its predecessor, but how



renewables has increased, as they are able to handle a greater supply of changing energy demands.

The sheer profitability of renewables

Figure 1. January 2019 (without smart energy system) – one day example (24 hours from 0:00 to 23:59).

Figure 2. January 2020 (with smart energy system – one day example (24 hours from 0:00 to 23:59).

exactly is being decided currently. Why should renewables be an integral part of stimulus packages? Why is now the best time? What needs to be done to make it happen?

Why consider green recovery? Apart from drastically reducing carbon emissions, investment in renewables encourages the adoption of stable and sustainable energy, cheaper electricity, and a fairer and decentralised energy framework.

Modernising the grid In many parts of the world, modernising the grid is a process long overdue. The existing energy systems often operate inefficiently, causing dependency on centralised power facilities to exponentially generate more energy than needed. Much of this energy is then lost as it travels over boundless distribution lines to reach households. In addition, the infrastructure is also susceptible to weather events or failures, and requires an increase in the capacity of existing power lines as our demand for electricity grows – something likely to happen post-COVID-19. Digitising and modernising the grid with renewable energy could bring smart, decentralised, efficient, and stable energy management. For instance, Australia will likely need approximately 30 - 45 GW of new energy generation by 2040 to replace coal-fired power stations that are being retired.3 By making the investment in renewable energy now, societies could build a direct pathway for a clean energy transition, while generating economic opportunities in the process. There is another important reason why green energy should be at the centre of a modernised grid. Throughout the pandemic, renewables have proved to be better equipped to handle uncertainties compared to fossil fuels. Not only do they often leverage advanced technologies, but they also count on remote operations, seeing minimum disruptions even when direct human management is impossible. With even a pandemic not impacting how much the sun shines or how much the wind blows, the past few months have shown that the reliability of


Over the past decade, renewable energy has seen progress in leaps and bounds. Wind and solar energy have become the most affordable power generation sources on the market, and many of the new projects are reportedly “cheaper than even the cheapest coal-fired power plants.”4 According to data from the International Renewable Energy Agency, investing in renewables around the world could provide a return of investment of up to 800% over the coming years, allowing societies to achieve diverse social and economic benefits. The economic favourability of renewables is further driven by the fact that the oil and gas industry has been experiencing significant hardships – especially amid the pandemic. “BP reduced its asset values by US$17.5 billion; Royal Dutch Shell says its oil and gas assets are down US$22 billion, and Total cut the value of its Canadian oilsands assets by CAN$7 billion.”5 Many of the top fossil fuel companies are beginning to doubt whether oil demand will ever go back to pre-COVID-19 levels, prompting them to increasingly consider wind and solar energy investments. Considering that even leading financial institutions such as Deutsche Bank, HSBC, and Barclays are now stepping back from economic involvement in coal-fired projects, it is clear that investments in renewable energy have become more stable and commonplace than ever before.

Green jobs Investments in renewable energy can also bring great economic reactivation. It has been reported that “analysis conducted by the groups E2 (Environmental Entrepreneurs) and E4TheFuture found that the US could create 860 000 full-time jobs for at least five years and add US$66 billion to the country’s economy every year for five years if targeted clean energy investments were included in the next round of federal stimulus payments.”6 According to Chatham House, green jobs are lucrative due to “the modular nature of renewable projects, the sheer number of households requiring energy efficiency upgrades, and short lead times [of these projects].”7 The distributed aspect of renewable energy also means that green jobs could help tackle many socio-economic challenges. As many developing countries actually champion renewable energy, activities such as the cleaning and maintenance of solar assets can bring jobs to previously unutilised demographics.

Why now is the time The truth is that renewables have perhaps never had as much momentum as they do now. With the outbreak of COVID-19, many grid operators automatically turned to the cheapest energy supplies to meet the falling demand – which was often wind and solar power sources.1 More expensive fossil fuels, on the other hand, were the first to be abandoned. For example, the UK’s grid operator announced on 28 April 2020 that the country had not used coal for some 18 days in a row, a milestone that has not been reached since the Industrial

Revolution. So, while global energy demand is predicted to fall by 6%, renewable energy demand is projected to increase by 1% in 2020.8 Dr Fatih Birol, Executive Director of the International Energy Agency, said: “The recent drop in electricity demand fast-forwarded some power systems 10 years into the future, suddenly giving them levels of wind and solar power they wouldn’t have had otherwise without another decade of investment in renewables.” An unprecedented appetite for change among consumers is also being experienced. The pandemic has turned out to be a wake-up call, driving more conscious consumption and leading to an unseen rise in the popularity of a plant-based diet. With decreased pollution levels and common environmental discussions, individuals themselves could become the driving force of green investments, such as household, corporate, and political entities. Their pressure to sideline fossil fuels could directly impact the way stimulus packages are tailored. Now, the policies will have to follow.

it strengthened the clean energy economy in the US.” In the US since 2008, the number of wind power installations has increased almost four-fold, and solar power saw a rise of 50 times. “The cost of utility-scale solar fell by 60% between 2008 and 2016, with solar becoming cost-competitive with fossil fuels in 20 different states.” In addition, the uptake of renewables contributed to offsetting 270 million t of CO2 in the first four years.10 According to Bloomberg, the 2008 financial crisis also encouraged South Korea to spend approximately 80% of its stimulus spending on policies that were climate-friendly. This spending consisted of a further expansion of renewable industries, as well as investments in energy efficiency. The IMF then reportedly named South Korea’s recovery as one of the world’s quickest and most successful, and the country is determined to continue this trend: it has set aside US$185 million in subsidies for home rooftop solar installations to be included in its post-COVID recovery plan.11

Civic efforts will go hand-in-hand with policies

There are also reasons to believe that the control over renewables is getting better, making them more reliable. Different innovations now allow operators to make the entire process much more effective than ever before. Looking at the following case of monitoring the control over solar power production, Figure 2 shows that in 2020, the energy produced by solar panels was causing less harm to the power grid and that the system deviation was much lower than the previous year. This effect transmits into a more stable power supply and large savings on the regulation costs, as fewer ancillary services are needed. With AI-powered software, efficient energy trading, and by leveraging energy storage, renewables can be both ecological and economical. While renewables have made decisive progress in recent years, their past reputation is still holding them back, presenting a potential drawback to their optimal deployment. However, there are coherent reasons to believe that if officials around the globe were to put their trust into renewables and administer their implementation adequately, the post-pandemic economic recovery could be both green and effective.

The completion of different renewable energy projects has been slowed down by disruptions brought by the pandemic, such as changes in supply chains and specific incentives ending this year. Policymakers now have to act to implement policies that will allow renewables to keep growing sustainably. According to Vox EU, “Green stimulus packages, just as the ones implemented during the 2008 Global Crisis, typically include government spending on building retrofits, green infrastructure programmes, as well as large scale support for clean R&D.” It is unclear whether it is no longer ideal to invest in assets that run the risk of being affected by changes in the market, technology, or changes in policy. Still, with renewables, one of the challenges is the best selection of the types of investments that can bring both economic reactivation and environmental benefits in the longer term. For example, investments in green R&D may not be as useful in increasing job growth instantly, while transport electrification or power sector infrastructure can have a quicker impact. Identifying the priorities accurately and setting up the right incentives portfolio will be the key to success.9

Addressing the criticism of green economic recovery While renewables have their supporters, there are also opponents. Those sceptical about a green recovery often look to historical data of the post-2008 financial crisis, pointing out that the effects of the green stimulus were negligible. It is true that the effect on short-term employment was subtle but in the long run the initiative saw promise that could be enhanced in the future by leveraging carbon pricing measures. Moreover, renewable technology was much more expensive and far less efficient than it is today, and its unpredictability was harder to calculate than it is now. According to a report, “Obama’s stimulus plan is considered the biggest clean energy bill in history because

Improved control over renewables

References 1.

Azo Cleantech, ‘How is the Coronavirus Pandemic Affecting the Renewable Energy Industry?’, 27 May 2020. 2. The Guardian, ‘Renewables surpass coal in US energy generation for first time in 130 years’, 3 June 2020. 3. Clean Energy Council, ‘Renewables to drive a clean recovery from Covid-19’, 14 May 2020. 4. World Economic Forum, ‘Chart of the day: Renewables are increasingly cheaper than coal’ 23 June 2020. 5. MPR News, ‘Big Oil’s pandemic pivot is toward renewables, but will it last?’, 6 August 2020. 6. Climate Jobs NY, ‘Renewable energy growth stymied by pandemic, but optimism is high’, 17 July 2020. 7. Chatham House, ‘Green industries can accelerate a true jobs-focused recovery’, 23 June 2020. 8. Science Magazine, ‘Renewable power surges as pandemic scrambles global energy outlook, new report finds’, 30 April 2020. 9. Vox EU, ‘Green stimulus, jobs and the post-pandemic green recovery’, 4 July 2020. 10. Mission2020, ‘Green stimulus: case studies from 2008-2009’ April 2020, available at: 11. Bloomberg, ‘How to grow green: 26 ways to launch a clean energy future out of the pandemic recovery’, 9 June 2020.



Dr. Ilkka Virkajärvi, Ductor Oy, Finland, details the use of biogas as a renewable source of energy, considering the rise of poultry manure as a biogas source.

iogas is a renewable source of energy that has a variety of applications, in district heating, electricity production, and mobility. The flipside has been that the substrate mostly used is energy crop, and that has taken land area away from food production. This factor, and the corn monoculture effects on fauna, have recently created opposition to biogas. Organic fraction of municipal solid waste, along with sludge from wastewater treatment plants, are two alternative and well-used substrates for biogas. An almost unused source of biogas is poultry manure. Poultry production generates over 2 billion tpy of manure. It is expected that the future growth of poultry – especially chicken – as a protein source will continue to increase relative to red meat and fish due to its favourable CO2 footprint. The current biogas potential is conservatively estimated at 160 m3 biogas/t – this material corresponds to 320 000 million m3/y.



Converting this to mobility: the methane part of the biogas would be enough to travel around the world 70 million times in a gas fuelled vehicle (5 kg gas/100 km).

Annual chicken manure production and the possible benefits FF2 billion t chicken manure. FF320 billion m3 biogas. FF(70 million times around the globe). FF50 million t nitrogen. FF30 million t phosphorus. FF34 million t potassium.

Figure 1. A biogas plant with ammonia removal process.

Why is this energy source not used in biogas production? The reason lies in the nutrients contained in poultry manure. The high nitrogen quantity leads to ammonia inhibition, meaning biogas formation is reduced. However, there are methods, processes, and trials to overcome the inhibition, and Ductor Oy has designed a solution to this problem. Ductor Oy has a patented microbial population that converts organic nitrogen into ammonia, and it can use many organic materials including poultry manure. The conversion takes place in an additional reactor (similar to the biogas digester) in five days. After this step, approximately 60% of the nitrogen in the organic material is converted into ammonia, and the ammonia can be separated from the fermented slurry by air or steam stripping. Finally, the poultry manure has become a suitable source for biogas production. The important issue here is that nitrogen is lowered to a level which does not cause inhibition in the digester prior to being fed into the digester, not after or within the digester. This technology has been verified on a small scale in a pilot plant in Helsinki, Finland. The pilot project consisted of over 11 months of operation using 100% chicken manure as substrate, and by recycling the reject water back into the process it allowed the ammonia level to stay below 3 g/l in the digester. Overall, the biogas production was stable. Fast forward from this pilot project to October 2020, and an industrial size biogas plant in Haren, Germany has now started to use this technology in its production process: FFSubstrates corn: 1130 t; chicken manure: 10 200 t; pig manure: 4100 t.

FFDuctor fermenter: 800 m3. FFDigester: 2 × 2400 m3. FFCHP: 540 kWe.

Figure 2. Ductor at San Juan de los Lagos’ demonstration and development plant in Mexico, 2019. Image courtesy of Gavin Shen.

Figure 3. The industrial size biogas plant in Haren, Germany.


The twist to biogas production comes from the change of substrate and nutrient content of chicken manure. The removed ammonia is approximately 50% of the total nitrogen in the manure and it is separated by stripping either as an ammonium salt (such as ammonium sulfate) or as ammonia water. Moreover, it is a fertilizer without phosphorus. The rest of the ammonia enters the digester and is partly used by the methanogenic bacteria in the digester before eventually leaving in the digestate. There is a large environmental benefit to processing poultry manure this way because direct application of manure on the field can lead to almost 50% loss of nitrogen as ammonia gas into the atmosphere. Although ammonia itself is not considered a greenhouse gas (GHG), the production of ammonia by the Haber-Bosch process creates considerable GHG emissions. In fact, this ammonia is actually responsible for approximately 2% of the world’s energy consumption. The digestate is the only way other nutrients can leave the process, so 50% of the nitrogen, 100% of the phosphorus, and 100% of the potassium leaves with the digestate, generating a good NPK fertilizer. The largest difference comparing the

Table 1. Water soluble N and P components in chicken manure (CM), Ductor digestate from corn is a six-fold concentration of fermented manure (DFM) and digestate (D) phosphorus in chicken manure digestate. PO4-P NH4-N NO3-N From Table 1, it can be seen that the ammonia (NH4+NO3)-N (NH4+NO3)/Ntot PO4-P/Ptot mg/kg mg/kg mg/kg % % mg/kg fresh nitrogen (NH4-N) reduces along the process, indicating fresh fresh fresh that the risk of ammonia loss to the atmosphere is CM 10.0 0 10.0 50 2.1 45 lowered through processing. The test carried out DFM 4.1 0 4.1 53 1.8 26 by Natural Resources Institute Finland showed that although NH4-N was lowered in the process, the soil D 2.9 0 2.9 36 1.7 21 soluble N content increased to the same level as with Dry matter content: CM 30.0%; DFM 23.9%; D 22.8.% unprocessed chicken manure. This means that there substrate. The solid phase is used as an NPK fertilizer as such, or it are no nitrogen losses into the atmosphere, but it can be dried and granulated or pelletised. stays available to plants. The ammonia removal process has three additional steps The plant availability tests of both N and P will be run in compared to a normal biogas plant: an extra reactor for the spring 2021, but earlier results from pot testing have indicated Ductor process approximately 1/5 the size of the AD reactor; a good nutrient availability for the plants. solid-liquid separation step; and a stripping unit. Biogas is a versatile renewable form of energy that – unlike How is the poultry manure turned into wind or solar energy – can be easily and efficiently stored biogas substrate? and transformed to electricity and heat. Unleashing a vast The Ductor biogas plant has five main steps, which are detailed amount of new renewable substrate – poultry manure – should in Figure 1. Manure is diluted to 8 - 10% depending on the amount remove objections that have lately hindered the expansion of of grit in the manure. The first step is Ductor fermentation where the biogas industry. Instead of using vast monoculture energy most of the organic nitrogen is converted into ammonium – this crops, an increasing feedstock for biogas is available, with the takes place in a temperature of 52˚C and lasts five days. Now additional twist of the environmental recycling of nutrients. ammonia is in the liquid phase of the fermented slurry and The environmental benefits include: reduction of ammonia therefore solids are separated from the liquid which enters for and methane emissions to the atmosphere; less leaching stripping. Stripping removes ammonia as ammonia vapour, of nutrients to rivers and ground water; and GHG savings in whether the method is air or steam stripping. Ammonia is ammonia fertilizer production. The production of biogas from captured from the vapour by acid washing, cold water washing, poultry manure to create a pure nitrogen fertilizer and enriched, or by condensing if steam stripping is applied. upgraded NPK fertilizer (digestate) is a clear example of a circular The digestate is run through a solid liquid separation economy. process and the liquid fraction is returned to dilute the incoming

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GLOBAL NEWS Recent records for US wind turbine installations

New DNV GL class rules for floating offshore wind

According to data collected by the US Energy Information Administration (EIA), project developers expect more than 23 GW of wind turbine generating capacity to come online in the US in 2020, far more than the previous record of 13.2 GW added in 2012. Only 5 GW of capacity has come online in the first eight months of 2020, according to EIA’s ‘Preliminary Monthly Electric Generator Inventory’, but as is typical with wind turbine installations, most of the annual capacity additions come online in the final months of the year. Another 18.5 GW are planned to come online in September ‑ December 2020, according to project timelines reported to EIA by power plant owners and developers. The 5 GW of capacity added in the first eight months of 2020 is already more than the capacity added in the first months of any year except 2009. Developers expect to add another 18.5 GW in the final four months of 2020: 8.9 GW in September - November and 9.6 GW in December. December is typically the month with the most wind turbine capacity additions. In the previous 10 years, 41% of the annual wind capacity additions came online in December. The impending phase-out of the full value of the US production tax credit (PTC) at the end of 2020 is leading to more capacity additions than average this year, just as previous tax credit reductions led to significant wind capacity additions in 2012 and 2019. Wind turbine projects coming online through 2023 that began construction in 2019 qualify for lower values of the PTC.

As the first successful pilots transition into the first commercial projects, floating offshore wind is opening up new vistas to offshore wind generation. To help expand the segment, DNV GL, the leading classification society, has released the first integrated rule set for floating offshore wind structures (DNVGL-RU-OU-0512). The rules provide both new entrants and experienced stakeholders a set of well-tested rules and standardised processes for these new structures. The newly developed DNV GL class rules for floating wind turbine installations, DNVGL-RU-OU-0512, apply standardised, well-proven maritime processes and apply them to floating wind. Owners, designers, and manufacturers benefit from being able to shift into this exciting new segment, while having a familiar framework so that new processes can be seamlessly integrated into their existing production structures. The rules are flexible enough to cover all potential hull shapes, including barge, semi-submersible, vertical floating columns (spar), and tension-leg platform. The basic classification scope covers the floating structure, including mooring systems, with an additional voluntary class notation covering the power generation system, including the tower. The rules are also designed to scale – considering not just the individual units but the entire field with data-based services and condition-based monitoring (CBM) and through linking with fatigue methodology sensor data. The new class rules were launched on 28 October 2020.

Mammoet delivers 13 wind turbine tower sections to Kazakhstan Mammoet has successfully delivered 13 wind turbine tower sections for the second phase of the Astana Expo 2017 wind farm project in Kazakhstan. In doing so, it has broken its own record for the longest land transportation ever undertaken in the country. The second phase of the wind farm – Astana II, will expand the wind farm from 52 MW to 100 MW capacity. It is being developed by TSATEK Green Energy LLP, which has contracted Danish wind turbine manufacturer Vestas to supply 14 units of V117-3.45MW wind turbines equipped with Vestas low temperature operation.


These turbines are designed for optimal performance in northern Kazakhstan’s dry continental climate; with extremely fluctuating temperatures and high wind conditions. The cargo was received at a Caspian port, directly from the sea-river vessel, and then carefully transported over 3500 km route between the port and the project site. Mammoet arranged special escort vehicles, constructed bypass roads, and organised for permits and authorisation required along the route well in advance. All 13 turbine sections have been delivered over four voyages.


GLOBAL NEWS Statkraft acquires solar pioneer Solarcentury Statkraft has signed an agreement to acquire the solar pioneer Solarcentury. Together the companies are well positioned for accelerated growth in solar and to become one of the world’s leading renewable energy companies. Statkraft will gain access to a 6 GW pipeline (gross) in Europe and South America that, combined with Statkraft’s current project portfolio, immediately positions the company as a prominent developer in the European solar market. Solarcentury’s project pipeline spans many high-growth markets including Spain, the Netherlands, the UK, France, Greece, Italy, and Chile. The transaction is an acquisition of 100% of the shares in Solarcentury Holdings and its subsidiaries. The main shareholders were previously Scottish Equity Partners, VantagePoint Capital Partners, Zouk Capital, and Grupo Ecos. The purchase price is £117.7 million and includes net cash. The transaction is conditional upon customary regulatory and local competition approvals and is expected to be completed by the end of 2020.

Bond Loan facility signed for solar projects in Greece Piraeus Bank SA and National Energy Holdings Limited have announced the signing of a Bond Loan facility of approximately €22 million to finance the construction of five solar photovoltaic projects in Greece with a total generating capacity of 24 MWp. The projects are located in central Greece and will produce enough electricity to power the electricity consumption of approximately 10 000 homes and will also reduce approximately 23 000 t of CO2 from the emissions to the environment for each year of operation. All sites have secured a 20-year fixed tariff, awarded via the operational aid auction conducted by the Greek Regulatory Authority of Energy (RAE) in July 2019. Currently the projects are under construction and energisation is scheduled to take place within the next six months for all projects.

Voltalia buys stake in four solar plants in Jordan Voltalia has signed a share purchase agreement to acquire a 70% controlling stake in a portfolio of four solar plants (57 MW) in Jordan, which have been built, maintained, and partially developed by Voltalia since 2015. Supported by the recent development of its solar hub in Egypt and long-term local presence as a service provider, Voltalia becomes a power producer in the growing Jordan market. Energy demand in Jordan is expected to grow steeply, with an estimated 2.5 GW increase of installed capacity over 2017 - 2025 as a result of the competitiveness of photovoltaic power. The portfolio bought by Voltalia includes three 11 MW plants located in Ma’an and a 24 MW plant located in Mafraq. Voltalia knows these solar plants well as a service provider: it was involved in their development and has been fully in charge of their construction since 2015 and their maintenance since their commissioning in 2016. Their owner naturally turned to Voltalia to divest the plants, given Voltalia’s historic presence, knowledge of the assets, and long-term historic ties with the International Finance Corporation, member of the World Bank Group, which is the main funder of the four plants.

THE RENEWABLES REWIND > European Energy to build largest solar farm in Northern Europe > ABB software to target savings for offshore wind farms >>EBRD, EU and partners boost green finance in Egypt Follow our website and social media pages for more updates, industry news, and technical articles.




GLOBAL NEWS France’s biggest hydropower project has been commissioned

American Hydro awarded rehab contract at hydroelectric plant

On 9 October 2020, the new Romanche-Gavet hydroelectric plant, France’s biggest hydropower project, was commissioned after 10 years of construction work. The structure was inaugurated by Jean-Bernard Lévy, EDF Group Chairman and Chief Executive Officer. The event was attended by Joël Giraud, State Secretary in charge of rural development, as well as by elected representatives and delegates from the local and regional public authorities. With a capacity of 97 MW, the new Romanche-Gavet hydroelectric plant can increase power output by 40% along the same stretch of river (La Romanche). This structure illustrates the commitment to developing hydropower, the largest source of renewable energy in France and Europe. Its output will equate to the amount of power consumed every year by the French cities of Grenoble and Chambéry (230 000 inhabitants), using a decarbonised and renewable energy source. The EDF Group committed €400 million of expenditure to the construction project. 94% of these contracts were awarded to French companies, 28% of which are located in the Auvergne Rhône-Alpes region. 75% of the structure was funded by green bonds, thereby supporting the energy transition. Jean-Bernard Lévy stated: “The new Romanche-Gavet hydroelectric plant bears testimony to EDF’s ability to develop hydropower, the largest source of renewable energy, whilst at the same time protecting the environment...”

American Hydro, part of Wärtsilä Corporation, has been awarded a major contract to perform rehabilitation services and complete the upgrade and refurbishment of the Unit 5 and 15 turbines at Ameren’s historic Keokuk Hydroelectric plant in Iowa, US. The order with Ameren Corporation was booked in July. American Hydro designed, manufactured, and delivered new 200 in., 120 000 lb Francis type runners for these units under a previous contract. The new contract includes all field labour and supervision to conduct a simultaneous two-unit outage; disassembly of the major turbine and generator components; shop and field rehabilitation and machining; installation of the new runners and refurbished turbine components; and commissioning of the upgraded turbines. Engineering and planning are currently underway, and the outages are scheduled to finish in spring 2021. Upon completion of this work, American Hydro will have upgraded all 15 turbines at the Keokuk plant. “For more than 100 years, the Keokuk Energy Centre has provided clean, carbon-free energy to customers. Its continued safe, efficient operation is foundational to Ameren’s net-zero carbon emissions goal,” said Warren Witt, Director of hydro operations at Ameren Missouri. The 142 MW Keokuk hydroelectric plant was originally commissioned in 1913 and has been in continuous operation with the original equipment since that time.

Vattenfall’s hydropower runs Finnish supercomputer As part of a pan-European initiative, one of three leadershipclass supercomputers, LUMI, will be located at CSC’s data centre in Kajaani, Finland. LUMI is one of the fastest supercomputers in the world and will run on 100% fossil free hydropower from Vattenfall. As of 1 January 2021, Vattenfall will deliver a yearly volume of up to 100 GWh of guarantee of origin-certified hydropower to CSC’s data centre. CSC is a Finnish centre of expertise in information technology owned by the Finnish state and higher education institutions. In all service development and production, CSC strives


to implement Finland’s goal of being carbon neutral in 2035 and to promote the implementation of the European Green Growth Program. LUMI will be operational between 2021 and 2026. “Supercomputers consume a lot of electricity, so the use of hydropower is important to reach climate goals. Besides the advantage of renewable energy, we have excess heat from cooling water, thanks to which waste heat can be utilised in Kajaani’s district heating network. This reduces both costs and the carbon footprint.” said CSC’s Managing Director, Kimmo Koski.



Nova Innovation secures investment for Welsh tidal energy project

Canada invests in Nova Scotia tidal energy

Nova Innovation has secured an investment of £1.2 million from the Welsh Government for its Enlli tidal energy project in north Wales. The Enlli project creates the opportunity to generate electricity from the natural ebb and flow of the tide between Ynys Enlli – ‘The Island in the Currents’ – and the mainland of the Llyn Peninsula. It has the potential to help the Island in the Currents switch from a dependency on diesel generation to become the world’s first blue energy island. The funding provided by the Welsh Government, through the European Regional Development Fund (ERDF), will support the environmental consenting and engineering design work for this ground-breaking project. Award-winning Nova plans to install five 100 kW turbines on the seabed with a view to install more turbines in the future. Nova’s tidal turbines are completely hidden beneath the surface of the sea, with none of the visual siting issues faced by wind, solar and conventional fossil fuels. Environmental monitoring of Nova’s Shetland Tidal Array in Bluemull Sound, UK, which includes regular seabird and marine mammal surveys of the area and use of underwater cameras to monitor wildlife around the turbines, has not detected any negative impacts on marine wildlife. Tidal energy is unique among renewable energy resources as it is predictable ahead of time, helping to meet and balance local demand.

Seamus O’Regan, Canada’s Minister of Natural Resources, has announced one of Canada’s largest ever investments in tidal energy: CAN$28.5 million to Sustainable Marine in Nova Scotia, Canada, to deliver the country’s first floating tidal energy array. Canada has an abundance of renewable energy sources that are helping power the country’s clean growth future and the Canadian government is investing in renewables to reduce emissions, create jobs and invigorate local economies in a post COVID‑19 pandemic world. Sustainable Marine developed an innovative floating tidal energy platform called PLAT-I that has undergone rigorous testing on the waters of Grand Passage, Nova Scotia, for nearly two years. A second platform is currently being assembled in Meteghan, Nova Scotia, and will be launched in Grand Passage later this year for testing before relocation to the Fundy Ocean Research Centre for Energy in 2021. The objective of the project is to provide up to 9 MW of predictable and clean renewable electricity to Nova Scotia’s electrical grid. This will reduce greenhouse gas emissions by 17 000 tpy of CO2 while creating new jobs in the province. Funding for the project comes from Natural Resources Canada’s Emerging Renewables power programme, part of Canada’s more than CAN$180 billion ‘Investing in Canada’ infrastructure plan for public transit projects, green infrastructure, social infrastructure, trade and transportation routes, and Canada’s rural and northern communities.

CorPower Ocean secures license for wave energy project in Portugal CorPower Ocean is set to begin a wave energy project in the Atlantic Ocean after securing a 10-year license. CorPower’s next generation WECs will be tested in the Atlantic Ocean, experiencing some of the most aggressive and challenging maritime conditions. The TUPEM license – awarded by the national Directorate-General for Natural Resources – provides a permit for the private use of the maritime space up to 12 miles off the coast of Aguçadoura, northern Portugal. CorPower Ocean Country Manager, Miguel Silva, said the

permit unlocks the demonstration phase of the firm’s flagship HiWave-5 project, paving the way for a new class of highefficiency WEC products. “The Aguçadoura coastal zone is a world-renowned site for marine renewable energy and has previously hosted the demonstration of floating offshore wind technology, now fully operational and supplying electricity to Portugal’s grid. There is huge potential for wave energy developments to deliver consistent and predictable clean electricity along the Portuguese coast, either as standalone wave farms or combined with floating wind.”




GLOBAL NEWS Ørsted and bp team up on German green hydrogen project

Iberdrola and Fertiberia to invest in Spanish green hydrogen

Ørsted and bp have agreed to jointly develop a potential largescale renewable hydrogen project at bp’s Lingen Refinery in North West Germany. The project, which is expected to be operational in 2024, will comprise a 50 MW electrolyser system capable of generating 1 tph of renewable hydrogen or almost 9000 tpy. This would be sufficient to replace approximately 20% of the refinery’s current fossil-based hydrogen consumption, avoiding 80 000 tpy CO2 emissions – equivalent to emissions of 45 000 cars in Germany. The project is also intended to support a longer-term ambition to build more than 500 MW of renewable hydrogen capacity at Lingen. This could provide renewable hydrogen to both meet all the refinery’s hydrogen demand and provide feedstock for future synthetic fuel production. The electrolyser is expected to be powered by an Ørsted North Sea offshore wind farm. The partners have jointly applied for funding for the project – named Lingen Green Hydrogen – from the EU Innovation Fund, which is one of the largest funding programmes for innovative low-carbon technologies focusing on energy intensive industries.

Iberdrola and Fertiberia have allied in the hope of seeing Spain become an industrial leader of green hydrogen technology, with the aim to install 800 MW of green hydrogen production capacity through a €1.8 billion investment programme over the next seven years. In the next year, the partners will commission their first plant in Puertollano, Spain, becoming one of Europe’s largest green hydrogen complexes for industrial use. The partnership includes plans to develop three additional projects between 2023 and 2027, in the Fertiberia plants of Puertollano and Palos de la Frontera, Huelva, Spain, which could deliver 40 times the capacity of the first plant. The plan would deliver 800 MW of electrolysis, equivalent to 20% of Spain’s national target – which envisages the installation of 4 GW by 2030 – and would ensure that around 25% of the hydrogen currently consumed in Spain is emissions free. The EU and the Government of Spain have launched strategies to promote green hydrogen. The EU aims to have 40 GW of green hydrogen electrolysers in just 10 years, while in Spain the goal is 4 GW of installed capacity.



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