Energy Global - Spring 2021

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34. Handling the heat

03. Comment

Tim Bruewer, Energy & Environmental Technologies at Watlow Electric Manufacturing Company, USA.

04. It's getting greener Down Under Harshavardhan Nagatham, GlobalData, India.

38. The Moon is boss Ralf Starzmann, Sustainable Marine, Germany.

42. Turning to the tide

Harshavardhan Nagatham, GlobalData, India, explores Australia’s energy transition from conventional to renewable, where solar PV and onshore wind are at the forefront while large scale offshore capacity addition is being considered.

Keith Murray, QED Naval, UK.

48. We're going underground


ustralia’s renewable power capacity increased significantly during 2010 - 2020, with most of the growth coming from large capacity additions during 2018 - 2020. The total renewable power capacity was 3340 MW in 2010 and grew at a CAGR of 20.7% to reach 12 467 MW in 2017. With more government efforts to reduce coal power and increase renewable power, the renewable capacity grew at a higher CAGR of 25.7% during 2017 - 2020 to reach an estimated 24 772 MW in 2020. Of this capacity, over 23 000 MW capacity was from solar photovoltaic (PV) and wind power installations. Australia had a bioenergy capacity of approximately 1000 MW in 2010 and this grew only marginally during this period. All other renewable technologies have very minimal capacities. Generation from renewables grew in line with the growth of capacity. During 2014 - 2017, the growth in generation was slightly less than proportional to the growth in capacity as there were delays in some coal power decommissioning, leading to excessive generation. From 2018 onwards, the generation regained momentum. Onshore wind power and solar PV plants contribute to most of the renewable generation in the country.

Anne Knour, TRACTO, Germany.

52. An ocean of opportunity John Olav Giæver Tande, SINTEF, and Magnus Korpås, Norwegian University of Science and Technology, Norway.

Change in the power mix Traditionally, Australia’s power capacity is dominated by thermal power – largely coal and gas-fired. This is due to the country’s substantial coal and gas reserves. At 149 billion t, Australia has the world’s third largest coal reserve, only after the US and Russia. The country also has large natural gas reserves





56. Laying the groundwork Rob Lindsay, Global Offshore, UK.

62. Raindrops keep falling on my wind turbines

10. Stores of plenty Feifei Peng, RES, Germany.

Renate Lemke and Péter Sebö, HPF The Mineral Engineers, Germany.

16. On-demand power at the fingertips Barbara Gregorio, Atlas Copco Power and Flow Division, Spain.

68. Digitalisation of the wind

20. A choice of ingredients

72. Moving crew from A to B

Ralf Wiesenberg, VP of Business Development, Azelio AB, Sweden.

26. A story of storage from the isles

Evgenia Golysheva, ONYX InSight, UK.

Lea Hurst, Head of Fleet, CWind, UK.

78. Change is in the air for RNG Enrico Calzavacca, AB Energy, Italy.

Jeff Damron, Wärtsilä Energy Storage and Optimisation, USA.

82. Weighing up the options 30. Southern Africa's powerhouse Rob Graham, CPCS, Canada.

Yoichiro Taguchi, Yokogawa, Japan.

87. Global news Reader enquiries []

ON THIS ISSUE'S COVER Technip Energies is a leading engineering and technology company for the energy transition, with leadership positions in LNG, hydrogen and ethylene, as well as growing market positions in blue and green hydrogen, sustainable chemistry, and CO2 management. The company benefits from its robust project delivery model supported by extensive technology, products and services offering. Operating in 34 countries, its 15 000 people are fully committed to bringing its client’s innovative projects to life, breaking boundaries to accelerate the energy transition for a better tomorrow. Learn more:

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he evenings are getting longer and lighter, an indication that spring is upon us as daylight saving time comes into force across much of Europe and North America. With this emergence into a new season, Energy Global brings you the first issue of 2021 – our Spring issue. Without trying to jinx the year ahead, so far, activity in the renewables industry for the past three months has been non-stop, with contracts being signed, partnerships co-ordinated, and innovative technologies researched and developed. Whether it be the fact that countries are cracking down on their climate goals for 2030 and the Paris Agreement, or that companies are driven by a competitive spirit and are keen to be the greenest and cleanest in action, the increase in renewables on an international scale is evident and a welcome sight. There is every confidence that this renewables drive will keep pushing on; a knowledge supported by the International Renewable Energy Agency (IRENA)’s recently shared preview of its World Energy Transitions Outlook, which anticipates a decline in fossil fuel use to 2050 by approximately 75%. The main contributors to this reduction will be oil and coal consumption, leaving natural gas as the main fossil fuel to remain in 2050, whilst renewables take charge of the greener energy mix. As time goes on, the gap is tightening between the once-distant worlds of fossil fuels and the world of renewables. The steady departure of fossil fuels from global consumption and the rise of renewables is depicted simply when addressing CAPEX for such energy projects. Analysis conducted by Rystad Energy has found that a new record will be achieved this year for renewables, with CAPEX for projects reaching US$243 billion – not far off from spending in the oil and gas sector, which is estimated to be US$311 billion (a figure that has been in decline for some years, particularly since its heyday in 2019 of US$422 billion).

Rystad has detailed where most of the spending in the renewables sector will be utilised, with onshore wind projects climbing by US$6 billion from its 2020 spending to US$100 billion this year, and solar photovoltaics CAPEX reaching US$96 billion, up from US$88 billion in 2020. Consulting Energy Global’s website ( – home to the latest updates and industry news – provides a pool of information to enhance the reports published by the likes of Rystad Energy and IRENA. Between Siemens Gamesa being awarded a contract to supply wind turbines in New Zealand, GE Renewable Energy supplying turbines to Vietnam, and Total Eren commissioning a wind farm in southern Argentina, there are numerous articles on the onshore wind sector, which is proving it is on track to spend US$100 billion this year. However, offshore wind cannot be ignored, as CAPEX for these projects is expected to grow to US$46 billion this year, largely contributed to by China’s Rudong wind farm and Ørsted’s Hornsea 2 project in the UK. The vast scale of these projects has positive upshots throughout the industry, with companies coming onboard from across the globe – inter-array cable systems need to be supplied, protection systems put in place for cables, monopiles transported, steel platforms fabricated, turbines manufactured, etc. In this issue of Energy Global magazine, our technical articles cover a varied spectrum of renewable energies, including a regional report on Australia’s renewables sector, research and development into tidal power, the future of energy storage, and the opportunities and advances in offshore wind, plus many more. With a breadth of information shared, we hope this latest issue of Energy Global provides you with some new knowledge and perhaps some alternative perspectives on the future technologies shaping the renewables industry.

Harshavardhan Nagatham, GlobalData, India, explores Australia’s energy transition from conventional to renewable, where solar PV and onshore wind are at the forefront while large scale offshore capacity addition is being considered.


ustralia’s renewable power capacity increased significantly during 2010 - 2020, with most of the growth coming from large capacity additions during 2018 - 2020. The total renewable power capacity was 3340 MW in 2010 and grew at a CAGR of 20.7% to reach 12 467 MW in 2017. With more government efforts to reduce coal power and increase renewable power, the renewable capacity grew at a higher CAGR of 25.7% during 2017 - 2020 to reach an estimated 24 772 MW in 2020. Of this capacity, over 23 000 MW capacity was from solar photovoltaic (PV) and wind power installations. Australia had a bioenergy capacity of approximately 1000 MW in 2010 and this grew only marginally during this period. All other renewable technologies have very minimal capacities. Generation from renewables grew in line with the growth of capacity. During 2014 - 2017, the growth in generation was slightly less than proportional to the growth in capacity as there were delays in some coal power decommissioning, leading to excessive generation. From 2018 onwards, the generation regained momentum. Onshore wind power and solar PV plants contribute to most of the renewable generation in the country.

Change in the power mix Traditionally, Australia’s power capacity is dominated by thermal power – largely coal and gas-fired. This is due to the country’s substantial coal and gas reserves. At 149 billion t, Australia has the world’s third largest coal reserve, only after the US and Russia. The country also has large natural gas reserves




of over 84 trillion ft3. Australia exports most of its coal production to Japan, China, South Korea, and India, and uses a small share to cater to its own domestic coal-fired plants. With natural gas, Australia consumes around one-third of its own production and then exports the remainder. This has increased in the past years with the increase of gas-fired power capacity. The Australian power capacity portfolio is undergoing a major transition and the power sector is currently in a very critical point of this transition. Thermal power went from comprising 73% of the country’s power capacity in 2015 to less than 60% in 2020. Meanwhile, renewable power capacity’s share increased from 14.5% to 30.4% during the same period. This was possible due to the decommissioning of coal-fired capacity every year during 2015 - 2019 and the addition of solar PV and onshore wind power capacities during the same period.

Outcome of the Paris Agreement At the Paris Climate Agreement in 2016, Australia ratified and pledged to reduce greenhouse (GHG) emissions by 26% to 28% below 2005 levels. In this pursuit, among other initiatives, the

government aimed at phasing down or phasing out coal power and replacing it majorly with renewable power and some gas-fired thermal power. As part of the phase-down plan, the government set a target of halving the amount of GHG emissions from coal-fired plants by 2030, which would translate to reducing the coal power generation by 50%. The country has included the addition of gasfired capacity in its emission reduction roadmap as it is difficult to compensate for the planned coal phase-down with just renewable power. Australia’s targets are considered quite unambitious as the targets include Land Use, Land Use Change, and Forestry (LULUCF) related emissions, whereas most countries’ targets are of similar extent but excluding LULUCF emissions. Despite this, the country needs large renewable capacity additions in order to meet their own targets. Although renewable power installations existed in Australia since the early 2000s, major capacity additions started quite late and only after the signing of the Paris Agreement. However, between signing the agreement and now, much less capacity addition has taken place than was earlier estimated because the phase-down of coal power did not initially reach the levels that were planned. Even before signing the Paris Agreement, the Australian Government had planned to decommission significant coal-based capacity and substitute it with natural gas-fired capacity, as the latter is less emission intensive. The increase in gas-fired capacity and insufficient coal plant decommissioning led to abundant capacity and generation and consequently to a fall in wholesale electricity prices, disincentivising new renewable capacity growth.

Positive environment for renewables created by coal phase-down

Figure 1. Australia’s renewable power capacity by technology, 2010 - 2020. Source: GlobalData Power Database [Accessed on 09 February 2021]. Note: 2020 numbers are estimated.

After signing the agreement, the government has been more instrumental about phasing down coal power capacity and creating space for renewables in the power mix. The government uses an auction system that identifies the plants that are least profitable and the plants that have the least remaining life. This way the government plans to minimise the cost of reducing emissions. During 2016 - 2020, the coal power capacity decreased by 2.3 GW, with a decrease of 1.5 GW in 2017 alone. This drove up electricity prices and helped attract investments into renewable power. During the same period, over US$24 billion was invested in renewables, leading to a capacity addition of 13 691 MW of renewable power. One option for the government as it further expedites coal power decommissioning and boosts renewable power, is to fully compensate several coal plants’ entire future profits and get them to shut down, as was the case in Germany. This would require significant funds, and the extent of government support in the next round of auctions remains to be seen. Faster and more coal power decommissioning would lead to an overall reduction in generation and make renewable capacity addition more profitable for developers and power producers.

Major renewable technologies

Figure 2. Australia’s renewable generation by technology, 2010 - 2020. Source: GlobalData Power Database [Accessed on 09 February 2021]. Note: 2020 numbers are estimated.



Australia currently has solar PV, onshore wind power, solar thermal, small hydropower, bioenergy, and geothermal power technologies with active capacities. Except solar PV and onshore wind, all other technologies have only negligible capacities installed in the country and the other technologies do not have any major upcoming capacity additions either in the next 10 years.


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The only new technology to add capacity in the coming years is offshore wind power, with 1 GW planned capacity by 2030. Among solar PV and wind power, wind power was the first to have large capacities added, but solar PV has larger active capacity currently. In 2008 when there was less than 100 MW of solar PV capacity, there was over 1 GW of onshore wind power capacity. In 2020, solar PV capacity was estimated at 16.5 GW while that of wind power was 6.85 GW. During 2021 - 2030, both solar PV and wind power (including upcoming offshore wind plants) are estimated to add similar capacities, while capacity additions from all other technologies are set to be little to none. Solar PV capacities of under 50 MW were added in Australia each year during 2000 - 2009. It was in 2010 and 2011 that solar capacity was developed on a slightly larger scale to the order of a few hundred megawatts. From 2012 onwards, approximately 1 GW of solar PV capacity, mostly through rooftop installations, was added each year up until 2017 and over 2.5 GW in 2018. Australia has abundant wind resources and policy support. In 2020, Australia had 6.85 GW of wind power installed capacity, accounting for an 8.4% share in the country’s cumulative power capacity compared to a 7.5% share in 2019. Historically, the total wind installed capacity has grown by a CAGR of 13.9% during 2010 - 2020. Several new wind projects were commissioned in 2019 and 2020. Some of the major wind power projects under

construction and set to be commissioned in 2021 and 2022 include: Stockyard Hill wind farm, Moorabool wind farm, and Berry Bank wind farm – all in the state of Victoria.

Policy support

Figure 3. Cumulative coal power capacity and wholesale electricity spot prices, 2012 - 2018. Source: GlobalData Power Database [Accessed on 09 February 2021]; Australian Energy Regulator, 2021.

Policy support by the government for the promotion and development of wind power in the country has been driving the growth of the market. The need for Australia to meet its emission reduction targets, and policy support extended in that pursuit, have led to significant capacity additions since 2016 and will continue to drive the same. Currently, four of the six states in Australia – Queensland, South Australia, Tasmania, and Victoria – as well as the Australian Capital Territory (ACT), have feed-in tariffs (FiT) for small scale renewable installations. Most of these schemes were introduced in 2008 - 2010, which explains the surge in solar PV capacity in the country after 2010. Although small installations of several technologies qualify for these FiTs, they are mostly claimed by rooftop solar PV installations on residential buildings. These FiTs were given on a long-term basis and fixed at approximately AUS$0.40/kWh. Installations that had signed up for these FiTs still get these high rates while current FiTs are much lower, in the region of AUS$0.10/kWh, and are given for one-year terms, after which the tariff gets reviewed. Currently, in most states the state government sets a minimum FiT and revises this periodically. The electricity retailers compete and offer slightly higher FiTs as yearly contracts. To promote large scale installations, ACT and Victoria have taken up auctions to allot solar PV capacity to developers and sign PPAs with them at a price that developers deem profitable. This has kept the annual capacity addition stable during 2015 - 2020. The Government of Australia had set a target of 8 GW wind power capacity by 2020, but based on GlobalData’s estimates of capacity addition, it seems that the country has fallen short of this by approximately 1 GW, owing to small delays in construction due to the COVID-19 pandemic. With the resumption of construction in most of these sites, the country is likely to achieve the target in 2021. Wind power is expected to account for a majority of the share in the country’s total renewable energy mix. Victoria and South Australia hold the largest wind power capacities in the country with close to a 30% share each, while New South Wales is the third largest and holds 22.4% of the country’s wind power capacity.

Table 1. Australia renewable power auctions


Auction date

Auction name



Auctioned capacity (MW)

Awarded capacity (MW)

Technology of awarded capacity

08 September 2020

ACT Fifth Renewable Energy Reverse Auction, 2020


ACT Government




11 September 2018

Victorian Renewable Energy Targets (VRET) 2017 Reverse Auction


Department of Environment, Land, Water and Planning



Wind and solar

23 August 2016

Next Generation Renewables Auction, 2016


ACT Government




17 December 2015

Australia’s ACT Wind Auction II, 2015


ACT Planning and Land Authority




06 February 2015

Australia’s ACT Wind Auction I, 2015


ACT Planning and Land Authority





Rise of imports and the future of domestic manufacture Most solar PV installations in Australia use PV modules imported from China because the domestic production of modules is still very small in the country. After the signing of the Paris Agreement, the import of solar modules more than tripled in Australia, creating a huge opportunity for locally manufacturing modules. Tindo solar, the only large domestic manufacturer, started building a new manufacturing capacity in order to cater to the increasing demand and tap into the market currently dominated by Chinese imports. Several other international manufacturers are considering setting up manufacturing units in the country with the same intention, while some European manufacturers are trying to export their modules to Australia and compete with both domestic modules and Chinese imports. With approximately 3 GW solar PV capacity set to be allotted each year during 2021 - 2025, the module manufacturing and importing business is set to see considerable action during this time. The manufacture of wind turbines has been minimal in Australia due to the high cost of labour and the fact that most of the wind farms have used turbines imported from China and India. Domestic industry associations have made some efforts to impose anti-dumping tariffs on turbine imports but that has not led to any major increase in domestic manufacture. With the introduction of the auction mechanism in 2015 and significant capacities awarded, the import of wind equipment soared during 2016 - 2019. In 2020, Australia added over 1 GW of wind power capacity for the first time, and during 2021 - 2030, it is estimated that over 2 GW wind power will be added each year. Capacity additions of this level are sufficient to make domestic manufacturing of wind turbine components attractive, and this would receive a further push if one or more state governments levy domestic content requirements on power producers that wish to sign PPAs with the state. Based on current estimates, it can be expected that the imports would decrease during 2023 - 2027 and domestic manufacturing would pick up during the same period.

The way forward During 2021 - 2030, the renewable capacity addition in Australia will continue to be restricted to solar PV and wind power. Renewable power capacity is set to grow from an estimated 30 287 MW in 2021 to over 72 000 MW in 2030 at a CAGR of 10.2% during this period, with over 95% of the capacity additions coming from solar PV and onshore wind power. With further decommissioning of coal plants and only moderate addition of gas-fired plants, the share of renewables is set to increase significantly and reach 55% of total cumulative power capacity by 2030. Offshore wind power is set to make a debut in the country toward the end of the decade and is set to grow significantly after 2030. Offshore wind power is a practical form of power in Australia as over 80% of the country’s population lives in several coastal cities. It is more practical to wheel electricity from offshore plants to coastal cities than wheel electricity from the vast expanses in the northern and central parts of the country to the coastal cities through a grid that is already overloaded. The country has an established marine industry which can aid with installations and provide labour that can be easily transitioned from their current jobs to the jobs in offshore installations, utilising their existing marine

work skills to an extent. Australia has approved its first offshore wind project and the plant is set to be commissioned in two phases in 2028 and 2029. Pilot Energy, an oil and gas company, plans to use its existing offshore capabilities to install the country’s first offshore wind farm with a capacity of 1 GW. Following this, it is likely that the momentum would pick up with more installations. During 2021 - 2025, more rounds of renewable power auctions are estimated to take place in order for the country to boost capacity, compensate for coal phase-down, and meet emission targets. Areas with large untapped solar and wind power potential will need to be used for installations. Many of these high potential regions do not have grid connectivity. Besides, the grid regulators are already planning to set caps on new renewable power connections to the existing grid due to congestion. The Australian Energy Market Operator (AEMO) claims that the existing grid is technically capable of handling up to 75% renewable energy, but the problem is with the inability to connect new capacity additions, especially in areas distant from existing grid infrastructure. There is currently no significant upcoming grid infrastructure in the country, but to smoothly incorporate upcoming renewable capacity, the AEMO would soon feel the need to establish grid connectivity to new regions and strengthen existing connections.

Figure 4. Australia’s wind turbine imports (US$million). Source: GlobalData, 2021; UNCOMTRADE, 2021 [Accessed on 09 February 2021].

Figure 5. Australia’s forecasted renewable power capacity by technology, 2021 - 2030. Source: GlobalData Power Database [Accessed on 09 February 2021].




Feifei Peng, RES, Germany, comments on how battery storage will help empower the energy transition as countries around the globe commit to climate targets.


he next decade is set to be a period of mass energy transition. The world’s leading carbon dioxide (CO2) emitters (China, US, and the EU), who together account for more than half of global CO2, have each set ambitious near-term climate targets by 2030 to dramatically curb those emissions.1 Notably, on 11 December 2020, EU leaders agreed to increase the target to cut greenhouse gas (GHG) emissions to 55% by 2030 (compared to 1990 levels). The following day, President Xi of China restated China’s commitment to reaching peak carbon by the end of this decade. Additionally, in the US, President Biden has made the rejoining of the 2016 Paris Agreement among his immediate priorities as newly elected president. Since global primary energy consumption makes up approximately ¾ of total harmful GHG emissions, the stage is set for a decade of mass energy transition. With non-emitting, renewable energy technologies such as wind and solar taking their place firmly in the mainstream in recent decades, clean electricity generation represents one of the most effective levers for achieving the necessary GHG reductions. But growth in renewable energy of this scale, although theoretically achievable, exposes some fundamental shortcomings in market design and electricity distribution infrastructure. Take the Electric Reliability Council of Texas (ERCOT) market as an example, where there has been substantial increases in renewable energy generation capacity over the past decade. Driven by the fuel-free nature of wind and solar energy, wholesale power prices in this liquid market have seen great reductions during periods of high renewable generation and dramatic price spikes


when peak demand coincides with low renewable generation (Figure 1). The traditional definition of peak demand which follows daily, seasonal, or annual patterns is now disrupted by renewable generation whose variability requires a fast, affordable, and reliable response. Secondly, although fuel-free and non-emitting, renewable energy – specifically wind and solar generation – is not always optimally situated with respect to load. Such fundamentals require both considerable investment in electricity transmission and the ability to store energy, as low-cost wind and solar generation occupy an increasing share of the electricity supply mix. Battery energy storage systems (both mobile and stationary), with their falling cost and improving technology, are now viable enablers of more renewable energy. They can offer alternatives for increasing transmission and distribution system operators to provide safe, affordable, and reliable energy to consumers. However, as a nascent industry, battery energy storage is not without its challenges, requiring careful attention to supply chain dynamics and changing standards for cost-effective deployment and safe, reliable, long-term operation. As Bloomberg New Energy Finance’s December 2020 report ‘2020 Lithium-Ion Battery Price Survey’ shows, between 2010 - 2020 there has been an 89% fall in battery pack price including a 13% decrease from 2019 in 2020. Notably, this past year’s decline in cost was greater for stationary storage at 20%. Such decline in cost is largely driven by the rapid growth in demand for electric vehicles (EV), which is impacting the dynamics of the supply chain. Car manufacturers are taking aggressive steps to secure battery supply through equity investment in battery suppliers, forming joint ventures and/or partnerships to jointly invest in production lines. Similarly, different energy storage integrators or EPC companies each have had to develop their own plans for defensively securing supply chain. As the industry moves forward at an expectedly rapid pace this decade, it will be important to recognise that not all batteries are created equal, and with myriad custom applications and multi-decade project lifecycles, it is essential that the industry pays close attention to the fundamentals: quality of design and interoperability to safeguard potential future revenues, supplier bankability, and

warranty and suppliers’ commitment to service such warranty. A sustainable storage market, and by extension a clean electricity supply mix, requires a healthy and diversified supply chain.

Safety in the supply chain A secure and diversified supply chain is certainly important, but even more crucial is a non-compromising position on safety as an abundance of manufacturers debut on the international arena. Batteries have inherent fire risk and, according to statistics from Clean Energy Associates, in the first half of 2020 China reported 20 EV fires alone, and since 2017, South Korea experienced a total of 28 energy storage system fire accidents. In the US, an energy storage system explosion occurred at a facility in Arizona that resulted in injuries to four fire fighters. In September 2020, an energy storage explosion in Liverpool rang the alarm for industry participants in the UK. Looking to the future where battery storage systems are increasingly and internationally deployed at scale, on one hand from the supply chain there is an increasing trend toward higher energy density, reduction in state of health limit and longer lifecycles, and on the other hand from investors the desire to have extended battery lifetime and flexible usage. It is vital that safety is not compromised.

Mass transition

Deploying battery storage to truly accelerate the mass transition toward renewable energy requires more than a robust and diversified supply chain. Safely operating utilityscale battery energy storage systems to unlock their full value, whether stand-alone or paired with generation, is not a trivial undertaking. Maintaining a healthy state of charge of batteries is a delicate balancing act, a choreography between hardware and software to enable seamless integration of storage assets with utilities, off-takers, and coupled generation in the case of hybrid systems. The future will see many storage sites performing a myriad of services, hybrid sites, and a constantly evolving technology and market landscape. RES began preparing for this over seven years ago with investment in its RESolve platform. This flexible energy management system (EMS) allows for the tailoring of a site’s components to specific market needs to deliver quality, reliable service. RES use it to hybridise sites, deliver solar sites that are storage ready, and make it easier to plan for a future addition of storage. The company standardises battery types, services, and site architecture at fleet level, allowing a single unified interface to manage assets and services. At the same time, the RESolve system allows Figure 1. US merit order maker: Interactive power supply curves, January 2021. Image courtesy of Bloomberg New for fleet standardisation while Energy Finance. maintaining the flexibility to offer



Wind farms have become a mainstay of the energy transition in recent years, their development potential is considered the most economical among renewable energies. Trenchless installation of the power lines for connecting wind turbines and distributing

the green current makes it possible to tap this potential in an economically sensible and ecologically friendly way. Besides, the reduced land requirements can make a valuable contribution to the acceptance of wind farms in the public.


Figure 2. Bordesholm energy storage project in Germany, developed by RES for VBB.

finding the optimal operating zone for batteries to provide a sustainable service. By trialling alternative control strategies in a simulation environment that is tuned to accurately represent the real system, tailored control mode improvements can be recommended and deployed in RESolve. As shown in Figure 3, the possible trade-offs between battery throughput and service performance are scored for a frequency response application, leading to identification and implementation of the desired configuration. The impact of the control mode change is subsequently verified using the operational data. This process can be applied iteratively throughout the asset life to continuously adapt the operational strategy as desired. The same advanced analytics methodologies are used during the design phase to optimise the system configuration and inform techno-economic assessments. Technology has afforded the industry many advancements, but it needs to be operated properly, in a timely fashion, and be locally maintained. Safe and effective long-term operation of battery energy storage systems’ facilities depends on robust supplier engagement, careful monitoring, and timely incident response.

Technology in practice

Figure 3. The RESolve system trials alternative battery control strategies in a simulated environment, tracking their impact to predict performance. This allows batteries to be calibrated based on the available data in order to keep them operational for as long as possible.

additional ancillary services and respond to future market opportunities. Fortunately, efforts in developing RESolve pays off for clients. The blackouts in August 2019 in the UK is a good example. Ofgem, the UK market regulator, declared that “the overall performance of frequency response providers was generally inadequate”, however, the three RES-developed and constructed UK assets that responded to this event did so perfectly. This was due to RES’s ability to choose technology and design it precisely for the service required to ensure performance and revenue during the most essential times. More recently, National Grid ESO has launched a new Dynamic Containment service. The suite of flexible controls developed for RESolve can be easily adapted to deliver this service, deploy across a fleet, and capture additional revenue stream for asset owners.

The data behind the scenes Behind RESolve’s algorithms is a team of data scientists who couple accurate simulations with operational data analysis to facilitate operational improvements and through life performance predictions. The harder a battery is used to perform services, the more quickly it reaches its lifetime capacity. It is therefore crucial to keep batteries operational for as long as possible. At RES, data scientists do this by


RES is the one of the world’s largest independent renewable energy companies active in onshore and offshore wind, solar, energy storage, transmission, and distribution. At the forefront of the industry for 39 years, the company has delivered 19 GW of renewable energy projects across the globe and supported an operational asset portfolio exceeding 7 GW worldwide for a large client base. Since 2014, RES has been operating battery energy storage projects. From conducting timely repair and preventive maintenance to the management of incidents, to obsolescence and warranty, RES Asset Managers closely monitor conditions and deploy local staff to carry out preventative maintenance and manage any incidents. The benefit of this local presence was never clearer than during this past year of COVID-19 pandemic travel restriction. Recently the company constructed the Top Gun Energy Storage facility in California, US, a 120 MWh lithium-ion site – the company’s largest in the country. Indeed, the company has in-depth knowledge on batteries having worked with seven different suppliers on more than 370 MWh of battery projects in that time. Its vision is to create a future where everyone has access to affordable zero-carbon energy. Today, utility-scale battery energy storage systems are essential infrastructure. They have reached both technological and commercial maturity of being investment grade assets. They are playing an increasing role in ensuring the stable operation of generation and transmission systems, setting the stage for significantly greater adoption of renewable energy, and empowering this decade of mass energy transition. *Article written in February 2021.

References 1.

CRIPPA M., GUIZZARDI D., MUNTEAN M., SCHAAF E., SOLAZZO E., MONFORTIFERRARIO F., OLIVIER J., and VIGNATI E., ‘Fossil CO2 emissions of all world countries: 2020 Report’, 2020.



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he way energy is consumed, produced, and stored is changing. The shift towards a more sustainable way of operating is visible across industries, driven by tightening legislation, the need to improve efficiency to remain competitive, and growing awareness of the planet’s health. Coupled with the need to continue to drive productivity, companies in all sectors are looking for cost-efficient and effective ways to address the challenge. Technology trends in the industry, such as the growing electrification of industrial machinery, reflect this. In recent years, battery technologies and energy storage systems have emerged as crucial technologies in this field, helping industrial and rental businesses find more versatile and efficient access to energy, while also lowering the total cost of ownership. Lithium-ion (Li-ion) battery energy storage systems can help with all the above. For example, Atlas Copco’s ZenergiZe range can help operators to unlock reliable, on-demand power while optimising the sustainability and efficiency of their operations.


What is a battery energy storage system? A battery energy storage system is a sub-set of energy storage systems, using an electrochemical solution. In other words, a battery energy storage system is an easy way to capture energy and store it for later use, for instance, to supply power to an off-grid application; or to complement a peak in demand. They are usually not used to replace grid power completely but instead used to offer short-term solutions in applications where access to grid power is intermittent, or the use of a generator is unsuitable due to noise or pollution concerns. Energy storage systems are also often used to manage energy generated from intermittent sources, such as solar panels or wind turbines, amongst others. A variety of different battery technologies are available for use in battery energy storage systems. However, in recent years solutions using Li-ion batteries have grown in popularity, driven by their long working life, wide operational range, lightweight structure, high energy efficiency, and crucially, the falling cost

Barbara Gregorio, Atlas Copco Power and Flow Division, Spain, explains how energy storage systems can provide a quiet source of power and reduce carbon dioxide emissions.



of the technology.1 These, combined with the low total cost of ownership and sustainability, make them attractive for several applications.

How does a battery energy storage system work? A Li-ion battery is comprised of:

F Cathode (+): A lithium compound with different ions coming from different raw materials such as iron, phosphate, and cobalt.

F Anode (-): Usually graphite that also contains lithium. F Separator: The separator allows the ions to flow, controlling the charge so it is not discharged all at once. In a Li-ion battery, the electrolytes carry positively charged lithium ions between the anodes and the cathodes through the separator. As the lithium ions move, the movement creates free electrons in the anode, creating a charge at the positive current collector. This enables the electrical current to flow on from the current collector, through the device being powered, and back to the negative current collector. When the battery is powering a device, the anode releases lithium ions to the cathode, effectively creating a flow of electrons from one side to the other. In rechargeable batteries, this flow is reversed when the battery charges (with an external source, such as a generator), as the lithium ions are released by the cathode and received by the anode.2

Ensuring sustainable, flexible power Atlas Copco’s ZenergiZe unit range is a good example of how the high-density Li-ion batteries can be leveraged to enable a new level of sustainability, flexibility, and usability, without compromising on power. Due to their modular structure, they can be considered an ideal solution for small businesses requiring a versatile power management, as well as large applications with multiple units, where they aim to revolutionise fleet efficiency. The ZenergiZe units can serve as the primary source of power in ‘island mode’. Alternatively, they can be combined with a generator to enable smart load management, giving operators with demanding applications peace of mind that any peaks in demand can be effectively addressed. With a footprint of 1.5 m2, the units are 70% smaller and lighter in weight than traditional stand-alone generators, which means that they can be transported without any specialist equipment. Despite their compact size, they pack a punch: a unit can provide over 12 hours of energy with a single charge, and the charging time is only 1.5 hours. The solution has a working life of over 40 000 hours. This translates to more than 5000 cycles, or over 1600 days of continuous operation – although this figure is useful for illustration purposes only, as battery energy storage systems are primarily used as a temporary system. This contributes to a very low total cost of ownership, and the system typically pays itself back in under two years.

The three zeros The technology is built to help operators embrace a new way of managing, storing, and using energy.

Zero emissions The ZenergiZe units have been designed with sustainability in mind, enabling operators to drastically reduce emissions and fuel consumption in every application. With a hybrid solution, during its operating life the emissions of a standard stand-alone generator can be reduced by up to 50%. This translates to approximately 100 t of CO2 – the equivalent of planting 450 trees (assuming a tree life of 30 years). However, if the unit is used as a stand-alone power solution and charged by a renewable energy source, such as a solar panel, it can eliminate up to 100% of the CO2 emissions of the operation. Figure 1. Battery discharging.

Zero noise Another key benefit of a battery storage solution is the lack of noise. Unlike generator-powered solutions where the sound of the engine is impossible to eliminate, batteries operate silently. In island mode, the ZenergiZe unit can be operated noise-free, which helps operators comply with regulations at city centre construction sites, and other environments where generator noise is undesired or unsuitable, for example at events.

Zero maintenance

Figure 2. Process of battery charging.


In normal operating conditions, the Li-ion batteries have a lifespan of 40 000 hours and an overload capability of 200%. The units have also been specifically designed to operate in high and low ambient temperatures, from -15˚C to 50˚C. This helps minimise maintenance needs during the battery energy storage

systems’ lifecycle, helping operators achieve optimal uptime. It is essential to have a regular maintenance schedule in place to optimise the health of the batteries used in the solution.

Choosing the right operating mode One of the key benefits of the company’s modular battery storage solution is its flexibility. Depending on the application, and the available power source, the unit can be used either as a sole source of power or to enable smart load management to help balance power consumption in demanding applications.

Island mode In island mode, the units can be used as a stand-alone source of power. The modular unit can be used in a 3ph connection or in a single phase. A typical application would be a small event in a city centre, where the unit is needed to power low loads, such as lighting and music devices, and where emissions and noise need to be limited. When combined with a renewable source to produce the energy needed, such as solar panels or a wind turbine, running the units in an island mode can reduce CO2 emissions by up to 100%, resulting in a completely sustainable solution.

Figure 3. Energy storage systems are also used to manage energy generated from intermittent sources, such as solar panels.

Hybrid mode In the hybrid mode, the ZenergiZe units are combined with any diesel generator to enable smart load management. This mode is ideal for improving performance in an application such as a construction site, where the batteries can be used to feed low loads – such as site lighting – during nights, or to supply extra power during peaks in demand. The generator will recharge the batteries when the demand for power is low, optimising efficiency and ensuring that the batteries are ready for use when needed. The hybrid mode is designed to help operators improve sustainability and cut costs. It can reduce the daily fuel consumption by up to 50%, compared to a stand-alone diesel generator, significantly reducing the cost of operations, and saving approximately 100 t of CO2. In addition to green operation, a key benefit of the hybrid mode is that the battery system can help extend the lifespan of the generator while optimising its performance. In practice, this means that a 40% smaller generator can be used for the same application. This helps operators reduce fuel consumption by a corresponding amount, improving sustainability. A smaller and lighter unit also translates to reduced fuel costs during transportation, and the small footprint makes the unit an easy fit for a range of applications from busy construction sites to crowded events.

Solar plus storage When combined with a renewable energy source, such as solar panels, the ZenergiZe units can become 100% sustainable, eliminating all emissions. Access to power is often a challenge for telecom operators with towers in rural areas where connecting to the grid is impossible. As towers often use generators that are larger than their real power needs, low loads can have very negative effects on the engine, resulting in oil leakages or black fumes. To avoid this, the most sustainable alternative is using the combination of

Figure 4. ZenergiZe units can serve as the primary source of power in island mode.

solar panels and a battery energy storage. During the day, the power demand can be covered with the solar panels, which will also recharge the batteries in the energy storage system. During the night, or when the sun cannot provide enough energy, the energy storage system will take the lead. This optimises the use of the generator, saving it for use when it is really needed, and eliminating all CO2 emissions for the duration of use.

Conclusion The industry is at a turning point when it comes to energy consumption. That is why forward-thinking businesses are already taking steps towards a more sustainable, more flexible, and overall more efficient way of operating. Electrification and the reduction of fossil fuels it enables is a key driver for change. Technologies such as ZenergiZe are crucial for providing a costefficient way to enable this, helping to reduce CO2 emissions and improve operations.

References 1. 2.

Environmental and Energy Study Institute, ‘Fact Sheet Energy Storage’, (2019). Office of Energy and Renewable Energy, ‘How Does a Lithium-ion Battery Work?’, (2014).



Ralf Wiesenberg, VP of Business Development, Azelio AB, Sweden, details the importance of energy storage, with a focus on Li-ion batteries vs the company’s technology, and the security of supply chains for a more sustainable and diversified future.


he global energy transition in the power sector away from fossil fuels to renewable energy will not meet its true potential without a massive use of storage application. A recent BNEF report has forecasted that the annual energy storage demand will double in two years from now, reaching a total of 150 GWh in 2030. In the following years, variable renewable energy sources such as wind and solar power will replace conventional power generation as the main energy source in many countries. This will trigger an increased use of energy storage for grid stability purposes but also for distributed baseload power supply. The graph in Figure 1 illustrates in a simplified way how demand and supply must be matched during every hour of the day if the goal is to achieve an almost 24/7 supply of power using solely renewable energy. This can be done by directly using solar power during the daytime and then an energy storage system with dispatchable power production for the rest of the day.


Li-ion batteries are so far the first choice for many applications and account for more than 98% of installed capacity of energy storage, excluding hydropower. However, the prevalence of Li-ion batteries does raise concerns regarding the security of supply due to the over-reliance on Asian supply chains. The ongoing COVID-19 crisis has shown in a drastic way how vulnerable the world economy is to disruptions in supply chains, as well as how dependent it is on raw materials and products from Asian countries. In addition, the mining and processing of raw materials, as well as the manufacturing of Li-ion batteries, are causing severe environmental, health, and social impacts. As an example, consider the 2018 CBS News investigation which looked into child labour in cobalt mines in the Democratic Republic of Congo. The investigation revealed that approximately 40 000 children work in cobalt mines.

Europe’s role The EU has been aware of these issues for a long time and has started to map the sources and the impact of so-called critical raw material for its economy. Access to resources has been identified as a strategic security question for Europe’s ambition to deliver the Green Deal and meet its target of 2050 climate neutrality, as well as increasingly ambitious commitments for 2030. Earlier this year, the EU Commission published a revised list of critical raw materials, screening 83 materials, including lithium. By doing so, this addressed the vulnerability of the exponential growth expected for Li-ion batteries in the transport and power sector. The projected growth for Li-ion batteries is susceptible to supply constraints, not just for lithium but also for other



critical raw materials used for these kinds of batteries, including cobalt, vanadium and phosphorus. One strategy, which some companies have chosen to manage this risk, is to engage in mining activities closer to consumer markets. According to a recent Financial Times article, Infinity Lithium is seeking a permit for a lithium mine in Spain, while Savannah Resources wants to develop an opencast mine in Portugal. Other examples include the German start-up Vulcan Energy Resources, looking to extract lithium from geothermal waters, or Tesla, which wants to start mining lithium in Nevada, US. All these planned mining activities will improve the security of lithium supply but will take time and require significant investments. Another way to avoid possible supply chain constraints and related negative socio-environmental impacts is to shift from Li-ion batteries to alternative battery systems, where the main components do not consist of critical raw materials.

The company has developed a long duration energy storage solution, called TES.POD, which is able to store thermal energy and dispatch it as electricity and low temperature heat for 13 hours or more, depending on demand. The concept of the TES.POD is based on two main components. The first one is a thermal energy storage using a non-critical raw material – recycled aluminium silicate – as a phase changing storage medium, which is heated up to 600˚C by electricity (charging cycle). A Stirling engine is the other main component and converts the stored heat back to electricity and supply of low temperature heat at 55 - 65˚C on demand (discharging cycle). The TES.POD has interesting advantages compared to incumbent battery systems. One is the high constant charging power that enables the TES.POD to be fully charged in 6 hours. This characteristic is very important for operating in a real environment when using solar or wind power as the main charging source. Take, for instance, the production profile of a fix-tilt PV plant presented in Moving away from critical raw materials Figure 1. It is evident that there are only 6 - 8 hours per Azelio, a Swedish SME high-tech company, chose to go day during which a PV plant generates power at a higher down this route where the main components of battery level. The power produced during the morning and early storage systems do not rely on critical raw materials. evening hours is very low and is not enough to charge a long duration battery system. Li-ion batteries used for long duration storage – for example with 13 hours of constant discharge power – would need considerably more time than these available 6 - 8 hours to charge the battery. It is an inherent technical attribute of Li-ion batteries and it will be the case for the time being. This means that Li-ion batteries cannot provide the required 13 hours, as requested, of power under these conditions. The only solution to this problem is to significantly oversize the PV field and, most important and of greatest cost, to oversize the Li-ion battery capacity. A further advantage of Azelio’s storage system is its ability to switch modes directly from charging to discharging mode, and achieving this whilst with full operating discharging power. Figure 1. Typical daily power demand curve and power production of a photovoltaic Li-ion batteries cannot achieve this without (PV) installation. losing performance. Trying to discharge a Li-ion battery directly after charging it with full power is possible but results in an accelerated internal energy consumption. As a result, the Li-ion battery cannot supply full power for the required discharging time of, for instance, 13 hours. Additionally, unlike Li-ion batteries, Azelio’s TES.POD is designed to offer 100% depth of discharge and is able to charge and discharge at standard operational capacity, regardless of the state of charge of the system. Normally, the depth of charge of Li-ion batteries is in the region of 80% and they cannot charge or discharge with constant operational power. The input power of a Li-ion battery must be reduced as the battery is approaching the upper limit of its state of Figure 2. Largest supplier countries of critical raw materials to the EU. charge. The same happens for its output power,


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Figure 3. EU economic importance and supply risk results of 2020 criticality assessment.

with already recycled aluminium. This will position Azelio’s solution as part of the circular economy in its truest sense.

Conclusion It is evident that the world cannot rely on Li-ion batteries as the only energy storage technology in the future. Specifically, long duration storage would need vast amounts of lithium and other critical raw materials, as the size of batteries and the volume Figure 4. End uses and sourcing of aluminium in the EU (average 2012 - 2016). of the market segments to be served, will increase significantly. which must decrease as the state of charge approaches its It is already clear that long duration storage minimum level. applications are playing an increasing role in the Finally, Azelio’s system has been created for a technical power supply of off-grid application in sectors such as lifetime of 30 years and, with the environment in mind, the mining, agriculture, water treatment and desalination, stored aluminium is fully recyclable without degradation telecommunications, as well as residential communities. after decommissioning of the system. The Swedish In these cases, hybrid PV and storage systems are mainly research institute RISE carried out an independent lifecycle substituting the use of fossil fuel for diesel genset, which assessment of Azelio’s system and the results found that is resulting in a considerable reduction of CO2 and other contaminating emissions. Azelio’s carbon footprint is at least 29% lower than for a However, the demand for long duration storage will also Li-ion battery system, and not taking into consideration the rapidly grow in on-grid applications, as well as highway degradation of the Li-ion battery system. and rural EV-charging stations in developed countries Sourcing aluminium is quite a diversified process like the US and Australia. New technologies such as compared to lithium, and the EU does not see it as a critical Azelio’s long duration storage are not only economically raw material – meaning that production is secure from viable alternatives for all the mentioned applications, but supply chain disruptions. In addition to this point, Azelio the technologies can also help to break the reliance on and Stena Aluminium, a part of Swedish-based Stena vulnerable supply chains of critical raw materials and offer Metall Group, are planning to enter into a long-term global a more diversified and sustainable future. collaboration that aims to fill Azelio’s energy storage units


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Jeff Damron, Wärtsilä Energy Storage and Optimisation, USA, discusses the role of energy storage in relation to the UK energy market and the national grid.


rid software acts as a modern-day map, helping to chart and navigate today’s energy grids – thus software engineers are tasked with carefully delineating how each region’s energy markets operate. However, looking more closely at energy markets makes clear how unique each market is – each defined by different topography, resources, and histories. The UK proves to be one of the most complex markets. Its design presents both an island story and an energy trading story, and underscores the value of locational energy, contracted revenues, energy trading, and energy arbitrage. With a population of 67 million, the UK generated 26% of its electricity in 2019 from solar and wind.1 This is compared with the global average of 9% of electricity generated from solar and wind.2 The UK is crossing impressive renewable thresholds and aims to continue with a goal to get to net-zero emissions by 2050 as part of its green industrial revolution plan.³ These clean energy accomplishments are made possible by the region’s ability to leverage new energy markets and activate flexible generation for customised support. Value streams flow from local grid needs, so understanding how and why the UK energy markets work helps better inform and design flexible power to provide grid support.

Islands are all about locational value While energy can trade to and from the UK and European markets, the UK is inherently limited by the

size of the transmission infrastructure to supply that power; therefore, congestion defines the UK market, similar to other island grids such as Australia and Texas, US.4 With an islanded grid, the locational value of energy is important to manage congestion and keep costs low. Therefore, for some grid services in the UK, a power plant must be in the UK to provide them. These UK-centric, locational services for batteries are driven by physics; for example, with frequency response, batteries measure the frequency of the grid, and when the frequency dips below a threshold, the battery quickly provides power to stabilise the grid. Wärtsilä’s energy storage project in Scotland provides spinning reserve capacity, which saves fuel and helps integrate more wind energy. Wärtsilä’s projects in the UK with Pivot Power provide strong locational value. Firstly, the Pivot Power projects provide retail power to end users. Acting as an infrastructure and capacity supplier to electric vehicle charging (EV), two 50 MW / 50 MWh systems provide essential capacity for rapid EV charging hubs. By providing the infrastructure to accommodate projected growth in EVs throughout the UK, the projects are supporting the grid by helping prevent system peaks and minimising strain on transmission and distribution infrastructure. It offers the project owner a contracted revenue stream from the EV charging customers. Wärtsilä’s GridSolv Max systems’ modular structure is helpful in locating storage closer to service demand in city centres where space may be limited. The Pivot Power projects also offer grid-balancing services to ensure the reliability of electricity generation


and supply across the UK. Wärtsilä’s solutions optimise a fleet of assets for best results and can be dynamically adjusted according to the demands of the markets across multiple revenue streams. They deliver frequency response, electricity market trading, reactive power, and EV charging services.

Trading as a currency The UK energy market has a strong culture of energy commerce, which is reinforced by the many different types of available energy markets. The UK maintains a day-ahead market and a real-time market. Additionally, EU countries can sell power to each other, which opens up many cross-border trading opportunities. The EU is made up of strong supply and demand markets with large renewables adoption and closely-located and densely-populated city centres. UK regulation allows bilateral agreements – or power purchase agreements (PPAs) – that happen completely separate

from trading markets. Therefore, it is common to see batteries dedicate a certain percentage of their energy to performing one grid service and another percentage to other services. A battery could fulfil a PPA obligation during part of the day, sell energy to France on a wholesale market during another part of the day, and provide frequency response to the UK grid at night. The UK also has a culture of innovation with competitions for new smart grid technologies and solutions, and grid operators are constantly developing new markets.5 To help account for the diminishing energy demand during the initial stages of the pandemic, the UK market implemented a new market called Optional Downward Flexibility Management (ODFM).6 There are also other recently created markets such as Firm Frequency Response. The large amount of opportunities in trading, however, can create a run on the market; therefore, the UK does face integration challenges as countries in the region see surging renewables output.7 At one point at the start of the pandemic, Germany paid approximately £800 000/h to export 10.5 GW of electricity.8 During diminishing demand from COVID-19, the UK paid a nuclear power station approximately £73 million to halve its output over the initial lockdown.8 These scenarios make energy arbitrage compelling. Energy arbitrage is when energy is purchased off-peak at low cost and then sold during periods of high prices. It is a valuable revenue stream for energy storage and flexible resources in active and engaged energy markets such as in the UK and Europe. Wärtsilä’s project in Cremzow, Germany, delivers frequency regulation and energy arbitrage for other markets in the region.

Active participation

Figure 1. Pivot Power and Wärtsilä have installed 100 MW of transmission-connected energy storage alongside high-volume power connections that will provide essential capacity for rapid EV charging. Project site in Kent, UK, pictured.

Value streams and revenue stacking in grid storage includes the whole set of customised revenue opportunities that independent power producers can offer as a project owner or operator.9 Value streams are critical to driving returns and value creation and are established through offtake agreements, regulatory conditions, and merchant markets. Digital platforms will play a critical role in enabling the growth in renewables by connecting energy assets to energy markets and helping open and unlock these value streams. Software brings into the equation the market access and trading capability, while also providing a flexible power plant more levers with which to play. Optimisation of assets extends beyond market trading to include managing and operating them to maximise economic return, such as operating under a specific energy scenario, and a stable energy supply. With more customised software that understands market dynamics and leverages assets to their full extent, more active participation and bidding by distributed energy resources will be the new standard.

References 1. Carbon Brief, ‘Analysis: UK renewables generate more electricity than fossil fuels for first time’, 2. 3. 4. 5.

Figure 2. Smart technologies and flexibility for the growing renewable energy infrastructure market are accelerating the UK’s energy transition. Energy storage site in Cowley, UK, pictured.


6. 7. 8. 9.

(October 2019). IEA, ‘Global Energy Review 2020’, (April 2020). UK Government, ‘New plans to make UK world leader in green energy’, (October 2020). The Texas Tribune, ‘Texplainer: Why does Texas have its own power grid?’, (February 2011). JENKINS, N., LONG, C., WU, J., ‘An Overview of the Smart Grid in Great Britain’, Engineering, Vol. 1, No.4, (December 2015). Energy Storage News, ‘UK industry says more energy storage is needed, as COVID-19 offers glimpse of low carbon future’, (June 2020). Greentech Media, ‘UK Struggles With Sagging Power Demand and Surging Renewables’, (June 2020). Forbes, ‘Ditch Nuclear And Save $860 Million With Grid Flexibility, UK Told’, (November 2020). NREL, ‘Grid-Scale Battery Storage’, (September 2019).

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Securing a sustainable future energy system through strategy, collaboration and innovation The Citizens Energy Congress, taking place virtually 15–16 June 2021, will bring together a broad spectrum of energy industry professionals, policy makers, investors, and civil society. Together, these groups will challenge the concepts and constraints of the existing energy models and foster consensus-driven foundations for a low carbon energy system. Join us as we help reset the energy system.

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Rob Graham, CPCS, Canada, details the designs and plans for Sub-Saharan Africa’s largest solar and battery storage procurement programme, based in Mozambique.


ozambique’s generation potential of 187 GW is greater than Africa’s entire electricity production. It is virtually Southern Africa’s power generator. However, despite being a net exporter of power, only 29% of Mozambique’s population has access to electricity. This is because the country and the electricity utility lack the capital to invest in the transmission and distribution infrastructure needed to effectively deliver power to all of the population. As a rapidly developing country, Mozambique has committed to achieve universal access to electricity by 2030. This is where the Global Energy Transfer Feed-in Tariff (GET FiT) programme comes into play. Developed by the German development bank KfW, GET FiT provides tools to help emerging economies develop small scale

renewable energy projects. Provisions such as technical and funding assistance and risk mitigation make projects part of this programme attractive to investors. After successful implementation in Uganda, and with a second ongoing programme in Zambia, Mozambique is next to benefit from GET FiT. Through GET FiT, Mozambique has realised that achieving universal access to electricity will likely require renewable energy, battery storage, and decentralised solutions.

How to make the solution fit Making GET FiT work in the Mozambican context is easier said than done. CPCS, a global management consulting firm in the infrastructure sector, brought the right combination of technical, financial, and public-private partnership knowledge to develop an innovative solution for the country. “GET FiT is a toolbox of support options,” says Robert Graham, CPCS’s Managing Director, Infrastructure Development Advisory. “Our role was to craft a plan to best adapt these tools to Mozambique’s unique needs and context and achieve stated objectives.” Doing so requires deep knowledge of the country’s economic, financial, and political realities. Equally important



is the technical aspect of the programme. While GET FiT promotes renewable energy projects, it does not specify which technologies to use and how to adapt the tools to the local context. The challenge, then, was to determine the support tools as well as the renewable energy technology that best addresses energy needs in Mozambique.

Bringing solar and battery into the mix CPCS experts concluded that combining solar power and large scale batteries was the best way to energise Mozambican cities and villages. This was not a routine assessment, because pairing solar power with battery procurement of such a scale had never been achieved in Africa, however CPCS felt confident breaking the mould, for many reasons. First, this combined solution is financially sound, as the price of solar has plummeted over the past decade. In Africa, solar can be as cheap as US$0.03/kWh. Compared to other renewable energy sources such as hydro and wind, solar tends to be the economic choice. The same goes for the price of battery storage. Similar to what happened to solar in the 2010s, batteries will likely become much more affordable in the 2020s. Low costs mean that financial donors and investors are likely to be more interested in backing renewable projects in Mozambique. Second, solar power is quicker to deploy than other sources of renewable energy. “Having a solar power system running in three months is possible,” says Robert. “In contrast, large hydro projects can take decades. Even wind turbines can require up to 18 months of data collection before moving to the development stage.” Third, paring solar and battery is flexible. Solar power systems can be installed anywhere with good sunlight, and batteries can be placed right next to demand centres. Other renewable energy sources are more limited in terms of placement.

In short, the solar and battery combination addresses Mozambique’s main energy objective, which is to improve access to electricity as quickly as possible.

A complete solution for a growing economy Coupling solar with battery storage not only addresses Mozambique’s energy needs but also meets infrastructure challenges in the power sector. Mozambique has always had difficulties moving electricity from power stations to people’s homes; the country’s power stations tend to be far from cities and villages. As such, Mozambique had to build lengthy transmission lines to connect these stations with population clusters. Overloaded or inadequate long transmission lines mean more power outages. Due to the fact Mozambique lacks access to sufficient capital to invest in adequate transmission and distribution infrastructure, abundant power generation has not translated into reliable electricity access for Mozambicans. More traditional power generation projects on their own are not the solution to electricity access goals. This is where the flexibility of solar power systems and batteries kicks in. They can be placed right next to cities with unreliable power. This way, these cities can bypass their reliance on long, overloaded, or unreliable transmission lines. Battery storage technology also ensures plenty of energy in the afterhours, alleviating the traditional inability of solar power systems to provide round the clock solutions. Solar power systems themselves do nothing to address peak electricity demand hours in Mozambique, which are between 6 pm and 10 pm. Overall, the innovative solar and battery solution resolves Mozambique’s power infrastructure challenges in three ways: F Reduces reliance on expensive transmission lines.

F Provides power to cities that need it the most. F Minimises the frequency of outages. In the near future, every population centre in Mozambique, no matter how remote, will have access to electricity at any time of the day.

Innovation on the ground

Figure 1. Targeted grid stabilisation and support with Global Energy Transfer Feed-in Tariff (GET FiT) projects.


Of course, using batteries to complement solar power systems is not new. “The innovation lies in how CPCS applied this solution in a way consistent with Mozambique’s regulatory, legal and financial realities, and how CPCS has attracted private capital to pay for these projects,” argues Robert. In fact, battery procurement was not even part of the original GET FiT toolbox. Before CPCS set foot in Mozambique, no framework detailed how to fit battery storage into the country’s regulatory, legal, and financial context. Neither has it been part of the GET FiT toolbox. Predictably, investors and financial donors were cautious to fund large battery programmes.

Figure 2. The traditional strategy to address energy constraints, which relies on transmission lines.

Figure 3. CPCS’s solution: battery storage near demand centres can alleviate transmission constraints.

They also downplayed the economic competitiveness of this solution. Hence, buy-in was scarce. Therefore, the brunt of CPCS’s work in Mozambique was to show stakeholders that the union of battery storage and solar is technically and financially feasible with the right programme design. Mozambique will soon launch the largest solar-storage programme ever conceived in Sub-Saharan Africa, as imagined and designed by CPCS.

Following the roadmap Mozambique intends to commit to the procurement of renewable energy projects in three rounds: F The first is acquiring solar generation systems and battery storage for areas in the greatest need of energy. CPCS expects an additional energy production and transmission of 60 MW.

F Traditional small hydro projects will be developed, providing a relief of 40 - 60 MW.

F Building on the success of the first round, a third potential round was designed to use solar and battery procurements to target even smaller and more remote sites, strengthening and extending the electric grid in Mozambique. “All things considered, we expect that GET FiT will improve the reliability of energy access for over a million Mozambicans currently suffering from unreliable grid power,” opines Robert.

Flash in the pan or sustainable solution? While Mozambique is the first benefactor of a large scale, comprehensive, solar plus storage solution in Africa, it is unlikely to be the last.

Challenges in replicating this project on the continent certainly abound, but they are primarily commercial rather than technical. Utility-scale battery services are still somewhat foreign in Africa, and the market for the services battery technologies provide is generally not yet developed. For example, ancillary services, an important market for battery technologies, are largely absent in Africa. Other commercial frameworks are needed to develop commercially viable battery projects in Africa. “The workaround lies in bundling batteries with existing market services in the form of a comprehensive power purchase agreement,” says Robert. “As our project in Mozambique has demonstrated, batteries can be integrated into the existing market framework by coupling with intermittent energy in PPAs.” The logic is that cheap power generation can subsidise the cost of the more expensive battery. This allows Africans to benefit from the best of both worlds: reliable power made possible by battery technology and affordable prices thanks to this contractual formula. Showing decision makers the additional benefits battery services provide to the grid, and convincing utilities of the value for money in these projects, will be key in replicating these projects across the continent. It is hoped that CPCS’s programme design in Mozambique will provide a replicable model to apply these exciting new technologies sustainably and viably throughout Sub-Saharan Africa. By doing so, this will allow citizens to benefit from access to clean, affordable, and reliable power without dependence on foreign energy imports or expensive traditional solutions to do so.



Tim Bruewer, Energy & Environmental Technologies at Watlow Electric Manufacturing Company, USA, discusses how molten salt heat management in solar thermal power plants is essential if freezing and leakage are to be avoided.



he demand for environmentally friendly and low carbon dioxide forms of energy generation has been increasing in Europe since the Green Deal was presented by the EU Commission in 2019, defining the climate neutrality of 26 member states up to the year 2050. Among other methods, the focus is on solar energy as an important representative in this area. Solar thermal power plants with concentrated solar power (CSP), in particular, often offer higher efficiency than photovoltaic (PV) systems. In order to compensate for the fluctuating production of electricity due to changing solar radiation, molten salt is often used for heat storage in such plants. However, if the temperature of the melt falls below a limit of approximately 228˚C, conventional salt compounds ‘freeze,’ which can block lines. On the other hand, if the temperature is too high, at approximately 585˚C, the salt dissolves and can no longer be used as a heat carrier. In addition, leakage can occur at



Figure 1. At a concentrated solar power (CSP) plant, sunlight is concentrated by mirrors onto a central tower, which absorbs the light and transfers the heat to a liquid energy source inside the tower.

the valves, reducing efficiency and increasing the likelihood that the melt will freeze. Therefore, extensive heat management is necessary to ensure that the temperature of the salt is stable. This can be achieved by a heating system consisting of electrical heating modules, sensors, and control units to stabilise the temperature of the molten salt at any point in the plant. In recent years, social and political movements have led to an increased focus on renewable forms of energy in the countries of the EU. According to data from the Energy Industries Council (EIC), more renewable energy projects are currently being planned and implemented in the EU area than in any other region in the world. The same applies to solar thermal generation with concentrated radiation (CSP) in particular, which, in contrast to now controversial wind energy, is characterised by particularly low environmental impact. The European Solar Thermal Electricity Association (ESTELA) puts the number of ongoing systems in Europe at 2385, with a further 588 systems being planned. Spain, for example, as the European pioneer of solar thermal energy, is working on new legislation that aims to launch new projects by 2024. However, in order to make this form of energy generation sustainable and at the same time economical, it is necessary to optimise efficiency on the one hand and minimise disruptive factors in operation on the other.

Molten salt as standard energy storage

Figure 2. An essential starting point for the efficient and cost-saving use of CSP systems is the heat carrier circulating in the system. Here, the medium often used is molten salts, which is superior to thermal oil because of its properties.

An essential starting point for the efficient and cost-saving use of CSP systems is the heat carrier circulating in the system. In the example of a CSP plant used here, sunlight is concentrated by mirrors onto a central tower, which absorbs the light and thus transfers the heat to a liquid energy source inside the tower. Here, the medium often used is molten salts, which are superior to thermal oil because of their properties: while the oil can be used only up to approximately 400˚C, molten salt is stable up to approximately 565˚C. By this means, steam can be generated at a higher temperature, which has a positive effect on the efficiency of the steam turbine and thus on the energy generated in the power generator. For this reason, chemical compounds such as NaNO3 and KNO3, which must first be preheated to a temperature of approximately 265˚C to be able to circulate, have proven themselves for some time. After the melt has been further heated by the solar heat in the central absorber to approximately 565˚C, the salt first flows into a storage tank where it is kept at a constant temperature. Depending on the system, it can remain there for several hours in order to provide heat or energy at night or during cloud cover. The plant then pumps the salt to a steam generator where the heat of the salt is used to produce steam from water. During this process, the salt cools down and is then fed back into the cycle. The resulting steam in turn operates a steam turbine and an electricity generator, which ultimately generates energy.

Freezing and leakage as primary risks in molten salt Figure 3. According to data from the Energy Industries Council (EIC), more renewable energy projects are currently being planned and implemented in the EU area than in any other region in the world.


However, in this complex process, which is characterised by very large differences in temperature, difficulties arise that can affect both the efficiency and the condition of the system. As the melt makes its way back to the central tower from the steam

Figure 4. CSP power plant in Tonopah, Nevada, US.

generator, there is a risk that the temperature of the salt will fall below a specific limit of approximately 228˚C, and the salt will solidify (known as freezing). This presents a great risk for the plant, as the salt can clog pipes and consequently shut down the entire process. At the same time, a significant amount of energy is required to reliquefy the solidified salt. This results in a poor energy balance and endangers the profitability of the plant. A further risk is that leaks may occur at the valves in the pipes used. This in turn reduces the temperature of the melt, and the probability of freezing increases. The loss of salt also has a negative effect on the efficiency of the plant, and may lead to downtime if the valves need to be repaired. Excessive heating of the salt is also critical: if a temperature limit of approximately 585˚C, which varies depending on the molten salt, is exceeded, the salt dissolves and can no longer be used.

Temperature management ensures stable circulation of the molten salt To counter these problems, the temperature is constantly monitored and regulated by a heating system. This requires sensitive temperature sensors, which are installed in the storage tanks as well as in the inlet and outlet tanks of the central tower. For a constant temperature of the melt in the storage tanks, powerful heating elements are also required. This task is usually performed by six to eight immersion heating elements, which are mounted in an additional cladding tube, and each has a

length of approximately 5 m (16 ft). The materials used in the tanks must also be corrosion resistant and suitable for high temperatures. The austenitic iron-nickel-chromium Alloy 800 or the special steel SS347H, for example, are suitable for the shells of the heating elements. This means that temperatures up to 600˚C are no problem – the material is corrosion resistant and stable even at low temperatures. Alternatively, parts exposed to media may also be made of chrome-nickel stainless steel AISI 347H, which also tolerates high temperatures and is resistant to intergranular corrosion. However, comprehensive temperature management is required not only in the storage tanks: numerous temperature sensors and controllers must be installed in the absorbing tower also, to ensure a uniform flow of the melt. To ensure that the temperature remains constant there, all lines carrying medium are fitted with high-temperature, tubular heating elements, which are characterised by a particularly short heating time and are themselves heat resistant up to 982˚C – due to the use of Alloy 800 or special steel SS347H. At the same time, the temperature of the melt can be controlled with the aid of control technology in such a way that no locally limited cold zones occur. As an option, mineral-insulated cables can also be used to heat the lines. Overall, the heat management system ensures that the temperature is monitored without interruption, and thus the molten salt can be used without any costly downtimes or loss of efficiency.




idal energy is produced by the surge of ocean waters during the rise and fall of tides. Undersea currents are one of the oldest forms of power known to man and have been harnessed for their energy for millennia. By the 20th century, engineers had devised many methods to use tidal movement to generate electricity in areas where there is a significant tidal range, all of which used special generators. Now a band of pioneering ocean energy developers are busy working away in various locations around the world, to thrust tidal power firmly into the 21st century, and stimulate a global tidal and wave market estimated to be worth approximately €535 billion between 2010 and 2050, according to the UK’s Carbon Trust.

Predictable energy guided by the Moon Controlled by the orbit of the Moon, tidal power is non-polluting, reliable, and predictable. In fact, it lays claim to being the most predictable form of renewable energy in existence, with scientists plotting tidal movements decades in advance. It is increasingly being recognised as a highly valuable marine energy resource, while helping protect coastlines and waterways vital to the culture and economy of remote, coastal communities. Tides are created by the gravitational pull of the Sun, Moon, and the rotation of the Earth, with tidal bulges developing due to the Moon’s gravitational pull. These tidal bulges move as the Earth rotates and the Moon changes position relative to the Earth. The part of the Earth closer to the Moon is more strongly attracted than the part farther away, creating an elongation in both directions. Since the Earth rotates a full turn every day, the point on the Earth that is being pulled towards the Moon is constantly changing, altering the position of the tidal bulges. Since the Earth has continents that disrupt the even flow of water, a complex pattern emerges. In some places, the water stretches out more towards the Moon. In other places, tidal nodes occur where the water does not really deform at all. Strong tidal resources are often found in narrow passages. As coastlines approach each other, or as the seafloor shallows, the water is ‘pinched’ which increases water speed – like pressing a thumb onto a garden hose. Power goes up exponentially with speed and every time water speed doubles, power increases eight-fold.


Ralf Starzmann, Sustainable Marine, Germany, explains how a methodical ‘stage-wise’ approach is helping to deliver the world’s first floating tidal energy array.



Tidal pathfinder Sustainable Marine has steadily built a reputation as a pathfinder in the tidal energy world. The system it first pursued was technically advanced and sophisticated, involving a submerged platform which floated in the middle of the water column – named PLAT-O. However, several years later it decided to redirect operations in a new direction, after reimagining the simplest and most straight-forward concept to convert tidal power, involving a floating platform with turbines deployed in a similar way to outboard engines. It proved a seminal moment and was in part influenced by extensive exploration of tidal energy sites around the world. The company noted that an accessible, floating, modular device would be more practical for islands and coastal communities with the greatest tidal energy potential, while benefitting those in greatest need. This change in tack also triggered the development of PLAT-I (PLATform for Inshore energy), informed by years of innovation, rigorous field tests, and sub-component analysis. Sustainable Marine’s passion for ground-breaking innovation continues to this day, and just one of many innovations is demonstrated by a collaborative R&D project with SCHOTTEL Hydro and RWTH Aachen University’s Center for Wind Power Drives – which has gained international recognition for wind turbine drivetrain testing. The marine technology developer is using the facility to test a new drivetrain generator for its tidal turbine, experiencing the equivalent of five years’ ‘real-time’ exposure or ‘theoretical damage’ within a six-month period. This

Figure 1. The launch of PLAT-I 6.40 tidal power platform in Nova Scotia, Canada.

accelerated lifetime testing is expected to unearth invaluable data to direct optimisation. Meanwhile, a new purpose-built, in-house foil test-rig and drivetrain has been created to influence foil design methodology as part of a wider internal development programme. A big differentiator in Sustainable Marine’s approach with PLAT-I, compared to other tidal energy devices, is the accessibility of the floating system in situ, alongside the scale of its turbines. This combination brings a broad range of operational and maintenance benefits. The floating approach provides greater access, whereas the smaller scale turbines allow for cost-effective offshore interventions, for example an ability to exchange foils, drivetrains or entire turbines in the field with relative ease. This ultimately reduces potential maintenance and servicing costs, and addresses one of the key challenges which hampered earlier tidal energy developers. The company’s unique approach continues to provide a particularly compelling edge during early stage development, while the platform’s innovative design requires just 2 m of water for launching and towing. It also benefits from a turret style mooring system which enables it to align perfectly with the tide or the river flow.

The Bay of Fundy The last decade has brought a string of high-profile projects with leading researchers, universities, partners, and supply chain operators around the world, helping build expertise in tidal energy engineering, production, project development, and business operations. Following rigorous site evaluations and demonstration projects in Europe and the Far East, Sustainable Marine’s journey ultimately led to the Bay of Fundy, in Nova Scotia, Canada. The site lays claim to the most extreme tidal ranges in the world – with 115 billion t of water surging in and and out, twice a day – creating a resource from which approximately 7 GW of power could be extracted. It also offers an ideal location due to a world-class tidal energy support network, regulatory support, and framework policy. In February 2021, the bay became home to the company’s next-generation PLAT-I 6.40 tidal energy platform which is currently undergoing sea testing and commissioning in the Grand Passage, Canada, before engaging in commercial deployment at Fundy Ocean Research Centre for Energy (FORCE), with current speed as fast as 4.5 m/s.

Benefits of a stage-wise approach

Figure 2. Innovative, multi-turbine design to be used to build 9 MW Pempa’q project in the Bay of Fundy, Canada.


This current project is the result a gradual and carefully orchestrated step-by-step process, with prototypes being tested in increasingly challenging environments over many years. This has maximised learning opportunities and provided necessary time to fine-tune technology, not only to withstand greater natural forces but also to ensure proven power output. Sustainable Marine initially launched its first basic single turbine prototype in collaboration with SCHOTTEL Hydro in 2012. Early stage testing saw deployments across various other sites in the UK, Indonesia, and Singapore, before more intensive programmes to advance the PLAT-I concept in Connel, Scotland, and in Nova Scotia, Canada, in recent years. This sustained effort has led to the creation of the nextgeneration 420 kW PLAT-I 6.40 model which produces 50% more

power than its predecessor. Vital information has been gleaned at each small stage of the decade-long journey, translating to constant modifications and improvements, driving greater efficiency, reliability, and power generation. Sustainable Marine’s model of steady, incremental growth combined with large volumes of time spent on the platform have helped shaped the firm and will further influence the future architecture of the firm’s third platform, currently on the drawing board.

Grid connection Following this year’s deployment, the scene is now set for PLAT-I 6.40 to play a central role in the forthcoming Pempa’q Project – the world’s first floating tidal array. The platform is being supplied to project entity Spicer Marine Energy, which has signed a design build and operate (DBO) agreement with Reconcept GmbH, on behalf of its RE13 Meeresenergie investment fund. The initiative is receiving support from the Canadian Government with a CAN$28.5 million investment – one of the nation’s largest-ever investments in tidal energy, with an overall objective to light up Nova Scotia’s grid delivering power to homes, vehicles, and businesses. It is further expected to reduce greenhouse gas emissions by 17 000 tpy of carbon dioxide and create new jobs in Nova Scotia. The Minas Basin section of the Bay of Fundy, where the Pempa’q Project will be situated, experiences highly aggressive tides, leading Sustainable Marine to conduct initial testing and development in the Grand Passage. This is another important element of the stage-wise approach, carrying out thorough preparation before positioning at FORCE for the commercial element of the project. The PLAT-I 6.40 platform will eventually form an array delivering up to 9 MW of electricity, following a gradual modular pattern, building in stages and confidence.

Growing political will and future targets In broad terms, the path ahead for tidal energy is very positive. According to Marine Renewables Canada, the North American nation has an estimated tidal energy potential of 35 700 MW alone, which is enough clean power to displace over 113 million t of carbon dioxide – equal to removing over 24 million cars from the road. The Minas Passage area of the Bay of Fundy has an estimated energy potential to roughly power 2 million homes – or all of Atlantic Canada. The territory is fast emerging as a global leader in tidal energy, with strong resource areas close to existing grid infrastructure and supportive marine renewable energy legislation that includes market incentives in the form of a feed-in tariff. Across the Atlantic, the European Commission envisions a significant role for emerging ocean technologies in its new Offshore Renewable Energy Strategy. Meanwhile, Ocean Energy Europe (OEE) – the largest network of ocean energy professionals in the world, which represents the interests of more than 120 organisations – is calling on the European Commission to include an ambitious deployment target of 100 MW by 2025 for ocean energy in the strategy. The network’s ‘2030 Ocean Energy Vision’ report illustrated that energy costs will reduce and supply chains will grow, as more ocean energy is deployed. It is now calling for a supportive

Figure 3. Construction of the new tidal platform in Meteghan, Nova Scotia, Canada, November 2020.

Figure 4. PLAT-I 6.40 is equipped with six SIT 250 instream turbines rated at 70 kW for a total of 420 kW.

policy framework including an ‘Ocean Energy Alliance’ of European and national authorities who provide accessible revenue support plus supportive permitting frameworks for demonstration projects. It further calls for continued European level support for research and innovation actions – to further progress the technology, while developing an ‘Insurance and Guarantee Fund’ to reduce financing costs and attract commercial insurers into market.

The next decade The next decade presents a perfect opportunity to unlock the promise of tidal and ‘run of river’ power and prove the value of next-generation ocean energy systems, through utility scale and off-grid applications. National leaders are providing a clear signal to both the sector and investors, helping leverage more private investment, thereby increasing the volume of energy-generating devices in the water. This will propel the industry into the mainstream. The story of the offshore wind sector shows how strong, supportive policies directly increase deployments, which in turn brings down costs. As more tidal energy capacity is installed, economies of scale and accelerated learning will also bring down costs. Revenue support is also needed at a national level to give developers and investors greater certainty and to leverage private financing. This public-private financing mix, which mature renewable technologies have enjoyed for decades, is an ideal approach to enable developers of today’s emerging ocean technology to successfully reach commercialisation.



Keith Murray, QED Naval, UK, puts forward the case for immediate support and investment in the UK tidal sector as the government looks to achieve net zero targets and move the nation towards a more sustainable energy mix.

Figure 1. QED’s partnership with Islay Energy Trust looks to develop submersible turbines in true partnership with the environment and community.


he global population is living in very different, rapidly changing times. More than ever, there is a strong focus on the environment – reducing carbon footprints, cutting out fossil fuels, getting to net zero and a green economy. The UK’s energy sector is still dominated by fossil fuels but retiring nuclear power stations and a planned coal phase-out could leave the UK facing a huge electricity supply gap by 2025. Renewables are starting to make a real difference; however, when the sun does not shine, or the wind does not blow, the UK is still reliant on burning fossil fuels and has been left with big gaps in its national grid, which require payment of up to £4000/MWh in balancing costs. Consequently, a predictable, reliable, energy mix is urgently needed. Renewables have made a difference but the UK is far from being on track in meeting its climate goals. The solutions, innovative technology, clever financing models, and an ever increasing momentum all exist, thus there is every reason to be optimistic as renewable energy becomes so much more affordable. This is evidenced by significant developments in solar and wind, with costs decreasing 89% and 70% respectively since 2010. Electricity is now the cheapest ever. The world is at a turning point. Countries representing 65% of the world’s carbon dioxide emissions (70% of the global economy) are committed to net zero targets and the US seeks to join the Paris Agreement. Sadly however, over 50% of funding is expected to be directed to fossil fuels. More investment directed at clean energy is needed to help the population’s health, create jobs, and cope with the increasing demand for electricity. This will be even more pressing as the population grows and fossil fuels are replaced with sustainable electric and storage



solutions, with transport and heating requiring the greatest priority. Governments need to focus on targeted action now, financing renewable initiatives and scaling them up to accelerate this. Energy has been obtained from water for thousands of years. The seas and rivers have a very valuable part to play in our daily lives, as most of the UK population and industry is located around them. Tidal energy is renewable, 100% predictable, and abundant. The UK has approximately 50%

of Europe’s tidal energy resource and, with 30 GW potential, a predicted gross value added (GVA) of £1.4 billion by 2030. Current technology is already capable of delivering more than 6 GW from 30 key tidal sites, approximately 11% of the UK’s electricity supply. Many of its tidal stream companies demonstrate high technology readiness levels, and with sites available, it is time for action. This is a great opportunity to kickstart and embed an entire sector in the UK, along with its supply chain, and drive the government’s renewables recovery agenda and export targets.

Funding for UK tidal

Figure 2. QED’s submersible Subhub on the surface with turbines.

Figure 3. QED’s Subhub undertaking tank testing prior to site deployment.

Figure 4. QED’s self-deploying abilities can reduce operations and shipping costs (60%), as well as increase turbine yields (48%).


The UK Government is currently looking at kickstarting the tidal sector in its next AR4 round of funding. Still in its infancy, tidal awaits its turn and urgently needs a better funding and R&D framework. Wind, solar, and energy from waste have guided the way, showing the issues and lessons to be learned. The government has been here before, has all the tools at its disposal, and is capable of incentivising a sector. The government needs to balance the equation and ensure that the sector is: well and fairly represented; incentivises invention; prevents auctions (which favour the larger, well-funded, and more established); avoids stifling smaller, developing technologies; ensures many affordable sites (rather than only a few); drives long-term thinking; and prevents developer greed (i.e. site grabbing, holding, and flipping for profit). Decisions need to be made quickly however to enable tidal to gear up and cash flow all this, or it will be lost forever. The government has a variety of tried and tested tools to kickstart the tidal sector for the long-term including: feed-in tariffs (FiTs), renewable obligation certificates (ROCs), contracts for difference (CfDs), innovation power purchase agreements (IPPAs), etc. It can also employ mechanisms such as grants (i.e. Innovate UK) and devolve powers to assist target specific areas. Directly assisting tidal energy companies by removing EIS tax restrictions on marine energy generation would certainly help get investment into the sector. In driving change, however, sometimes the direct approach is best. The introduction of a ‘carbon tax’ at source would drive heavy users of fossil fuels and polluters to quickly adopt such technologies and get over any apathy for change. This would be a direct route for market led solutions, encourage partnerships, strategic joint ventures (JVs) and industry development, as well as centres of excellence. Such a tough, direct approach would however require vision, leadership, and a shift in paradigm. Other sectors have been here before, but sadly all expertise, manufacturing, and gross development value (GDV) vanished abroad. With Edinburgh, Scotland, hosting Cleantech Forum Europe and Glasgow, Scotland, hosting COP26, the UK, as a great maritime nation, has an opportunity to showcase its natural resource, put in place policy and sector strategy, and deliver growth, a predictable energy mix, and a route to net zero. Representing the wave and tidal stream sector, the Marine Energy Council has been raising these issues with the government and helping advise on its next funding round, AR4. Working with BEIS and the Energy Minister, it seeks

policy support via CfD reform and the introduction of an IPPA. It has suggested driving a CfD dedicated capacity of 100 MW for tidal in AR4, with an administrative strike price of £250/MWh and more frequent auctions. Such policy support could enable a realistic deployment target of 4 GW in the UK by the end of the 2030s, supporting the UK’s 2050 net-zero obligation. It will embed UK supply chains, support the UK Government’s ‘levelling up’ agenda, and deliver significant export opportunity. With ongoing uncertainty and lack of clear policy causing a lack of confidence in investment, the industry simply struggles to plan ahead. It does not know what things will look like, or when they will come into force, so is unable to finance and cashflow any upfront investment. As in life, development and investment in the next generation is needed to show young people a future and let older generations move on. Innovators such as the tidal sector need to be encouraged and helped to grow by giving them a clear path with funding.

Technology in action QED Naval, established in 2008, with a strong background in naval architecture developing Ministry of Defence (MOD), defence, submarine, and propulsion technology, is a remarkable story and example to the UK Government as it seeks to scale. Its founder, Jeremy Smith, and the integrated project team he created around him, has designed, developed, and tested a highly disruptive, patented, selfdeploying marine tidal turbine foundation system which is

able to significantly reduce the costs of deployment and maintenance and improve yields. Having been tested at sea for over two years, this self-deploying Subhub has evidenced over 60% saving on costs by eliminating the reliance on costly marine operations and shipping. Through its patented design it has shown yield and revenue improvement to turbines of up to 48%. QED’s journey and impressive growth to date is particularly interesting. As a small start-up company in the energy sector with plans to be at utility scale, it has progressed from developing its Subhub, grown seismically in the last 12 months, and is now positioning itself carefully for a global market. In January 2020, the company acquired the renowned Tocardo tidal turbines – with their much respected and well-tested technology – in a JV with Hydrowing. This has increased QED’s resource, capabilities, and helped it obtain an EU base. The company followed this up by announcing its first large project, €3.5 million funding, and a place on Interreg’s €46 million showcase TIGER tidal project. 2021 has been as busy, with Tocardo acquiring the Netherlands’ iconic Oosterschelde (OTP) tidal dam project and saw Macquarie Group give great accolade and showcase it as a scalable energy solution at the Climate Adaption Summit 2021. Tocardo’s OTP dam presents a clear ability to deliver resilient infrastructure and climate adaptation solutions globally, capable of helping the over 400 global tidal deltas at risk of flooding. With its tried and tested Subhub and Tocardo turbines that have been in operation for over 10 years, QED is

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Figure 5. The Oosterschelde (OTP) dam project with Tocardo’s turbines.

Figure 6. Turbine installation in OTP dam.

Figure 7. Tocardo’s turbines – a QED joint venture with Hydrowing.

ready to deploy. Through the EU Interreg TIGER project and in partnership with ORE Catapult, it is deploying its 300 kW community scale unit (targeted at remote, island communities and diesel replacement) on the south coast of the UK and building its industrial scale 1.25 MW unit. This will deliver much data and learning to the sector. With some support funding, CfD mechanisms (taking up to seven years to be realised), upfront R&D projects, and site costs are difficult to fund. QED views long-term, strategic partnerships as key to its future and is targeting island and community schemes initially as it works with Scottish and


Welsh Governments to deploy its technology. Investors remain unclear on the route to market and revenue support, and as a result tidal projects are forced to compete with mature technologies such as offshore wind. With investors not prepared to get involved in small projects (<5 MW) and competitive finance only available on larger projects (>10 MW), it is no wonder the sector has only been able to demonstrate 32 GWh of electricity to the UK grid. There is a real need for more confidence and a visible support mechanism to help scale tidal. So much of QED’s focus has been on cost reduction and design development to date. In line with the sector, QED anticipates costs largely under £80/MWh at scales of 1 GW by the 2030s. Recent deployment, research, and industry learning, at 15%, all point to cost reduction curves similar to that evidenced by wind. Reducing CAPEX, OPEX, and increasing yield through technology innovation, economies of scale and commercial structuring will all play their part. QED sees supply chain partnerships as key to this as it aligns itself to a US$67 billion market by 2030 (the International Energy Agency forecasts up to 337 GW by 2050). For every 300 MW of projected pipeline, QED has some £600 million of supply chain opportunity and GDV; yet getting the right partners, with the right resource, cultural fit, experience, as well as global capability, is not easy. In looking for synergies to sectors such as oil and gas and to the more mature renewables such as wind for learning, there is a wealth of experience, manufacturing capability and resource, but a considerable difference in approach. As the oil and gas market matures rapidly and gets somewhat tarnished, its attitude to margin, risk, and change is somewhat different to those from a renewables perspective and more recent learning curve, such as wind. There are significant renewables supply chain and partnering opportunities in tidal energy, but careful preferencing and matching is of vital importance. What price for a green recovery, energy security, UK supply chain, and grid resilience? Which energy source is best and where? The answer is – there is no one size fits all but we must do it for our future. A predictable energy mix is needed, and the country is at the start of a journey. Optimism is high but things could be better. Predictable tidal energy and storage needs to play its part, but the sector urgently needs to be given the support and confidence to grow. With so much natural resource and technology in place, ready to go, all that is needed is targeted support, funding, and confidence.

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Anne Knour, TRACTO, Germany, considers the current sustainable trenchless solutions for building wind power infrastructure.


ind power is one of the fastest-growing renewable energies and a has become a mainstay of the energy transition required to reach the world’s climate goals. Its usage is on the rise worldwide, in part because costs are falling, and in part because wind turbine capacity has increased over time. However, according to the International Energy Agency (IEA), COVID-19 measures led to onshore construction activity slowing down from February to April 2020, but project developers and equipment manufacturers adapted to the ‘new normal’ and accelerated construction activity from May onwards. For 2021, the IEA even forecasts a further acceleration of wind additions from 65 GW in 2019 to 68 GW, driven by delayed onshore projects becoming operational. Using so-called trenchless technologies for installing the required transport cables underground can make a significant contribution to catch up with these delays and to tap the wind power’s full potential in a profitable and ecologically sustainable way.

Sustainable trenchless technologies Considering that up to 80% of the costs for conventional open-trench pipe and cable installations fall on the civil engineering works, the cost saving potentials when applying the trenchless methods are easy to imagine. The various underground pipeline construction methods, which


Figure 1. A Grundodrill HDD rig establishing the pilot bore for installing new power lines to expand a wind farm.



are summarised under the technical term ‘NoDig technology’, allow for all types of pipelines to be installed quickly, gently, and cost-efficiently up to the connection at the user’s premises. The economic and ecological advantages of trenchless technology over open construction are clearly shown: F Valuable surfaces are protected, extensive excavation and re-instatement work is avoided.

F Low emissions of noise, CO2 and fine dust, as well as less consumption of natural capital.

F Short construction and set-up times, quick execution, and high adherence to time schedules.

F On-target and reliable installation methods, proven application.

F Maximum planning and technical security due to high regulation conformity.

F Lower direct and indirect costs compared to the opentrench method.

Figure 2. Installing new power lines to expand a wind farm.

The challenges with renewable energies in general, and wind power in particular, are mainly due to ever-growing capacity requirements. No matter if the wind power was generated onshore or offshore, it is often unavoidable to install new power cables. But quite often too, tedious discussions and disputes with nature preservation authorities or local residents who oppose new power poles in the landscape, delay the power being provided to where it should be as quickly as possible. This is where the trenchless technologies provide another advantage: with new overhead lines being omitted when using those minimally invasive underground installation methods, the acceptance of wind farms in the public can be increased in the longterm.

Figure 3. Schematic illustration of the horizontal directional drilling (HDD) method for the underground installation of power lines in wind farming.

Figure 4. Drawing to illustrate the underground connection of an offshore wind power sea cable onshore.


Maximum flexibility for network construction The supply of electricity requires a dense and flexible power network. Depending on the overall conditions and requirements, there are different trenchless methods available to build it in the most efficient and sustainable way. A distinction is made between non-steerable and steerable NoDig methods. Non-steerable bore devices, such as a soil displacement hammer, are usually applied over shorter distances, if the bore path is a straight line. This

is also the case for steel pipe installations with the ramming method, which can cross beneath roads and railway tracks over shorter distances, but can also supply an optimal solution to install power pipelines for underground cabling, e.g. construction of bore path passageways for wind energy. However, due to its flexibility, the trenchless method that is the most suitable for getting wind power from the turbine into the grid and to flexibly adapt its capacity, is the so-called horizontal directional drilling method (HDD). With the HDD method, a steerable HDD bore rig is applied to initially produce a pilot bore along any required bore path using a steerable bore head. The bore head is equipped with a sonde whose signals can be detected overground. Based on these signals, the pilot bore is monitored and steered accordingly by the operator. When pulling back the drill rods, the bore hole is upsized by means of an expanding head and the pipe(s) or cable(s) attached to it are pulled into the pilot bore path simultaneously. In this way, power lines can be installed along curvy paths underneath or parallel to roads, railway tracks, rivers, and buildings. As single pipes or bundles can be installed along flexibly plannable bore paths like this, the HDD method is suitable for use within complex innercity infrastructures as well as in rural areas and even nature conservation areas. In a nutshell, the trenchless HDD method is suitable for installing any power lines required in wind farming: F Underground installation of media pipes for cables from onshore and offshore turbines to the transformer station and from the transformer station to the power grid.

F Onshore connection of sea cables supplying wind power

Figure 5. Successful underground installation of a power host pipe through the mudflats of the North Sea to receive a new sea cable.

from offshore wind farms.

F Ground cabling of new transmission lines. F Sustainable, minimally invasive techniques applicable in inner-city and rural areas and even protected landscapes.

F Reduced space requirements for the necessary construction works.

F High economic efficiency for construction and expansion of the power grid.

F Safe application according to the latest technical standards and regulations. Some electricity utilities have already recognised the economic and ecological advantages of trenchless technology and are using it for power grid construction – for example ENERTRAG, a large energy supplier active all over Europe, is generating power from wind farms only. ENERTRAG came to rely on trenchless technology as part of the expansion of wind farms the company is operating in the Uckermarck region in eastern Germany. To connect three wind farms and their 13 new wind turbines to the nearest transformer station, protection pipes for three medium-voltage systems were installed over 90 m length, each underneath a motorway that was not allowed to be walked on. Using a steerable HDD rig,

Figure 6. ENERTRAG’s wind farm expansion required protection pipes to be installed underneath a major motorway.

this was achieved within several days at an installation speed of approximately 13 - 15 m/hr. Those responsible summarised this very eloquently: “Wind energy and trenchless construction go together perfectly. Construction time is massively reduced by the use of NoDig techniques and no least, the impact on the environment is also minimised.” Further information on underground pipeline construction and the innovative trenchless methods can be obtained from NoDig trade associations, specialised civil engineering companies, and the manufacturers of trenchless equipment.





ffshore wind has the potential to meet the world’s electricity demand 18 times over.1 It currently constitutes a miniscule fraction of the electricity mix but is pinpointed as a vital resource to make the future energy system sustainable without any emissions of CO2. In Europe, the official target for 2050 is 300 GW of offshore wind capacity.2 That quantity will be enough to supply approximately one-third of the electricity demand, and will make offshore wind a cornerstone of the energy system. To reach the target for offshore wind in Europe, approximately 10 GW of new capacity must be installed every year. As a comparison, in 2019 a total of 3.6 GW was installed, bringing the offshore wind capacity in Europe to a total of 22 GW. Thus, to reach the target requires a large increase in the annual installations, as well as significant efforts in research, industry, and policy. Three grand scientific challenges are depicted in a recent article in Science by a group of highly acclaimed wind energy experts.3 These are detailed next, in an amended format:

F Improved understanding of atmospheric and wind power plant flow physics. F Aero, structural, electrical, and offshore wind hydrodynamics of enlarged wind power plants.

F Systems science for integration of wind power plants into the future electricity grid. To be successful, the development must be sustainable with respect to nature and society; it must result in an affordable and reliable supply of energy; and it should contribute to creating jobs and export industry. The electrical infrastructure is a key enabler for large scale wind farm developments and could account for up to 50% of offshore wind total costs as wind farms move further from

John Olav Giæver Tande, SINTEF, and Magnus Korpås, Norwegian University of Science and Technology, Norway, discuss the challenges of offshore wind and how current research and development could unlock the industry’s potential.


shore.1 As a result, extensive R&D is required to find costeffective solutions for grid connection. This article discusses how offshore wind farms can be developed to provide an affordable and reliable supply of energy, using offshore wind in the North Sea as a case study.

Moving further from shore and into deep waters Presently, most offshore wind farms are located relatively close to shore and at shallow waters. However, shallow

Figure 1. Illustration of alternative substructures for bottom-fixed and floating wind turbines. Left to right: monopile, jacket, semi-submersible, and spar floater.

Figure 2. Illustration of floating wind turbines with subsea transformer.

Figure 3. Concept illustration of a future North Sea grid connecting large amounts of offshore wind to be a cornerstone of the energy system.


water sites are limited and often valuable for fishing, and areas close to the coast are typically preferred sailing routes. Thus, the trend is that new offshore wind farms are installed further from shore and in deeper waters – which calls for new solutions. The standard bottom-fixed monopile solution is not practical for deep water. The application of jacket structures or other bottom-fixed technologies is an option for intermediate water depths, but at water depths exceeding 60 m it is generally expected that floating solutions are required. There are only a few floating turbines installed globally. These include the Hywind concept that uses a spar floater and the WindFloat concept that applies a semisubmersible floater (Figure 1). These are designed to fit ‘any’ standard offshore wind turbine, whereas other concepts in development consider more radical solutions, such as floating structures combined with multi-rotor solutions or with vertical axis turbines. The main challenge is to develop the technology and industry so that floating wind can provide an affordable and cost-competitive supply of energy. Offshore bottom-fixed wind farms can be developed today to deliver energy at very competitive levels – for example, the 3.6 GW Dogger Bank wind farm will be built at approximately €45/MWh. Floating wind technology on the other hand is at a much earlier stage of development, with pilot installations of mere tens of megawatts in operation and costs in the range of €100 - €200/MWh. However, the potential for floating wind is huge. Approximately 80% of the global offshore wind potential is at locations with deep water.1 The expectation is that floating wind can become cost competitive with bottom-fixed wind farms. The target of the research centre NorthWind is to enable floating wind farms at a cost of €40 - €60/MWh by 2030. Its vision for 2050 is that floating wind will be a mainstream technology to provide large amounts of clean and affordable energy. Moving towards deep water does not only have implications for the substructure, but also for the grid connection that is composed of an internal collection grid, a substation, the transmission to shore, and connection to the main grid. The internal collection grid is essentially a system of submarine cables that connect the turbines to the substation. It should be carefully assessed to ensure an efficient and reliable design. This includes application of broadband models of the electrical system to accurately calculate switching transients and high frequency resonance phenomena.4 Alternative internal grid design with direct current (DC) collection systems have been proposed, though this is still a topic for research.5 As floating turbines will move in the water, the submarine cable for connecting the turbine must be able to withstand these movements and the forces of the sea. Such cables, commonly known as dynamic cables, have previously been developed for the oil and gas industry and are available for voltages up to 66 kV with a maximum load carrying capacity of approximately 90 MW. A research challenge is to identify new, less expensive design solutions that still offer the required strength, durability, and load carrying capacity.

The substation is conventionally installed at a platform, and in deep water this would need to be floating. However, it is possible to place the substation transformer on the seabed instead, thus removing the need for a platform (Figure 2). Subsea transformers are already developed for the oil and gas industry, but need to be adapted to fit for the wind industry. Also, wet-mate and dry-mate connectors need further development. This includes, among other things, testing new insulating materials in laboratory conditions. The substation transformer increases the voltage to the required level for the export cable, for example, 132 kV or 220 kV. Transmission by high-voltage alternating current (HVAC) is normally possible for distances up to 100 km. The limitation is due to the cable capacitance that causes a charging current which occupies the load carrying capacity of the cable. Application of reactive compensation and voltage control may help to stretch the limit for HVAC transmission, though at some point, high voltage direct current (HVDC) is the preferred option.6 This would require a HVDC converter station offshore and on land. Studies show that instead of connecting each wind farm with a separate cable to shore, it is economical to establish an offshore transmission grid that can connect many wind farms.7,8

purposes.16 In particular, an integrated North Sea grid should facilitate the utilisation of the regulated hydropower in the Nordic area for balancing. In the south of Norway alone, as much as 20 GW of additional power/pumping capacity could be revealed by expanding the existing hydropower system with new reversible pump stations between reservoirs.17 This would provide valuable balancing power for the 300 GW offshore wind power envisioned by the EU as well as onshore wind and solar power plants on the continent.18 A multinational, multi-terminal North Sea grid would require a very high degree of international co-operation with standardisation, market solutions, and regulation. A challenging issue is how to address the allocation of costs and benefits between different countries and actors which are affected by the offshore grid expansion. Several concepts, such as the Shapley Valley principle, have been identified as promising in theoretical studies, but these remain to be adapted into a practical setting for the multi-billion offshore grid investments that lie ahead.19 In the future, the offshore grid might be complemented with offshore charging stations for electric vessels. The future may also see wind farms located far offshore without any grid connection but producing hydrogen as fuel for zero-emission transport. The future holds an ocean of opportunities.

A vision of a future North Sea grid Grid integration of offshore wind farms is on the R&D roadmap for European transmission system operators (TSOs) and wind developers.9 Point-to-point connections present strong limitations for large offshore wind clusters. A multi-terminal offshore grid in the North Sea will offer many advantages, not only for offshore wind integration, but also to enhance power trading and balancing between the different countries. Although a multinational offshore grid is a promising concept, its planning and operation are technically challenging. Adverse grid/component interactions will have to be addressed in a multi-vendor context and wind farms will need to support the transmission system regulation with advanced ancillary services as grid forming capabilities.10,11 An optimisation framework should be established to co-ordinate these services and the power transfer according to grid needs, legal and market constraints, and energy carrier options.12,13,14 Recently, the TSO’s TenneT, Energinet and partners launched the North Sea Wind Power Hub Programme, where they envisage to develop offshore hubs – possibly artificial sand islands with up to 36 GW connection capacity each – integrating offshore wind farms, interconnectors, and possibly hydrogen infrastructure. Although still in the early phase, such offshore hubs have the potential to provide even more economic benefits, compared to traditional, radial grid topologies.15 Regardless of the technical solutions, it is a prerequisite that there are sound market solutions for offshore power generation and balancing needs. As the amount of North Sea wind power increases, there will be an increased need for the trade of energy and ancillary services across the neighbouring countries. Earlier studies have shown that there are significant economic benefits in optimising the allocation of offshore cable capacity daily for different

References 1. 2. 3. 4.




8. 9. 10. 11.

12. 13.







IEA, ‘Offshore Wind Outlook’, (2019). EU Commission Announcement, (2019), presscorner/detail/en/IP_20_2096 VEERS, P., et al., ‘Grand challenges in the science of wind energy’, Science Vol. 366, Issue 6464, 2019. GUSTAVSEN, B., BREDE, A.P., and TANDE, J.O.,‘Multivariate Analysis of Transformer Resonant Overvoltages in Power Stations’, IEEE Transactions on Power Delivery, (2011). GJERDE, S.S., OLSEN, P.K., LJØKELSØY, K., and UNDELAND, T.M., ‘Control and fault handling in a modular series-connected converter for a transformerless 100 kV lowweight offshore wind turbine’, IEEE Transactions on Industry Applications, (2014). GUSTAVSEN, B., and MO. O., ‘Variable Transmission Voltage for Loss Minimization in Long Offshore Wind Farm AC Export Cables’, IEEE Transactions on Power Delivery, (2016). KRISTIANSEN, M., SVENDSEN, H.G., KORPÅS, M., and FlLETEN, S.E., ‘Multistage grid investments incorporating uncertainty in offshore wind development’, Energy Procedia, Vol. 137, (2017), pp.468-476. EU-IEE Project OffshoreGrid, Final Report, (2011), projects/en/projects/offshoregrid. ENTSO-E Research, Development & Innovation Roadmap 2020-2030. BEERTEN, J., D’ARCO, S., and SUUL, J.A., ‘Identification and small-signal analysis of interaction modes in VSC MTDC systems’, IEEE Transactions on Power Delivery, (2015). D’ARCO, S., SUUL, J.A., and FOSSO, O.B., ‘A Virtual Synchronous Machine implementation for distributed control of power converters in SmartGrids’, Electric Power Systems Research, (2015). TRÖTSCHER, T., and KORPÅS, M., ‘A Framework to Determine Optimal Offshore Grid Structures for Wind Power Integration and Power Exchange, Wind Energy, (2011). KRISTIANSEN, M., MUÑOZ, F.D., OREN, S., and KORPÅS, M., ‘A mechanism for allocating benefits and costs from transmission interconnections under cooperation: a case study of the North Sea offshore grid’, The Energy Journal, (2018). BØDAL, E.F., MALLAPRAGADA, D., BOTTERUD, A., and KORPÅS, M., ‘Decarbonization Synergies from Joint Planning of Electricity and Hydrogen Production: A Texas Case Study’, International Journal of Hydrogen Energy, (2020). KRISTIANSEN, M., KORPÅS, M., and FARAHMAND, H., ‘Towards a fully integrated North Sea offshore grid: An engineering-economic assessment of a power link island’, WIREs Energy and Environment, (2018), FARAHMAND, H., AIGNER, T., DOORMAN, G., KORPÅS, M., and HUERTAS-HERNANDO, D., ‘Balancing Market Integration in the Northern European Continent: A 2030 Case Study’, IEEE Transactions Sustainable Energy, (2012). SOLVANG, E., HARBY, A., and KILLINGTVEIT, Å., ‘Increasing balance power capacity in Norwegian hydroelectric power stations’, SINTEF Energy Research, TR A7195, (2012), GRAABAK, I., KORPÅS, M., JAEHNERT, S., and M. BElLSNES ‘Balancing future variable wind and solar power production in Central-West Europe with Norwegian hydropower’, The Energy Journal, (2019). KRISTIANSEN, M., MUÑOZ, F., OREN S., and KORPÅS, M., ‘A Mechanism for Allocating Benefits and Costs from Transmission Interconnections under Cooperation: A Case Study of the North Sea Offshore Grid’, The Energy Journal, (2018).




here has been exponential growth in the offshore wind industry over the last few years and, despite changing political environments and a global pandemic, the industry shows no sign of slowing down. Research recently published by RenewableUK shows that the global pipeline of offshore wind energy projects soared by over 30% within the 12 months to July 2020, increasing from 122 GW to 159 GW. Leading the renewable energy transition is the UK, with almost 11 GW of installed offshore wind capacity – more than any other country in the world. Governmental climate goals are one of the main driving forces behind the skyrocketing demand, with the UK targeting 40 GW of offshore wind by 2030 and net-zero emissions by 2050. With the accelerated growth of the offshore wind market comes an increased requirement for the underpinning subsea cable infrastructure. The latest edition of Westwood’s ‘Subsea Cable Tracker H1’ report revealed that demand is forecast to grow by 17% annually, totalling 46 470 km over the period 2018 - 2022, representing a 71% growth compared to the 2013 - 2017 period. Couple this with the limited number of cable-lay vessels, burial equipment and trenchers currently available, and the urgent need for innovative, intelligent, and efficient technology becomes clear. As a provider of cable installation, trenching, burial, and repairs to the offshore energy industry, Global Offshore is acutely aware of the growing emphasis placed on technology, as well as the specialist skills required to ensure the demands of the market are met, for the long-term. “The challenges of laying and burying an increasing number of ever more sophisticated and critical power cables further offshore, often in difficult seabed conditions, at both floating offshore wind and fixed bottom sites, is a pressing issue that is driving technological innovation,” said Mike Daniel, Managing Director, Global Offshore.

Rob Lindsay, Global Offshore, UK, explains how the exponential growth of offshore wind is making way for innovation in subsea technologies.


Figure 1. Havila Jupiter and PLP240.


“As the demand for offshore wind rises, the emphasis is on reducing the associated costs – which has been a pivotal factor in the race for new technologies to make these cost efficiencies possible,” Mike explains. Other contributing factors for innovation are the ambitious decarbonisation and environmental objectives from major energy companies such as Ørsted, which is on track to be carbon neutral in energy generation and operations by 2025. These companies are targeting a carbon-neutral footprint by cutting their energy trading and supply chain emissions in half by 2032 and then down to netzero emissions by 2040, requiring their entire supply chain to reach net-zero emissions within the next two decades.

Ploughing the way for new technology Figure 2. Global Offshore’s PLP240 used for power cable burial and protection on the seabed.

Figure 3. PLP240 mobilising from the Havila Jupiter.

Mike, like the rest of the Global Offshore team, has extensive experience in both the oil and gas industry and offshore renewables. For more than 35 years, Mike has held a variety of positions in the offshore energy industry, and for the last two decades has been part of a variety of offshore wind projects including Hywind floating offshore wind farm, Kincardine floating offshore wind farm (the UK’s largest floating offshore wind farm once complete), Danish Kriegers Flak, DanTysk, and Pentland Firth. He has witnessed the significant increase in demand for offshore wind first-hand. A decade ago, the UK was reliant on fossil fuels, with approximately 40% of the UK’s electricity coming from coal. By 2019, that figure had dropped to approximately 2%. As part of the UK’s commitment to a green energy transition, the government aims to phase out coal altogether by 2024. Last year, the UK took a further step towards its green energy goal, with renewables generating a record 42% of the UK’s electricity in 2020, while fossil fuels accounted for 41% of electricity generation. Key to the growing reliance on wind power is the decreasing cost of renewable energy generation. The price of electricity from offshore wind has fallen by more than 66% since 2012, making it cheaper to build offshore wind farms than new fossil fuel power plants in north-western Europe.


With time and cost efficiencies for its clients in mind, coupled with the aim of reducing overall emissions, Global Offshore recently introduced the PLP240: a uniquely designed pre-lay plough engineered to reduce the operational risks of cable burial by reducing the time taken for this process, as well as enhancing and complementing the existing burial solutions available. Giving unrivalled capability to simultaneously prepare and plough cable routes and subsequently backfill them following installation, in order to adequately protect cable routes in the most difficult of seabed conditions, the 115 t pre-lay plough made its inaugural appearance at Vattenfall’s Danish Kriegers Flak offshore wind farm last year, followed soon after by use at the Kincardine floating wind farm project. Described as a step-change in trenching technology, on this project the PLP240 successfully completed two pre-cut campaigns totalling approximately 200 km, in some of the most challenging seabed conditions for burial. Clearing boulders of up to 1000 mm, the PLP240 completed 158 km of route clearance on the Danish Kriegers Flak site, over 72 different routes. Despite challenging seabed conditions, with boulder fields and heavy clay, the PLP240 achieved or exceeded target trench depths in over 99.5% of the total length ploughed, going over and above the project requirements and almost wholly derisking the cable burial. With a target share depth of 1.7 m across all routes, the majority of this work was completed in a single pass, attaining progress rates of 100 - 500 m/hr, in seabed types ranging from dense sands and very stiff, boulder clay through to gravelly, cobbly sands and low strength clay. Where jet lowering was required, progress rates of 350 - 450 m/hr were maintained, which is greater than those which could have been maintained for jet burial alone. Additionally, laying the cable within a trench has provided an element of protection and stabilisation of the cable. “The initial results of the PLP240 exceeded our expectations and, in the process, laid the groundwork for the introduction of other highly innovative, multi-purpose assets in the future. The success of the PLP240 means we can offer our customers a cost-effective solution whilst simultaneously removing the need for another asset to be mobilised and used for each part of the cable-laying process

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Figure 4. PLP240 recovery.

– in turn, saving valuable time and reducing greenhouse gas generating emissions,” Mike said. Sufficiently protecting the subsea cable is particularly important, as research shows more than 90% of all offshore wind farms have had at least one instance of cable damage. On average, inter-array network claims cost insurers between £1.1 million and £2.5 million per wind farm. Andy Lloyd, Director of Power Cables at Global Offshore, explains, “The figures are not unsurprising when you realise that on average, during operation, damage to the cable occurs once every 600 km, every year. Ultimately, damage to the cables can be extremely costly to repair and the impact this damage can have on the wind farm operations can be catastrophic.” He continues, “That is why it is so vital to reduce the risk of damages by getting the cable trenching and burial right during the initial installation phase. Additional care taken to protect assets from the beginning can reduce repair costs in the years that follow.” Andy leads Global Offshore’s Complete Cable Care offering, which provides cable maintenance and repair services to the offshore energy industry. Since he began his career at Global Marine Group over two decades ago, when he was Project Manager for the installation of the UK’s first offshore wind farm, Andy has worked on dozens of offshore wind projects – gaining the experience and expertise to truly appreciate the financial and operational impact of poor cable burial techniques.

Working in harmony

Figure 5. Havila Jupiter and PLP240 on Kincardine.


The PLP240 is not the only technology Global Offshore utilises for cable trenching – the company frequently uses its Q1400 remotely operated vehicles (ROVs), which have the capability to perform jet trenching in soils of up to 100 KPA and mechanical chain cutting of soils of up to 250 KPA. The PLP240 was designed to work seamlessly with the Q1400, whose skids sit perfectly in the spoil left behind by the PLP240’s initial route clearance pass. In a recent project, the team were able to complete a like-forlike comparison of the two systems working together against the Q1400 working alone, while performing the installation and burial of a cable parallel to one they installed and buried a few years previously. With the Q1400 alone, in hybrid mode, an overall depth of lowering of 1.0 m or greater was attained for 30% of a route containing stiff and overconsolidated, gravelly pebbly clays/till, dense sands, and underlying bedrock. The time taken from the commencement of lay to completion of burial was 18 days. On completion

Figure 6. Illustration of the PLP240, Global Offshore’s pre-lay plough.

of the second parallel cable a few years later, combining pre-cut trenching from the PLP240 with the Q1400 in jetting configuration, the overall depth of lowering was improved to >96% at, or greater than 1.0 m, in an overall time from start of lay to completion of jet burial of eight days. “Cutting the time taken by more than 50% and in the process, securing a lower risk burial, shows the very real benefits of our new technology. As the requirements for subsea cable works increase, it is thanks to assets like the PLP240 that we can keep up with demand and, in the process, render obsolete many traditional forms of boulder clearance and trenching,” Mike explains.

Ready for action Speed of mobilisation – which is growing increasingly important with the rising demand for services – as well as time efficiencies through the use of new assets, are significant factors in Global Offshore’s success. In the last 12 months alone, the company carried out 10 cable replacements under its Complete Cable Care offering, each requiring very short turnaround times. This is in addition to a range of installation, trenching, and burial projects carried out for customers within the offshore wind and oil and gas markets. At the core of Global Offshore’s short mobilisation times are the technological advancements of the company’s vessels and assets. Mike explains: “With recent upgrades and the acquisition of new vessels, our fleet is equipped to handle

the increased demand for innovative and more efficient ways of working. Our in-house team of engineers develop solutions which offer flexibility in our vessels and assets, making it quicker for us to switch modes. In the process, we are able to save valuable time and costs for our customers, by utilising one vessel for a project which traditionally could have required two or more vessels to complete. With better utilisation of vessels, we incur lower costs from vessels sitting idle, at the same time as reducing our impact on the environment with significantly reduced fuel burn time.”

Conclusion In 2020, Global Offshore introduced the Normand Clipper, a 127.5 m cable-laying vessel, to its fleet, and immediately carried out upgrades to create significant cost and time efficiencies for its clients. Upgrades included the addition of a 4000 t cable carousel, two 15 t cable tensioners, a 25 t quadrant deployment frame, and a fully integrated control system, enabling the company to lay cable at much higher speeds than traditional methods, while still maintaining high standards of safety and quality. For the Global Marine Group’s in-house engineering team, the challenge is finding a solution for clients and the wider industry’s requirements, without compromising on the quality of the end result. One thing is for certain, as the industry struggles to keep up with demand, there is an emergence of more technologies driven by the increased demand for overall project duration and cost savings.



Renate Lemke and Péter Sebö, HPF The Mineral Engineers, Germany, detail a recent laboratory investigation into coatings protection to improve the durability of offshore rotor blades.


he maintenance of existing wind turbines, but also the maintenance of newly installed wind power stations, is playing an increasingly important role. If damage occurs, the wind turbine must be shut down completely, in the worst case, and in some cases for several months. This can result in considerable costs for the operator of the plant, which can be very high if the rotor blades are completely lost. The rotor blades in particular are subject to a great deal of stress, because extreme environmental stresses – in particular, rain erosion – wear down the huge rotor blades of wind turbines. The rotor blades are elaborately coated with a multilayer coating system. With the help of high-performance fillers with specific surface treatment in the coating systems, the resistance of the rotor blades to rain erosion can be improved. HPF The Mineral Engineers, a division of Quarzwerke Group, creates unique system solutions by developing innovative and functional high-performance fillers and additives on a mineralogical and synthetic basis.

Introduction Wind energy has now advanced worldwide. In 2019, 500 offshore wind turbines in Europe with a total capacity




of 3620 MW were newly connected to the grid. This brings the total offshore wind energy capacity in Europe to approximately 5050 offshore wind turbines with a total capacity of approximately 22 000 MW at the end of 2019. The UK, with a total capacity of 10 000 MW, is far ahead of Germany with 7500 MW. This is followed by Denmark (approximately 1700 MW), Belgium (approximately 1550 MW), and the Netherlands (approximately 1120 MW). Rotor blades for wind turbines (WTG) are designed to survive 20 years of operation in the offshore sector without any impairment. They are exposed to a wide range of environmental influences, such as snow, rain, salty seawater, hail, heat, and UV radiation. Wind speeds of up to 500 km/h act on the blade tips. This area is therefore one of the greatest weak points of the rotor blade. The coating here is particularly strongly eroded and destroyed by rain erosion; the speed of impact and size of the raindrops play a decisive role. As a result, the aerodynamics on the blade surface change and the power output decreases. The basis of a rotor blade wing is a composite material consisting of bonded glass or carbon fibre mats, into which

Figure 1. Structure of coating system. Source: BASF.

Table 1. Characteristics of HPF fillers Filler

Grain shape

Grain size (μm) D50

Density (g/cm3)






Square edged




Thick tabular



Table 2. Characteristics of reference fillers Filler

Grain shape

Grain size (μm) D50

Density (g/cm3)

Synth. barium sulfate









epoxy resin is injected under vacuum. This is followed by a multi-stage coating as shown in Figure 1.1 The aim of the present investigation was to find out whether the use of special mineral high-performance fillers can contribute to the durability of such coating systems as well as the rotor blades. Rain erosion tests based on real conditions can be performed in a newly developed miniature simulator.

Used high-performance fillers

In numerous preliminary tests, various fillers were tested in the coating system. The fillers differed particularly in grain morphology and hardness. Among other things, plateletshaped and long-needled, as well as soft and hard fillers were used – some of which also differed in density. The most suitable high-performance fillers for the pore filler were concluded to be silica fine flours, wollastonite flours, and feldspar flours. These were modified with a surface coating that was adapted to the polymer system (Table 1). In order for silica to be used as a raw material, it must undergo complex washing, classifying, drying, and iron-free grinding processes. The production of silica fine flours with a defined grain size also requires separation processes. By combining grinding and classifying technology, silica powders with a grain size of up to 1 μm can be produced. A further refinement step is the customised surface modification with silanes or silane-based chemical compounds, tailored to the specific application. Wollastonite is a naturally occurring calcium silicate that forms from silicon dioxide and calcium carbonate at a temperature of approximately 450˚C. The structure of the individual wollastonite particles is on the one hand dependent on the geological formation, and on the other hand strongly determined by the selected processing technology. Depending on the selected technology, the particle shape is extremely influenced. The possible target products can have both a pronounced needle shape, i.e. high aspect ratio, and partially destroyed needles with a low aspect ratio (platelet). Due to the low influence on viscosity, the platelet wollastonite grade was used. Feldspar is a chemically resistant tectosilicate with a thick tabular grain morphology. With a participation of almost 60% by weight in the structure of Oil absorption Mohs Surface (g/100g) hardness treatment the earth’s crust accessible, feldspars are by far the most 26 4.5 Yes common mineral group. 27 7 Yes Correspondingly, often feldspars are involved in the 25 6 Yes structure of numerous rocks as a main and secondary component. The melting Oil absorption Mohs Surface temperature range is (g/100g) hardness treatment 1150˚C - 1250˚C. Feldspars have 11 3-4 a high degree of whiteness (Y >90) and are transparent in 32 1 many binder systems. There

are both potash and soda feldspars, which are separated, classified, and finely ground using complex processing technology.

Experimental procedure For the study, a coating structure consisting of a gelcoat, the pore filler, and the top coat was selected. All formulations contained polyaspartics-based binders. Polyaspartics have already proven their worth for rotor blade coatings and are characterised by low VOC content, among other things.2 They are fast curing and high layer thicknesses are achieved.3 To investigate the performance of the high-performance fillers, the reference fillers talc and synthetic barium sulfate (BaSO4) were replaced 1:1 in the starting formulation of the pore filler (Table 2) with the test candidates. Reference was the volume of the fillers. All preparations were mixed on a laboratory scale using a dispermat. For the gelcoat, a homogeneous mixture of binders and fillers was prepared by simple stirring at low speed. For the production of the top coat and pore filler, the fillers were added while stirring with subsequent dispersion into the liquid components. Further processing of the preparations was carried out after a maturing time of 24 hours. All coating preparations were applied to the glass fibre reinforced plastic (GRP) rods, 22 cm × 2.4 cm × 0.4 cm (L × W × D), using a brush. The following coating build-up was selected:

> > > >

Bonding primer: 1 - 2 μm. Gelcoat: approximately 250 μm. Pore filler: approximately 500 μm. Top coat: approximately 120 μm.

After curing for seven days at room temperature, the tests were performed.

Rain erosion test A new test method and a simulation chamber have been developed in order to quickly and realistically investigate rain erosion on rotor blades for wind turbines. The test method was intended to simulate – on a laboratory scale – the effect of impacting raindrops on a coated epoxy resin-based GRP test specimen rotating at high speed. For this purpose, the functional principle of a rotor blade was considered and transferred to a small scale. Figure 2 illustrates the following process. An electronically controlled and coolable centrifuge (1) was used as a simulation chamber to ensure a uniform speed of the test specimen at constant temperature. The rotor of the centrifuge was modified so that it served as a holder for the test rod (2). In addition, a watertight chamber (3) was built around the rotor to prevent the device from being damaged by splash water. A hole with a diameter of 4 mm was drilled at the outer edge of the centrifuge lid. An aluminium tube (4) with an inner diameter of 3 mm was inserted through this hole and placed

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so that it was positioned over the outer edge of the test rod (5). A circulating pump (6) was used to pump water through the tube at 0.5 l/min. The resulting water jet thus directly hit the tip of the test rod (7). The GRP rods were rotated around their own axis at a horizontal speed of 10 000 rpm in the centrifuge. For a 22 cm long rod, this corresponds to a speed of the rod ends of 414 km/h. At the same time, a vertical load was applied from above with a continuous 3 mm wide water jet, which flowed through the aluminium pipe 1 cm above the loaded area to simulate rain. By developing a suitable test method for the simulation of rain erosion on a laboratory scale, it was possible to carry out a comparative test relevant to the results.

Evaluation The evaluation of the damage patterns, which occurred on the differently coated test rods after different rotation times in the simulation chamber, was performed visually. It was clearly evident how the resistance to rain erosion depends on the respective fillers in the coating. The replacement of the reference filler combination talc and synthetic barium sulfate by coated high-performance

fillers in terms of volume significantly improved the resistance of the coated rods to impacting raindrops. After only 5 min. at 10 000 rpm, the samples with the reference fillers showed a serious damage pattern (Figure 3, photo 1). Furthermore, a dramatic edge break of the rod was observed after 8 min. at 10 000 rpm with the reference fillers (Figure 3, photo 2). By specifically modifying the surface of the wollastonite, silica and feldspar powders, it was possible to achieve an even more resistant coating. Only after a double loading time of 10 min. at 10 000 rpm, the test rods with coatings containing surface-modified wollastonite (Figure 3, photo 7) or surface-modified silica powder (Figure 3, photo 12) showed a damage pattern comparable to that of the reference rods after 5 min. at 10 000 rpm (Figure 3, photo 1). The surfacemodified feldspar continues to withstand this load. Only after 13 min. at 10 000 rpm serious damage occurs in the form of delamination and substrate breakage. Apart from the surface modification, the higher hardnesses of 4.5, 6, and 7, and the grain morphologies (platelet in wollastonite, square edged in silica, and thick tabular in feldspar) contribute to the better results of the high-performance fillers compared to the reference fillers.

Useful surface modification

Figure 2. Schematic structure of rain erosion test.

In what way do surface modifications improve the performance of coatings? Potential weak points can develop at the interface of the polymer-filler system. For example, moisture or aggressive substances can penetrate the coating and cause corrosion, blistering, and loss of adhesion. Surface treatment of the mineral fillers with silanes or silane-based chemical compounds can ensure optimum compatibility at the interface of the polymer matrix and the filler system. Thus, system improving properties of the inorganic filler are achieved and fully exploited. Silanes are bifunctional compounds containing stable organofunctional and hydrolysable reactive end groups. The hydrolysable group bonds with the filler surface, while the organofunctional groups harmonise with the polymer.

Conclusion The test results show that the resistance of rotor blade coatings of a wind turbine depends largely on the fillers used. By using special high-performance fillers in the pore filler, the resistance of rotor blade coatings to rain erosion is significantly improved. The resulting improvement in the coating system of rotor blades can lead to an increase in durability, improved efficiency, and optimised maintenance intervals of wind turbines. The investigation has been expanded and is still in progress. New and interesting results are expected shortly.

References 1. 2.

Figure 3. Damage patterns on the coated GRP epoxy rods.



BASF, RELEST® WIND Systeme für die Windenergie,XD99-8550-2010/45151613, S. 4, pp.7-8. Bayer Material Science, Polyaspartics-Change the coatings game!, MS00051641, 02/2011, p.9. EHLERS, M., 2010, Bayer Material Science, Presentation: Polyaspartics for environmentally friendly and efficient coatings.

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Evgenia Golysheva, ONYX InSight, UK, explores how digitalisation can improve three key areas of the offshore wind industry.


ccording to the Global Wind Energy Council (GWEC), offshore wind capacity in 2030 is projected to reach 234 GW.1 However, it is currently 29 GW globally.2 So how can the offshore wind industry unlock its full potential for growth to achieve the ambitious targets set by countries such as the UK, which has committed to power every home through offshore wind by 2030?3 The fundamentals are largely in place. Investors are increasingly confident in offshore wind as an asset class, and the technology is maturing. Significant decreases in the cost of producing energy with offshore wind have been driven by increases in turbine size and streamlining the supply chain. Now, the route forward for the sector involves using digital tools to help overcome three key challenges: logistics, ageing assets, and the emerging skills gap. These will continue to act as a bottleneck for growth, costing owners and operators money, unless action is taken now.

Optimising logistics The key difference between offshore and onshore wind is the need to transport personnel and equipment out to sea. An onshore wind farm can be serviced by a technician team in a van. In offshore operations, a wide supply chain of crew transfer vessels, jack-up platforms, and offshore cranes are required to carry out work, presenting a significant fixed cost for owners and operators. Being able to control and rationalise logistics therefore represents a critical cost saving for offshore wind. When a single gearbox replacement can cost up to £1 million, it is crucial to ensure that vessel utilisation is maximised.


Figure 1. The offshore wind sector is rapidly upgrading its approach to data.



Consolidating trips is particularly effective for crew transfer vessels, which transport technicians to and from offshore assets. But to unlock these savings and improve the flexibility of work schedules, owners and operators must first use data from offshore wind turbines to prioritise maintenance work and optimise scheduling to reduce weather risk. Predictive maintenance is ideally suited for offshore wind operations. By analysing data-streams from across a wind fleet and combining this data with real-world engineering expertise, it is possible to assess where action is urgently needed and where it might be more effective to carry over the work to a later date. Predictive maintenance can extend lead times on emerging problems by up to 24 months, giving owners and operators the flexibility to schedule work at optimum times. Working with a good predictive maintenance partner can deliver savings of 30% from O&M budgets. Crucially, with greater oversight of operations and maintenance across an entire offshore wind fleet, owners and operators can group work by location and work type, to ensure that scarce resources are used most effectively. Looking further ahead to the new megaprojects of the 2020s such as Dogger Bank, predictive maintenance will also play a vital role in enabling the success of these co-located projects. Data sharing and joint maintenance tenders will help to keep unnecessary trips out to wind farms to a minimum – and advanced diagnostics to accurately estimate remaining useful life can support this.

Ageing assets Currently, ageing assets are considered a problem mainly for onshore wind. However, as the offshore wind sector continues to mature, it can learn from the earlier best practice from onshore and tackle the challenge proactively. Wind turbines being built today will be operational in 2050. The right predictive maintenance programme can extend useful asset life by at least 25% – but the benefits are greater when datadriven life extension strategies are considered from the start of a turbine’s lifecycle. Advanced analytics enables owners and operators to gain insight into asset health and useful life, identify high risk components in advance and replace them at the optimal time, or optimise operating conditions before they progress into costly failures. Starting life extension early will see the industry benefit from increased valuations of their assets, by up to 12%. This helps to unlock further investment for the sector, while ensuring that wind farms continue to deliver profits long after their payback period has concluded. In offshore wind, assets are continuing to increase in size, and repair costs rise with this. Predictive maintenance maximises the impact of affordable, simple actions to boost asset health. Performing a grease flushing to protect the main bearing can add years to the lifetime of a component but is only 1% of the replacement cost. The latest advances in multi-channel data analysis are set to increase the effectiveness of predictive maintenance even further. A particularly powerful combination is oil condition data and vibration data. These data-streams, when analysed together,


enable issues to be pinpointed with more confidence, allowing more accurate insights into turbine operation. This technology is already being rolled out, but as it becomes more widespread, the potential to extend turbine lifetimes will improve in kind.

Bridging the skills gap The skills gap in offshore wind is a natural result of the sector’s impressive growth. As a relatively new industry, the established skilled labour force is smaller compared to older energy sectors, and offshore wind will need more workers than ever in the next decade. GWEC have projected that crucial emerging markets such as the US and China will need 77 000 skilled personnel by 2024.4 Across EU wind energy, there is a current annual shortfall of 7000, projected to rise to 15 000 by 2030 – but the problem is at its most severe in O&M.5 Part of this is supply-side, with a chronic shortage of STEM graduates in key European markets such as the UK. However, the issue has been compounded by a sector-wide drive for cost savings, putting pressure on training budgets needed to upskill new personnel into experienced offshore wind engineers. Digital tools can lessen the pressure of skills gaps, by standardising best practice and supporting operational decision making. The latest mobile applications available to field technicians can verify that optimised procedures are followed during inspections, while feeding back to site managers in realtime to provide support where needed. This helps ensure that more experienced personnel can share their expertise widely. Additionally, streamlining data collection can empower personnel to spend more time problem solving, and less time on administrative tasks. Applications that create automated reports of inspections with tagged photos are already being rolled out by large players in the wind energy. Digitising inspection data is an especially valuable way to gain insight on asset health, enabling expert engineers to analyse ongoing trends in the turbine’s operation. The opportunities laid out before the offshore wind sector are virtually boundless. Offshore wind is set to play a key role in the global green recovery, providing cheap, clean energy to power other sectors – and our homes. Exciting new technologies such as floating wind will open up new markets such as Japan, and scale up other technologies crucial to the low-carbon economy, such as green hydrogen. Turbines built in the next few years have a 40-year useful lifetime within reach. If offshore wind takes steps to future proof their operations and maintenance now using smart predictive maintenance strategies, owners and operators in the sector will be able to do more with less and ensure decades of continued growth.

References 1. 2. 3. 4. 5.

Global Wind Energy Council, ‘GWEC: Offshore wind will surge to over 234 GW by 2030, led by Asia-Pacific’, 5 August 2020. Offshore WIND, ‘GWEC: Global Offshore Wind Capacity Reaches 29GW’, 19 March 2020. The Guardian, ‘Powering all UK homes via offshore wind by 2030 will need £50bn’, 6 October 2020. Renews, ‘GWEC study warns of offshore wind ‘skills gap’’, 16 April 2020. European Wind Energy Technology Platform, ‘Workers wanted: The EU wind energy sector skills gap’, August 2013.

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Lea Hurst, Head of Fleet, CWind, UK, introduces a hybrid surface effect ship crew transfer vessel which can help contractors within the offshore wind industry remain competitive.


he offshore wind industry is booming, and with key governmental targets – such as the UK’s commitment to generate one-third of all UK electricity through offshore wind by 2030 – demand will continue to rise. Offering far greater energy generation capacity than onshore wind, at its maximum potential, offshore wind production could account for more than 120 000 GW, according to a report published by the International Energy Agency. If this was in fact the case, production of that magnitude would total 11 times the projected global electricity demand by 2040. Key to delivering this level of energy generation is the falling cost of offshore wind. Recent findings from the UK’s Department for Business, Energy & Industrial Strategy (BEIS) show that the wholesale price for offshore wind has dropped by more than half, from £167/MWh in 2017, to £83/MWh in 2021. Prices are expected to decline further as demand increases, with the expectation that offshore wind will form the backbone of an immensely expanded and zero carbon electricity supply, to meet ambitious targets such as the UK’s commitment to net zero by 2050. Driving the decrease in wholesale prices are the industry’s technological advancements, with innovative assets



assets which will not only allow contractors to shorten project timelines in order to meet the higher demand, it also enables clients to meet their environmental objectives.”

Adding to the fleet The latest addition to CWind’s fleet, a 22 m, 24PAX hybrid surface effect ship (SES) CTV, was designed with these reductions in cost, time, and emissions in mind. Named the CWind Pioneer to demonstrate its position at the forefront of CTV innovation, the vessel was created in response to an industry-wide push to develop and deploy Figure 1. CWind Pioneer, the world’s first hybrid surface effect ship (SES) crew transfer vessel (CTV). innovative technologies that reduce carbon dioxide (CO2) emissions, while costeffectively servicing wind farms located further offshore. With more than 80% of the world’s offshore wind resources located in areas of vast, deep ocean, wind farms are increasingly being constructed further offshore. This has led to a growing number of planned and approved floating offshore wind farm projects, which are viable options over fixed units for waters deeper than 60 m. The increasing distances from shore present a challenge for wind farm owners when it comes to maintaining their assets. Many owners and operators utilise a dedicated service operating vessel (SOV), which offers an offshore base for workers. These vessels can have a significant financial and Figure 2. The CWind Pioneer deck, which can hold 7 t. environmental impact. In fact, transferring personnel by the CWind Pioneer uses approximately four times less fuel than a and improved processes coming to market. As the wholesale SOV. price continues to fall drastically, BEIS projections show it could “This is where the CWind Pioneer is a game changer,” Nathanael continues, “The Hybrid SES technology offers reach lows of £46/MWh by 2024. wind farm owners and operators a lower-cost and greener Staying competitive in the offshore wind alternative to traditional vessels. Moreover, with its speed and industry efficiency it provides technicians and crew more time working To remain competitive, contractors within the offshore wind on the turbines or back onshore. industry must create cost and time efficiencies, either through “So far, the vessel has recorded a maximum speed of the development of new assets, or the adoption of new 43.5 knots in the UK Solent, in loaded condition. When you processes. This issue is further compounded by the current consider that the world’s largest offshore wind farm to date, deficit of low emission, high performance assets and skilled Hornsea One, is located almost 75 miles from shore, the workers to carry out the work required. benefits of utilising a high-speed CTV like the CWind Pioneer become clear. It offers more than a green alternative for the Nathanael Allison, Managing Director at CWind, a CTV market. It becomes a viable alternate to expensive SOVs provider of project services, crew transfer vessels (CTVs), as you can transit daily to locations further offshore.” and GWO-accredited training courses to the offshore wind When transferring personnel to a wind farm 30 miles industry, explains, “The exponential growth of the offshore from shore, the CWind Pioneer, at a speed of approximately wind industry over the last decade has led developers, OEMs, 40 knots, would take 45 min., compared with 1 hr 15 min. and the wider supply chain to create greener, more efficient


for an average CTV travelling at 24 knots. This translates to 10% more time on the turbines over a 12 hr shift, which is equivalent to taking another two technicians offshore for a fully manned 24PAX vessel. With surface effect hull form and active heave compensation technology, the CWind Pioneer can operate at high speeds, and can transit and transfer safely in sea states in excess of 1.8 m Hs, while minimising motion and acceleration through its air cushion motion control system, resulting in a smoother, more comfortable CTV experience for technicians and crew. Impressively, the active heave compensation works when the vessel is stationary – therefore enabling safe, reliable turbine transfers in conditions where other CTVs of similar size might be weathered off. The overall design and build pay particular attention to technician and crew health, safety and comfort, delivering the workforce in the best possible work-ready condition, resulting in increased operation days offshore for the client’s operations, maintenance, and construction activities. “Although the vessel’s full capabilities will not be realised and recorded until the vessel is operating on the wind farm, the results from trials have been extremely positive. Initial figures we can share have been extracted from our continuous monitoring and data recording system installed by Reygar. Having this data logging system means we know the performance of the vessel now and how this is being achieved, which will help us make the vessel operate in a

Figure 3. COVID-19 hygiene screens within the CWind Pioneer saloon.

Figure 4. The wheelhouse of CWind Pioneer, with ample room for three crew.

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more time and fuel-efficient manner, in the process, helping our customers achieve their emissions reduction targets,” said Andrew Newman, Engineering Manager at Global Marine Group, CWind’s parent company. “This vessel has exceeded 43 knots in loaded condition and already experienced inclement conditions on trials. It is a brilliant vessel which can truly be called a new generation of CTV. It is exciting to be part of this milestone project” continued Andrew.

The vessel in action The CWind Pioneer will be used at the Borssele 1 and 2 offshore wind farms through a long-term charter contract agreement with Ørsted. Together, the two wind farms have a total of 94 wind turbines, located almost 14 miles from shore, with water depths ranging from 14 - 39.7 m. The vessel can hold up to 24 technicians as well as three crew, who will carry out vital maintenance to the turbines to help power 1 million homes per year. The CWind Pioneer represents a well-designed vessel, purpose built for the task in hand and finely tuned to transport and transfer technicians safely, reliably, and efficiently. This has been achieved by close co-operation between Ørsted and CWind, at every level of the project. Most notably, senior directors, project managers, and technical staff for both companies have communicated and worked together for project success. A particular demonstration was representation at an Ørsted HIRA by the vessel construction project manager and operational team, before the first metal was cut on the CWind Pioneer. Such early, decisive co-operation ensures the vessel is optimised for client requirements, which translates to a lower levelised cost of energy and lower CO2 emissions. The CWind Pioneer enables Ørsted to not only operate and service its wind farms efficiently through reduced transit times, but also supports Ørsted’s ambition of a world that runs entirely on green energy. The vessel achieves this through a hybrid diesel and battery electric power system which enables the CWind Pioneer to operate purely on battery power while in harbour or at standby in the wind farm, resulting in a decrease in fuel burn and CO2. At a speed of 43.5 knots, the CWind Pioneer is over 20% more fuel efficient than conventional CTVs running at 24 knots, on a mile for mile basis. For a typical wind farm situated 30 miles from port, this translates to a reduction of over 110 tpy of CO2 per vessel, by using the hybrid SES. To put that into context, a reduction of 110 t of CO2 is equivalent to taking 24 passenger cars off the road every year – simply by switching to the SES. This figure excludes the savings of the hybrid system, which will allow the vessel to be zero emission ship infield whilst the technicians are on the structures, carrying out their work on the turbines. Specific figures will be shared once these savings are proven, but initial studies suggest a 30% - 50% saving over conventional vessels. This saving will be further increased when offshore charging becomes a viable option. Significant fuel savings are achieved by using the battery to stabilise load and using electrical infrastructure onboard


to ensure the diesel engines operate only at efficient power bands. The electric motors can also propel the vessel at speeds below 6 knots (on and off cushion) to enable zero emission transfers and low engine power running hours. Only operational experience will confirm the predicted models, but it is estimated that this capability could lead to engine operating hours being reduced by 50% during wind farm battery standby.

Important factors to consider Since achieving faster long-distance travel while reducing CO2 was key in the vessel’s development, the team explored both hybrid diesel/electric and hybrid diesel/hydrogen options. Electric propulsion does work best over shorter distances but, despite technological innovation that has reduced battery weight, it was not enough to allow electric-only operation with a meaningful range at this time. Diesel engines are needed to supplement the electric pack currently, but constant improvements and alternative fuels are expected to change this in the future. Hydrogen availability, storage, and fuel cell technology are too bulky and heavy for this lightweight vessel at present, meaning a diesel/electric hybrid was chosen over a diesel/ hydrogen or even hydrogen/electric hybrid. CWind remain closely engaged in the market on developments in this technology and see fuel cells and hydrogen as key enabling technologies for the company’s road to zero CO2 ambitions. The vessel’s control systems are largely automatic, meaning the vessel operates like a conventional vessel, with a few additions. There are no complex switching or manual input requirements, instead the onboard control systems naturally manage the power grid to ensure safe and efficient navigation is maintained and the vessel Master remains in control at all times. It is not just the design and mechanical drivetrain that is novel. The vessel has an aluminium hull with a composite polymer-based superstructure, giving weight savings whilst reducing noise, vibration, and providing thermal insulation. “Technician comfort is more than just seating,” Andrew explains, “In the saloon, noise, vibration, temperature, motion, and lighting have been carefully considered to create a space which can be controlled to ensure the technicians arrive at their destination in the best condition possible. Bright, cold light may be best for operational briefing; warmer, dimmer light for transit; and darker lighting for the return to allow some rest. It is all possible at the touch of a button.” “The launch of the CWind Pioneer marks a significant milestone for the industry and helps pave the way towards achieving net zero targets.” Nathanael continues, “the vessel utilises revolutionary technology to meet the needs of the market and our customers who want a greener, safer, and more efficient CTV to support their commercial and green objectives. With the CWind Pioneer we have delivered just that – a new generation of CTVs.” The CWind Pioneer is the newest addition to CWind’s fleet of more than 20 CTVs as part of a strategic plan to remodel and upgrade the company’s current asset offering.

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Enrico Calzavacca, AB Energy, Italy, considers the advantages of new developments in gas separation technology for upgrading raw biogas into renewable natural gas.


olstered by an ever-growing demand for cleaner energy sources and carbon dioxide (CO2) reductions, renewable natural gas (RNG) has become a hot topic for discussion and action across North America and the greater globe. RNG, also known as biomethane, is a refined natural gas arising from biogas produced from the bacterial breakdown of organic waste materials through anaerobic digestion. The sources of organics are commonly food and food processing waste, farm animal and plant waste, select industrial wastewaters, and municipal sewage. Biogas is purified into RNG and injected into natural gas utility pipelines for distribution or used as a fuel to power vehicles. The use and demand of RNG has seen strong growth both on the national and international market, thanks to the incentives of EU countries, which aim to promote the use of RNG in the transport sector. Recent studies, including the 2019 report 'The optimal role for gas in a net-zero emissions energy system’, published by Navigant and Gas for Climate, identify the crucial role that


Figure 1. Detail of the activated carbon filter system in a BIOCH4NGE® plant.

Figure 2. Front view of the activated carbon filters system in a BIOCH4NGE plant.

Figure 3. BIOCH4NGE is able to integrate seamlessly with cogeneration plants to create a totally sustainable energy system.


renewable gases, such as RNG and hydrogen, play in cutting emissions. Such studies also underline the importance of infrastructures, including those that are currently operational, in boosting total decarbonisation at accessible prices in view of the EU targets for 2050. An estimated potential of approximately 270 billion m3 of renewable gas is expected to be fed into existing infrastructures by mid-century, for estimated savings of approximately €217 billion/yr. According to Gary Collins, Regional Sales Manager at AB Energy UK, “While hydrogen initiatives have been grabbing headlines, RNG can be used locally at the site where the gas is created or it can be injected into natural gas transmission or distribution pipelines. Biomethane is an exact natural gas substitute, but decarbonised!” Currently, different RNG upgrading technologies are available on the market, based on different chemicalphysical principles related to gas separation. The BIOCH4NGE® solution developed by AB relies on a membrane system, the most widely used in the world. It consists of specific polymeric materials that have a selective permeability, particularly useful in the methane (CH4) and CO2 separation. Biogas obtained from the anaerobic digestion system is purified in order to remove water and pollutants. Once pretreated, the methane is separated from the carbon dioxide: this process makes it possible to obtain a specific RNG with the desired characteristics for different uses, maximising the recovery efficiency of methane from biogas. “RNG applications are extremely synergic with biogas plants, a sector in which AB is active with hundreds of plants around the world, representing an opportunity to boost technicalindustrial development in line with market demands,” stressed AB President Angelo Baronchelli. “BIOCH4NGE is the crowning achievement of our RNG production sector. It represents the combination of our engineering, industrial and operational expertise, as well as a strategic choice to offer the latest technologies and the best highefficiency solutions for the recovery of CH4 from biogas. It is indeed a valid

and competitive alternative for clients who already have an operational biogas plant, as well as an interesting possibility of high-efficiency development for those thinking of entering this market, while paying attention to environmental and economic sustainability.” The BIOCH4NGE system is the culmination of nearly four decades of advancements from the experience AB has acquired in the global cogeneration and biogas sectors. The system is compact, modular, easily scalable, versatile in application, and effective in upgrading and purifying raw biogas into RNG at a low cost of operation. At its core, the system employs advanced membrane technology to separate methane from other gases and impurities found in biogas. Raw ‘wet’ biogas flowing from anaerobic digesters enters the first stage of the process, where primary filtration followed by a chilled water exchanger condenses water vapour to dehumidify the biogas. This gas is compressed, cooled by a second heat exchanger, and delivered under strict temperature and pressure conditions to vessels containing activated carbon. The beds of activated carbon ‘strip’ the gas of residual hydrogen sulfide and volatile organic compounds (VOCs). In this final stage, the purified biogas is compressed and passed through AB’s proprietary membrane system to separate the CO2 and methane components. The purified methane exiting the process is ready to be used as fuel. AB preassembles and tests each system in the company’s production facility as part of its rigorous quality control regimen. This step is designed to dramatically reduce on-site installation and commissioning efforts, saving clients substantial costs and avoidable start-up challenges. BIOCH4NGE integrates well with cogeneration plants, to create a totally sustainable energy system. The need to obtain electrical energy for upgrading and heat for biology is effectively resolved with an ECOMAX® CHP system. This can be combined with the system, whether fed by methane gas from the grid or by surplus biogas. As a result of the CH4LNG liquefaction system, fully compatible with BIOCH4NGE, it is also possible to obtain liquid biomethane. The heart of the process is the cryocooler – based on Stirling cryogenics technology – which is a reciprocating system to generate cooling power in closed loop using no consumables. CH4LNG is a modular containerised solution also available in small sizes, with competitive CAPEX and OPEX even for small-sized plants, with plug-in operation, and without liquid nitrogen consumption. Another key point is the service, which makes all the difference. AB Service, with its worldwide team of specialist technicians, is the AB company dedicated to customer service and maintenance. AB Service is currently responsible for the maintenance of more than 1250 plants by over 200 field technicians, and a full service rapid response team active 24 hours a day, 365 days a year. The full service contract provides remote monitoring of the system and the availability of original spare parts. In fact, the system is equipped with a centralised monitoring and supervision system, produced and managed by AB,

which enables the remote control of all system parameters and related production processes. The benefits for customers include: minimum downtimes, strong performance, and maximum reliability. A strategic choice for an assured return on investment.

Application in Italy BIOCH4NGE helped to produce the first m3 of biomethane from agricultural biomasses to be injected into the Italian grid. The farm La Castellana, on the outskirts of Milan, Italy, was successful in this enterprise. At La Castellana, the fields are cultivated on 900 ha., approximately 15 000 pigs are bred, and electricity is produced by two biogas plants capable of 999 kW and 500 kW. Now, finally, biomethane is also being produced. AB Energy conducted an interview with Francesco Crivelli, who joined the company immediately after his studies. After several years in the business, where he was involved in new production (small organic fruits) and implementation of irrigation technologies, he had his real baptism, the biomethane plant.

How did the project of the plant come about? F: It stems from a need felt mainly by my father, that of giving continuity to the branch of energy production, even after the Italian incentives for electricity that will end in 2022. So, we converted one of the two existing plants and upgraded it by reducing electricity production by 30% to co-exist with biomethane production which is now at 450 m3/h. When the electricity is turned off it will reach 635 m3/h.

What were the biggest difficulties you encountered? F: In the first instance, finding the right synergy between field, breeding, and the plant to solve the biomass brain teaser for the production of advanced biomethane. Currently, the recipe is made of chopped triticale, sorghum, corn stalks, straw, and of course manure. But for biomethane to be sustainable we had to find the ‘trade off’ between first and second crops, so first we produce barley that goes to feed the animals, followed by sorghum as an energy crop. In other fields, we cultivate triticale as an energy crop, followed by maize for pigs, recovering the stalks for biomethane. In others, we alternate peas and sorghum. Straw is the residue of barley threshing. The other difficulty has been tracing for certification mainly due to the fragmentation of the land. So, we had to reconstruct the history of the land use through the maps of each field identifying the different crops. It was really challenging!

Is the management of the plant complex? F: No, the plant has very advanced technology, control, and regulation systems, however to date we have not yet found particular critical points with the upgrading process.

Are you satisfied with the decision to convert production from biogas to biomethane? F: To date I would say yes!




Yoichiro Taguchi, Yokogawa, Japan, discusses whether the reduction of process energy consumption is the ultimate goal, or if managers should also be optimising energy production efficiency by taking advantage of all the opportunities currently available.


hile manufacturing facilities have always recognised energy as a cost, when prices are stable and supplies reliable for the most part, it receives limited attention. For much of the 20th century, in North America particularly, energy was cheap. The calculations changed in the mid 1970s when global disagreements prompted oil embargos and major supply disruptions. Suddenly skyrocketing costs and concerns about availability forced manufacturers and the general population to pay attention to energy consumption and conservation. Over the last several decades, the energy landscape has changed in many ways, with costs fluctuating over a wide range. Traditional sources, such as coal and nuclear, have declined in importance, while supplies from natural gas and renewables are growing consistently.


Manufacturers, for the most part, are more aware of the role of energy in overall cost structures and continuously try to reduce its impact. Effects of the COVID-19 pandemic have caused major changes in consumption patterns, resulting in drastic price changes for oil and petroleum products. While overall consumption is expected to recover somewhat in 2021, traditional fuels may never return to their previous price levels since the range of competing options continues to grow. Energy is now available from more sources than ever before as countries throughout the world work at reducing their carbon footprint, or at least slowing its growth. Carbon reductions have become more international with countries working together to set goals and accountability.

Figure 1. Reducing energy costs generally involves a range of projects from simple to complex, each with varying payback times.

Is process energy demand reduction enough? Energy conservation for industrial users is important due to the magnitude of its cost. For large scale process plants, it normally accounts for 50% of operating expenses (Figure 1). Consequently, an energy outlay reduction of 10% can often improve gross profit by 5%. As companies seek to boost profit, energy is naturally one of the first places to look. That being the case, it is safe to believe that every plant has made at least some effort to reduce energy consumption through more efficient equipment and improved process control. Efficiency of everything from lighting to company trucks is better now than even a few years ago. Plants launching comprehensive programmes typically insert instruments into distribution systems to measure energy flow. For example, electrical branch circuits have individual power meters to see where power is being consumed. Similarly, natural gas and fuel oil flows are metered on a granular level, along with steam and compressed air. These efforts are all critically important. When consumption is monitored in detail, it is possible to identify and fix energy hogs, often reducing total energy demand significantly with just a few changes. Area by area, a plant can quickly make improvements to optimise consumption. On the other hand, large scale improvement projects, such as building a cogeneration system, need to be examined carefully for cost/benefit potential (Figure 2). The question is, are all of these efforts sufficient, or is there more that a company can do to reduce costs (a direct corporate benefit) and reduce carbon footprint (a social benefit)?

Optimal operation of energy systems

Figure 2. When considering major improvements, a plant should conduct a thorough analysis to create a holistic and accurate cost/benefit picture.

Figure 3. Energy management tools, such as KBC’s Visual MESA (a Yokogawa company), provide the mechanisms to analyse energy usage and optimise sources based on current needs and history.


The answer is yes, and that is through optimal operation of all the company’s interrelated energy systems. Not only can energy demand be reduced, supply can also be optimised to achieve specific goals by taking advantage of all the options available today, especially renewable sources. Process manufacturing plants and other manufacturing sites need to consider how these sources can produce, distribute, and mix energy into the consumption picture, and put it to good use by integrating them within or reformulating existing energy systems. Sometimes the objective is reducing cost, whereas other times the goal is to reduce emissions. Consider hydrogen production as an example. Traditionally, the least expensive way for a plant to generate hydrogen is by reforming methane, but this process produces carbon dioxide as a byproduct, which is normally vented to the atmosphere. If the plant wants to eliminate the carbon dioxide stream, it can follow a costlier approach and use electrolysis to break down water into oxygen and hydrogen (i.e. green hydrogen). However, deciding if this is advantageous depends on the power source. If the electricity to break down water comes from a coalfired, subcritical power plant, the amount of carbon dioxide produced per unit of hydrogen is probably worse than reforming methane. But, if it is generated by wind turbines on a particularly windy day, a bank of photovoltaic panels,

or surplus output from the facility’s cogeneration system, the calculation changes. Using this approach produces less (or zero) carbon dioxide, uses no methane, and might actually be less expensive. These conditions might not be available all the time, every day, but a plant should be able to take advantage of them when possible. The ability to make this determination requires detailed knowledge of the sources and uses of energy for the facility at any given moment (Figure 3). When such data, models, and analytical tools are available, energy usage can be optimised to minimise cost, minimise emissions, and/or favour specific sources. Performing such an evaluation automatically in real-time is ideal, but represents a major undertaking. Even large and energy-intensive facilities, such as oil refineries and multi-unit chemical plants, may not have the expertise and systems to gather all the supporting data and put it to good use.

networks (fuel, steam, electricity), but also equipment and systems related to renewable energy (solar, wind, biomass).

F Support for forecasting, which deals with future conditions of the site and its environment. These can include weather and market conditions on the supply side, plus process energy demand – including steam, power, fuels, hydrogen, etc.

F Support for analysing current and past energy efficiency and performance of the site from historical data.

Weighing up the options Selecting which source should be used at any given time depends on having data related to all the possible options. Should we fire up the cogeneration system and minimise power import from the grid, do the opposite, or something in between? Making the proper decision calls for knowing the fuel and operating costs compared to the current cost of running off the grid. These values fluctuate, and it is not practical to start the cogeneration plant to run for just an hour or two, so realistic predictions must be made based on past experience. At an operational level, decisions on when to use the cogeneration system or another option will now be directly affected by the predictions of weather conditions and their effects on wind or solar generation availability. Moreover, due to the uncertainty of the factors defining the generation of renewable energy, such as wind speed and solar intensity, some kind of energy storage mechanism should be available to capture the surplus and serve as back-up when renewable generation is expected to decline. Manufacturing green hydrogen is one example, or the power can be diverted to batteries. In some cases, it can be sold to the local utility, sending power out of the plant to the surrounding community. All this leads to a great challenge for the person or group in charge of optimally managing the energy system.

Figure 4. Conservation efforts often fall short of what they could accomplish, while programmes using digital transformation can go much farther to reduce costs and emissions.

Table 1. The expected savings are easy to see, all realised through use of real-time optimisation Economic Summary




Steam Turbogenerators STG2 Power generation (MW)





LS Extraction flow (tph)





Power generation (MW)





MS Extraction flow (tph)





Throttle flow (tph)





MS Extraction flow (tph)





Throttle flow (tph)





HS Extraction flow (tph)














Olefiny Large steam turbines

Analytical tools solve the challenge Clearly this kind of analysis cannot be undertaken manually to the extent and speed necessary for it to be effective across a large and complex facility, especially when renewables are involved. Fortunately, the tools already mentioned – using digital transformation – can follow both the sources and uses of energy (Figure 4), making it possible to optimise selections well beyond conventional conservation efforts. Selecting the best approach for a given situation calls for consultation with specialists who can evaluate each unique opportunity. Such tools must have specific capabilities, including: F An integrated model that considers equipment and subsystems common to traditional, carbon-based energy



GT-1201 Throttle flow (tph) HE Extraction flow (tph)



Real-world results Detailed next are two real-world examples of plants that have realised substantial savings through energy optimisation. First, PKN Orlen’s Plock Complex in Poland is one of Europe’s largest refineries. In addition to 276 000 bpd refining capacity, there is an olefins plant and a cogeneration power plant using combined cycle gas turbine technology. The site deployed an energy real-time optimiser with the objective of minimising energy use and reducing steam venting by optimising energy production. Once the Visual MESA Energy Real-Time Optimizer was designed and installed, the practical Figure 5. The complex relationships of the facility’s operating units and their operational parameters were set up, providing integration into the local energy infrastructure called for complex analysis as a first training for operators and engineers, along with step to optimisation. reporting procedures. Energy costs and steam losses are anticipated F Support for optimal management of energy inventory. to decrease substantially (Table 1). Depending on which units are operating, the overall F Support to optimise operation in real-time while taking facility can potentially save between 0.2 - 5.0% of total into consideration the optimal schedule, frequently energy production costs. These savings were realised by updated on a moving horizon time frame. using real-time optimisation. Second, Braskem’s UNIB-1 Olefins Complex in Brazil F Automated operation of these functions in the long deployed the Visual MESA Real-Time Optimizer to improve and short-term to make them fully feasible and free up its adaptation to changing operational scenarios. The operators for higher-value activities. programme built a systematic energy management process, integrated directly with plant-level operations. Internal These tools are usually built on a digital twin of the cogeneration and steam production capabilities (Figure 5) facility, providing real-time, model-based analysis of all the support the plant’s operations, but also external clients, so energy systems of the entire site and even neighbours. In energy was flowing out and in. operation, this combination of multi-period optimisation The optimisation programme alone provided total (MPO), energy monitoring (EM), and real-time optimisation energy savings of 2.1% without any equipment modifications (ERTO) performs activities in light of the past, optimising the or improvements, plus a range of other non-quantifiable present, but with an eye to the future. The MPO thus functions benefits. as a monitor and guide for ERTO, while considering a moving horizon optimal multi-period scheduler. This allows the facility to always operate at the lowest cost and within emission A tailored solution constraints. Real-time energy management tools, including optimal In stand-alone use, the combined MPO/EM/ERTO approach scheduling, monitoring, and optimisation, must be tailored helps operators and engineers generate, analyse, and to each facility or VPP since each situation is different. The distribute the optimal schedule of utility systems of the site, sources and uses of energy vary widely from one plant to even including its neighbourhood, under the concept know as another, so no single solution can fit everywhere. Yokogawa virtual power plant (VPP). A VPP could be a relatively complex and its companies have been using this approach for more network of decentralised power generating units such as wind than 30 years with constant evolution and improvement. farms, solar parks, and combined heat and power units, as Many companies have been using these technologies well as power consumers, green hydrogen generators/users, consistently for decades. and storage systems. The interconnected units are considered For example, the range of equipment that plants use as a whole, to be optimally scheduled, monitored, and has grown, along with the availability of renewable energy optimised in real-time. supplies within a given facility’s reach. This calls for flexibility The combination of energy management applications and adaptability within the conceptual framework. can be configured to work autonomously, gathering and The demands of corporate stakeholders and processing the necessary forecasts of the unmodelled environmental regulators will continue to evolve, as will variables — such as fuel price projections and weather the options for plant managers. For example, the notion of forecasts, executing calculations, historising key performance green hydrogen has been growing around the world and indicators, and distributing the resulting reports. These actions represents a major shift in zero-carbon energy production. guarantee consistency among the decisions systems at Companies wanting to join this movement must have the different time scales, optimising in real-time but accounting for right management tools, which are available today to drive the constraints imposed by the optimal schedule. their energy systems optimally from now on.



GLOBAL NEWS RWE to construct floating solar project in the Netherlands

VivoPower awarded electrical works contract for Australian solar project

RWE, one of the world’s leading companies for renewable energy, is to construct its first floating photovoltaic (PV) project. The Amer floating PV project consists of 13 400 solar panels that will float on a lake near the Amer power plant in Geertruidenberg, in the Netherlands’ province of Noord-Brabant. After completion, the innovative PV project will have an installed capacity of 6.1 MW peak. The company has also started constructing a 2.3 MWp ground-mounted PV project on the site of its Amer power plant. Both PV projects, floating and ground-mounted, are part of Solar Park Amer. Roger Miesen, CEO of RWE Generation and Country Chair for the Netherlands: “Our first floating PV project demonstrates our ambition to drive forward the energy transition with innovative technologies and clean energy supply.” In 2018, RWE realised the first phase of Solar Park Amer, installing over 2000 PV panels with 0.5 MW peak on the roof of its power plant. The solar park is now being expanded. Construction of the floating PV project is expected to start at the beginning of August 2021, and to be commissioned by the end of 2021. Construction of the ground-mounted project has already commenced and is expected to be finished in August 2021. The green electricity generated by Solar Park Amer is equal to the annual electricity consumption of approximately 2300 Dutch households.

VivoPower International PLC has announced that its wholly-owned subsidiary in Australia, J.A. Martin Electrical Pty Ltd (J.A. Martin), has recently been awarded a contract to complete all electrical works for the 200 MW Blue Grass Solar Farm located near the town of Chinchilla in the Australian state of Queensland. The project will be the third Australian solar farm completed by J.A. Martin in partnership with lead EPC contractor GRS and brings J.A. Martin’s total of completed and contracted solar farms to over 350 MWdc. Once energised, the Blue Grass Solar Farm will generate approximately 420 000 MWh/yr of clean energy, enough to power 80 000 homes, and avoid over 320 000 tpy of carbon dioxide emissions, the equivalent of approximately 130 000 vehicles. The project’s construction will create approximately 400 local jobs. Phil Lowbridge, General Manager of J.A. Martin, said, “J.A. Martin is excited to have the opportunity to once again work with GRS to construct another major solar farm, our largest to date and our first utility-scale solar project in Queensland. We look forward to completing another successful project and continuing to help power the growth of renewable energy across Australia.” Carlos López, Managing Director of GRS, added, “Our progress in Australia, with Blue Grass Solar Farm as paragon of our remarkable milestones in 2020, tells us that we are on the right track.

Sunseap signs solar energy agreement with Amazon Sunseap Group, a Singaporean solar energy provider, has signed a long-term agreement with Amazon to export 62 MWp of clean energy to the national grid, helping Amazon meet its sustainability goals. Sunseap was awarded one of the two contracts under JTC’s SolarLand Phase 3 tender in 2020, part of JTC’s efforts to make industrial estates more environmentally friendly. As part of the contract, Sunseap will install the solar systems on an estimated 40 ha. of temporary vacant land across Singapore. Unlike conventional fixed designs, these systems are designed to be

modular and flexible, and can be redeployed when the land is needed for other uses. When completed in 2022, they will be some of the largest aggregated mobile solar systems designed and installed in Singapore. The 62 MWp generated from the solar systems will amount to 80 GWh/yr of clean energy. 100% of the renewable energy generated by the plant will be supplied to Amazon, helping Amazon meet its commitment to achieve 100% renewable energy by 2030, a goal that the company is on path to reach by 2025.




GLOBAL NEWS Air Liquide purchases clean energy from Vattenfall Vattenfall has signed its first power contract for wind farm Hollandse Kust Zuid. Air Liquide will purchase 100 GWh/yr of fossil-free electricity from the wind farm located off the Dutch coast. The 15-year contract will start in 2023 when the Hollandse Kust Zuid wind farm is operational. Air Liquide, a world leader in gases, technologies, and services for the industry and health sectors, will use the electricity to power its factories in the Netherlands. Martijn Hagens, Chief Executive Officer, Vattenfall Netherlands: “We are delighted that Air Liquide, which has ambitious sustainability targets, will purchase fossil-free electricity from Vattenfall. Long-term contracts such as these provide us with financial security and enable us to keep investing in wind and solar farms, a cornerstone in our ambition to enable fossil-free living within one generation. The Netherlands is turning to a fossil-free future and we want to make that a reality for our customers.” Hollandse Kust Zuid is one of the first subsidy-free offshore wind farms in the world. It will be located between 18 - 36 km off the Dutch coast, between The Hague and Zandvoort. Construction will start in 2021. In 2023, when the wind farm is operational, the 140 wind turbines will produce more than 6 TWh/yr of green electricity. The electricity will be available to households, government and businesses, and thus contribute to Vattenfall’s ambition to provide all its Dutch customers with 100% Dutch fossil-free electricity by 2030.

MilliporeSigma, Akamai, Synopsys, and Uber enter into wind energy deal MilliporeSigma, Akamai Technologies, Inc. (Akamai), Synopsys, and Uber, with support from Sustainability Roundtable Inc’s Net Zero Consortium for Buyers, have signed power purchase agreements (PPAs) with Enel Green Power for the energy produced by a 111 MW portion of the Azure Sky wind project located in Texas, US. The aggregation deal, a model which enables companies with smaller and more distributed energy needs to combine renewable energy demand to collaboratively purchase renewable energy, is among the largest aggregation deals in the world. “This aggregation deal demonstrates an extraordinary shift in the renewable energy purchasing market to give businesses with modest energy demand, but ambitious renewable energy goals, the opportunity to procure renewable energy in a cost-effective way,” said Georgios Papadimitriou, Head of Enel Green Power in the US and Canada. “As more companies of all sizes look to power their operations with clean energy, Enel is uniquely positioned to enable that transition, by creating customised solutions to meet the energy needs of all buyers.” The wind energy purchased by the four companies from the 111 MW portion of the Azure Sky project is expected to generate approximately 430 000 MWh/yr, equivalent to the electricity used by approximately 40 000 average US homes annually.

TechnipFMC and Magnora to develop offshore wind projects TechnipFMC has announced it has entered into an agreement with Magnora ASA to jointly pursue floating offshore wind project development opportunities under the name Magnora Offshore Wind. Magnora holds a strategic position within the renewable energy sector as an owner in offshore wind, onshore wind and solar development projects, and is a key enabler in solar energy technologies. When combined with TechnipFMC’s technologies, experience delivering integrated EPCI projects, and its novel Deep PurpleTM initiative to integrate wind and wave energy


with offshore green hydrogen storage, this partnership will enable Magnora Offshore Wind to realise significant opportunities in the growing offshore floating wind market. Magnora Offshore Wind has already commenced operations and started work on an application for the first round of seabed leasing through the Scottish Government’s ScotWind Leasing programme. In addition, Magnora Offshore Wind will participate in the first offshore wind application round in Norway, which opens in 2021, and will also consider entering new markets in the coming months.



GLOBAL NEWS Vopak invests in storage capacity in the Netherlands Vopak is investing in the Port of Rotterdam, the Netherlands, for the storage of waste-based feedstocks for the production of biofuels such as biodiesel and bio-jet fuel. The market for energy from renewable sources in Europe is rising, in part as a result of the Renewable Energy Directive II of the EU. In total, 16 new tanks with a combined capacity of 64 000 m3 will be built at Vopak Terminal Vlaardingen, located in the Port of Rotterdam. The renewable feedstocks that can be stored in the new tanks are waste materials, such as used cooking oil and tallow. Vopak Terminal Vlaardingen already has extensive experience in storing these types of products. The terminal is strategically located within the Port of Rotterdam and is well connected for logistics by vessels, barges, trucks, and trains.

German bioenergy project reaches financial close Macquarie’s Green Investment Group (GIG), Wismar Pellets, and PEARL Infrastructure Capital (PEARL) have reached financial close on the Bioenergie Wismar Combined Heat and Power Plant in northern Germany. Located at the Port of Wismar, it is GIG’s first bioenergy project in continental Europe. Co-developed by GIG and Wismar Pellets, the combined heat and power (CHP) biomass plant will generate up to 18 MWe of electricity and 27 MWth of renewable heat. The project’s fuel supply is anchored by Wismar Pellets and ILIM Nordic Timbers, who will provide bark material as a byproduct of the companies’ timber operations. Wismar Pellets and ILIM will also contract for the project’s steam output and utilise the heat at neighbouring facilities for timber drying. The project successfully secured an EEG feed-in tariff for its electricity output in November 2020. For construction funding, GIG partnered with PEARL, who as majority shareholder will now take the project into construction with Wismar Pellets. Macquarie Capital, the project’s financial advisor, also raised a long-term project finance debt facility, which was provided by Landesbank Baden-Wuerttemberg. Commercial operations are anticipated to commence in 4Q22.

BIOGEST to build biogas plant in South Korea BIOGEST has received an order to build an agricultural and food waste biogas plant in the southern region of South Korea. The project, which is located close to Daegu, has been developed by BIOGEST in co-operation with HC Energy and DoBangYukJong Farm, and is supported by the Changnyeong-gun city office. The BIOGEST PowerRing biogas plant will be an important reference plant to attract further local projects. The expanding energy gap, technology growth, and population density has greatly increased the importance of renewable energy resources. Biogas production from animal, agricultural, and food waste is one of the most rapidly expanding sectors of renewable energy. The biogas plant is fed with pig slurry and the food waste will be delivered from an organic waste collection point. BIOGEST’s proven biogas plant technology offers advantages in energy efficiency and operational safety, as well as an easy and costefficient maintenance system. The plant is able to produce both electric and thermal energy. During the process, 13 000 t of pig slurry and 5000 t of food waste are transformed into high-quality organic fertilizer that acts as a substitute for chemical products. In addition, the air quality of the pig farm can be improved.

THE RENEWABLES REWIND > Haldor Topsoe and Aquamarine sign green ammonia MoU > Minesto and Schneider Electric team up on ocean energy commercialisation > Thordon Bearings and Millstream Engineering to improve hydropower infrastructure in Canada Follow our website and social media pages for more updates, industry news, and technical articles.




GLOBAL NEWS Deep Purple green hydrogen project secures backing from Innovation Norway TechnipFMC is moving ahead with a pilot project for the Deep Purple green hydrogen offshore energy system, which is a key component of its energy transition offering. The company is leading the consortium to construct and test the system, with Innovation Norway recently announcing its contribution to this €9 million pilot project. Deep Purple uses offshore wind energy to release hydrogen from seawater. The hydrogen is then stored subsea for later use to provide renewable energy. Deep Purple overcomes one of the challenges of storing energy generated from renewable sources. Deploying these systems is critical to accelerating the energy transition. The Deep Purple project began in 2016 and has received support from the Research Council of Norway. The consortium consists of leading industrial partners Vattenfall, Repsol, ABB, NEL, DNV GL, UMOE, and Slåttland, and is supported by academia, research companies, and clusters. The pilot will allow the consortium partners to prepare the system for large-scale offshore commercial use. The scope includes the development and testing of an advanced control and advisory system and a dynamic process simulator.

Fortescue Future Industries and Port of Açu to develop green hydrogen plant in Brazil Fortescue Future Industries Pty Ltd (FFI), a wholly owned subsidiary of Fortescue Metals Group Ltd, and Porto do Açu Operações S.A. (Port of Açu), a subsidiary of Prumo Logistica S.A., have signed a Memorandum of Understanding (MoU) to assess the opportunity to develop hydrogen-based green industrial projects in Rio de Janeiro, Brazil. Signed in late February, the MoU will allow for FFI and Port of Açu to conduct development studies into the feasibility of installing a green hydrogen plant at Port of Açu, Latin America’s largest privately owned deepwater port-industrial complex. Subject to the outcome of the studies, the project envisages construction of a 300 MW capacity green hydrogen plant at Port of Açu, with the potential to produce 250 000 tpy of green ammonia. The availability of green hydrogen and renewable power is expected to drive further sustainable industrialisation of the port, including production of green steel, fertilizers, chemicals, and other sustainably manufactured industrial products.





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