Energy Global June 2022

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CONTENTS 03. Guest comment


26. A new direction

04. What lies ahead for US renewables? Marcelo Ortega and Geoffrey Hebertson, Rystad Energy, US.

Thomas Raiser (Switzerland) and Ramnik Singh (US), Global Biobased and Renewables Group at Sulzer Chemtech Global.

30. A pillar of progress Maria Anez-Lingerfelt, PhD, Pall Corporation, US.

Marcelo Ortega and Geoffrey Hebertson, Rystad Energy, US, present an outlook for the current US renewables landscape, as well as outlining the roadblocks the country must overcome to reach market stability.

36. The gear up to green


t the start of the year, Rystad Energy estimated that 47 GWAC of solar photovoltaics (PV), wind, and energy storage projects would be commissioned in 2022. Of this, almost 10 GWAC of onshore wind assets are to be deployed this year – a 57% drop compared to 2021. Rising steel prices and expiring production tax credits are set to result in capacity levels such as those seen in 2019. Solar, meanwhile, could install just over 27 GWAC across the utility, residential, and commercial and industrial segments, which would have made 2022 a record-breaking year for PV capacity. The solar industry, however, has had a tough kick-off, with 17.5 GWAC at risk of being delayed or cancelled as the recent antidumping circumvention probe has halted panel imports into the US. Exacerbating the issue, silicon prices remain high with no alleviation in the immediate-term. More than 12 GWAC of renewable energy capacity was delayed by more than six months in 4Q21. Due to commodity price inflation and unfavourable policy decisions, almost 5 GWAC of solar PV, onshore wind, and battery capacity lined up for installation in the US was delayed in November last year, and almost 7 GWAC in December. This is a significant trend because while project delays are expected in the industry as installed capacity grows and developers overestimate lead times, in a typical month these delays do not exceed the gigawatt mark. While in the first three-quarters of last year, a typical delayed solar PV asset would see its start-up date pushed back by 3.5 months on average, this skyrocketed during 4Q21 to 6.4 months. This indicates that developers are facing more substantial hurdles in project development that could shift the entire country’s pipeline. The same trend can be appreciated for other technologies, with average project delays jumping from 2.4 months for batteries and onshore wind in the first three-quarters of the year to 5.5 months for batteries and 5.4 months for wind by the end of 2021. Solar PV projects were affected by polysilicon prices which soared in 2021. Prices for this commodity are not expected to come down until 2H22 at the earliest. US developers have been left hoping for a better economic and political environment further down the line. Similarly, steel price hikes put pressure on wind projects. Hopes were deposited on the Build Back Better framework that did not come to fruition. The bill put forward by US President Joe Biden was set to be voted by the Senate in December 2021 but was effectively killed when Democrats fell short by one vote. The legislation, which included commissions related to social policy and climate change, was expected to be a major game-changer for renewables in the US as it extended federal incentives for clean energy projects, specifically the Investment Tax Credit (ITC) and



Florian Gruschwitz, MAN Energy Solutions, Germany.

42. Invest in the future Ambroise Fayolle, Vice President of European Investment Bank, France.

46. Geothermal: the next frontier? 5


Brian Pye (Malaysia), Greg Rheaume (US), and Martin Rylance (UK), THREE60 Energy.

50. Going geographical with geothermal

10. Poland's push for offshore wind

Georgina Ainscow, Reddie & Grose, UK.

Marceli Tauzowski (Poland), Carla Ribeiro (UK), and Marie-Anne Cowan (UK), Wood Thilsted.

54. Feel the heat

16. Maintaining momentum Borbala Trifunovics, Director, Arup, UK.

22. Collaborate or stagnate Bahzad Ayoub, Westwood Global Energy Group, UK.

Max Brouwers, Getech, UK.

58. Iceland fires up Árni Magnússon, Bjarni Richter, and Arni Ragnarsson, ÍSOR, Iceland.

64. Global news

Reader enquiries []



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Director-General for Energy, European Commission


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n 18 May, the European Commission published its REPowerEU plan. First outlined in March in the aftermath of the Russian invasion of Ukraine, the objective of this plan is to rapidly and structurally transform Europe’s energy system to reduce dependence on Russian fossil fuels as quickly as possible, without losing track of the long-term ambition of becoming climate-neutral by 2050. For one, it underlines the immediate priority of finding alternative suppliers, and the vital role that energy infrastructure can play in sharing energy among member states. It also stresses the importance of energy efficiency and measures individual consumers can take to save energy. The cheapest form of energy is the one that is not consumed. And then there is renewables. The massive scale-up of renewables is one of the main pillars in the REPowerEU plan. This is an approach which clearly supports energy independence, while also serving the fight against climate change. A recent poll shows that 84% agree that the war in Ukraine makes it more urgent for EU member states to invest in renewable energy.1 In the new geopolitical situation, the REPowerEU plan proposes a new objective to increase the European renewable energy target from at least 45% of the energy mix by 2030, instead of 40% in last year’s proposal. This would bring the total EU renewable energy generation capacities to 1236 GW by 2030, in comparison to 511 GW today. This new target would enable us to rapidly reduce reliance on natural gas for heating purposes in buildings and industrial processes through heat pumps, solar thermal, and geothermal resources, as well as locally produced biogas from agricultural waste residues. The deployment of district heating systems in densely populated areas will be critical to ensure that renewables can help decarbonise buildings and offices in a cost-effective way, in particular if combined with renovation measures. A dedicated solar strategy will guide rapid deployment of utility scale solar technologies, unlock the rooftop potential on public, commercial, and residential buildings, and bring solar value to citizens and communities. The conversion of renewable power into renewable hydrogen is another avenue to replace fossil fuels in hard-to-decarbonise applications in the EU. The REPowerEU plan boosts both local

production and imports of renewable hydrogen, and accelerates the renewable electricity roll-out as well as electrolyser manufacturing capacities in the EU. The rapid development of both grid and hydrogen infrastructure to produce, transport, and import renewable hydrogen will be supported to ensure that renewable-rich areas are taken advantage of, and that these renewables are brought in the form of electricity or hydrogen to consumers. In light of the higher renewable energy targets, the European Commission is also taking additional measures to support member states and other stakeholders to speed up the deployment of renewables. Slow and complex permitting procedures for renewables have been a concern. Whilst legislation mandates specific time limits to permitting procedures for renewables, these rules are not evenly implemented across member states. This is why the European Commission will issue a guide to share best practices, as well as a set of recommendations to remove any ambiguities in the application of existing EU legislation. Furthermore, the European Commission is amending the existing legislative framework to introduce so-called ‘go-to areas’ where renewables deployment can take place through shortened and simplified permitting procedures, whilst minimising any potential impacts on the environment. Last but not least, the European Commission is supporting the development of renewable energy purchase agreements. Increasingly, large corporate companies have been signing long-term corporate renewable power purchase agreements with renewable project developers to obtain stable and cost-competitive renewable electricity. This often gives them a competitive advantage and also underlines their green credentials, whilst reducing public support for renewables deployment. The guidance aims to enable renewable energy purchase agreements across the EU as well as for small- and medium-size enterprises. Taken together, we believe these measures can help the EU address the most difficult geopolitical challenge that Europe has seen in more than half a century without losing focus of the longer-term fight against climate change.

References 1.

Flash Eurobarometer 506, ‘EU’s response to the war in Ukraine’, 5 May 2022.

Marcelo Ortega and Geoffrey Hebertson, Rystad Energy, US, present an outlook for the current US renewables landscape, as well as outlining the roadblocks the country must overcome to reach market stability.


t the start of the year, Rystad Energy estimated that 47 GWAC of solar photovoltaics (PV), wind, and energy storage projects would be commissioned in 2022. Of this, almost 10 GWAC of onshore wind assets are to be deployed this year – a 57% drop compared to 2021. Rising steel prices and expiring production tax credits are set to result in capacity levels such as those seen in 2019. Solar, meanwhile, could install just over 27 GWAC across the utility, residential, and commercial and industrial segments, which would have made 2022 a record-breaking year for PV capacity. The solar industry, however, has had a tough kick-off, with 17.5 GWAC at risk of being delayed or cancelled as the recent anti-dumping circumvention probe has halted panel imports into the US. Exacerbating the issue, silicon prices remain high with no alleviation in the immediate-term. More than 12 GWAC of renewable energy capacity was delayed by more than six months in 4Q21. Due to commodity price inflation and unfavourable policy decisions, almost 5 GWAC of solar PV, onshore wind, and battery capacity lined up for installation in the US was delayed in November last year, and almost 7 GWAC in December. This is a significant trend because while project delays are expected in the industry as installed capacity grows and developers overestimate lead times, in a typical month these delays do not exceed the gigawatt mark. While in the first three-quarters of last year, a typical delayed solar PV asset would see its start-up date pushed back by 3.5 months on average, this skyrocketed during 4Q21 to 6.4 months. This indicates that developers are facing more substantial hurdles in project development that could shift the entire country’s pipeline. The same trend can be appreciated for other technologies, with average project delays jumping from 2.4 months for batteries and onshore wind in the first three-quarters of the year to 5.5 months for batteries and 5.4 months for wind by the end of 2021. Solar PV projects were affected by polysilicon prices which soared in 2021. Prices for this commodity are not expected to come down until 2H22 at the earliest. US developers have been left hoping for a better economic and political environment further down the line. Similarly, steel price hikes put pressure on wind projects. Hopes were deposited on the Build Back Better framework that did not come to fruition. The bill put forward by US President Joe Biden was set to be voted on by the Senate in December 2021 but was effectively killed when Democrats fell short by one vote. The legislation, which included commissions related to social policy and climate change, was expected to be a major game-changer for renewables in the US as it extended federal incentives for clean energy projects, specifically the Investment Tax Credit (ITC) and




the Production Tax Credit (PTC). These two incentives have been paramount for the development of renewables in the US. The PTC is preferred by wind developers and was terminated at the end of 2021. The ITC was the incentive of choice for solar PV projects and has a scheduled phaseout in 2026. The legislation also contained other potential federal incentives addressing clean hydrogen production, standalone utility scale batteries, and manufacturing facilities for solar and wind components. When the bill failed, wind developers had to quickly reassess strategies, which led to 1.43 GWAC of capacity being delayed on the back of expectations of a PTC

Figure 1. US renewable energy installations to 2035 by year and technology.

Figure 2. Average delays for renewables in 2021 by energy source.

Figure 3. Battery storage outlook in the US to 2025 by state.



extension later this year instead. Meanwhile, uncertainty over the duration of the ITC also hit solar PV future projections. Discussions on Capitol Hill indicate that the bill may be revisited in a version that retains some of the original clean energy tax credits. If Democrats can agree on the contents of this new potential bill, they would be throwing the clean power sector a lifeline when it needs one the most to overcome current supply chain hurdles.

What to watch out for this year Despite significant policy and supply roadblocks for solar and uncertainty of tax extensions for wind, US storage is set to continue strong having established its presence across grids in the US with various use cases from arbitrage to resource adequacy. Worldwide battery installations are estimated to reach 24.6 GWAC by the end of the year, which entails a 96% annual growth rate. Although all regions of the world are waking up to the benefits of battery storage, nowhere is this more apparent than in the US. Last year marked the beginning of the battery boom in the US, and this trend will continue in 2022. The US battery capacity grew by 152% in 2021 and is estimated to grow by 154% this year, which equates to 8.8 GWAC of new capacity. By 2025, 53% of the world’s batteries will be in the US. This year, California will install 3.1 GWAC of batteries, reaching 5.8 GWAC of total capacity. California’s energy storage mandates from the early 2010s propped the state to become the leading US battery market. California’s lead has been declining since 2020 when the market in Texas started to ramp up deployments. This year, Texas is set to install 2.4 GWAC of capacity. New York and Arizona follow, with 900 MWAC and 488 MWAC, respectively, of the year’s total battery installations. The US battery boom is closely related to another key trend in the North American market: asset hybridisation. Rystad Energy estimates that 57.5% of the battery capacity to come online in 2022 will be part of a hybrid project. By co-locating a battery next to a solar PV or wind farm, different development synergies can be achieved resulting in lower project costs and the unlocking of lucrative tax credits. By employing these configurations, developers only need to acquire a single piece of land, negotiate a single power purchase agreement, and reduce the number of power electronics by sharing it between the battery and the power generator. Another trend to pay attention to is the clear dominance of renewables in the interconnection queues in the nation. Solar and storage are the most in-demand technologies looking to connect to the US grid in the short- to medium-term, according to Rystad Energy analysis of the country’s seven largest independent system operators (ISOs). There is currently over 760 GW of zero-carbon capacity seeking transmission access in the US, with over 320 GW of new capacity added to the interconnection queue in 2021. Nearly 80% of this is split between standalone storage, solar, solar plus battery, and storage paired with generation. While not all projects will reach completion, the major influx of capacity will undoubtedly help the US move closer to its clean energy goals. The current administration has aggressively incentivised offshore wind, with a hefty goal of deploying 30 GWAC of capacity by 2030. Noticing its lackluster 42 MWAC of operational capacity in 2021, the federal government has expedited auction processes. In February, the largest offshore wind leasing auction in the US occurred, with six companies being awarded offshore land with the potential to generate 5.6 GWAC of electricity. The pace of offshore

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leasing activity has ramped up dramatically, with six more auctions planned between 2022 and 2024. Nevertheless, supply chain constraints are limiting the deployment of these projects. The Jones Act, a World War I era law, requires goods shipped between US ports to be transported by vessels built, owned, and operated by the US – thus creating a major hurdle for offshore wind farms. For the purpose of this law,

the location of an offshore wind farm is considered a port and implies that any wind turbine installation vessel would have to be built domestically, leaving the industry unable to tap into existing European ships. The US has only one such vessel under construction which is set to create a bottleneck once all permitted projects start construction. For this reason. Rystad Energy estimates the US will end this decade with an offshore wind capacity close to the 22 GWAC mark.

Policy adds pressure

Figure 4. US interconnection request mix by ISO. Storage includes standalone battery, pumped-hydro, and other forms of renewable storage. Hybrid includes all storage that is co-located with generation. Other includes non-renewable capacity such as gas, coal, and methane.

Figure 5. US PV panel imports by country of origin.

While not impervious to supply chain constraints and policy, wind and storage could be in for above-average years in the short-term. Solar, however, less so. Delays due to supply chain constraints amid high commodity prices and shipping rates, as well as unfavourable policy have effectively shut down an entire industry in a matter of months. On the 25 March 2022, the US department of commerce (DOC) decided to investigate a petition by a domestic PV manufacturer concerning composite silicon (cSi) solar PV panels sourced from Malaysia, Vietnam, Thailand, and Cambodia. The investigation claims that Chinese panel manufacturers are circumventing anti-dumping and countervailing (ADCV) rules by offshoring cell and panel assembly processes to the four countries while still using cheap Chinese raw materials. The looming sanctions risk undermining the US solar industry since 84.9% of 2021’s and 99.4% of January and February 2022’s panel imports were sourced from these four countries. The DOC is scheduled to declare a preliminary judgement on the issue in August, with results due by January 2023. Historically, ADCV tariffs have been applied at different rates to different Chinese suppliers. In the 2012 investigation, the most applied rate was 30.66%, with some rates going as low as 24% and others as high as 250%. If the DOC determines a tariff extension will be imposed because of the latest probe, equipment imported after the announcement of the investigation would be allowed, but tariffs could be applied on imports dating as far back as November 2021. From November 2021 to February 2022, US buyers imported US$1.46 billion worth of panels from the four Southeast Asian countries under investigation. Depending on how the tariffs are applied, Chinese suppliers could be collectively liable to pay between US$365 million and US$3.6 billion in additional tariffs. Chinese panel manufacturers are unwilling to risk such prohibitively high fines so have opted to halt panel exports to the US. According to an industry survey by the Solar Energy Industry Association (SEIA), approximately 80% of respondents said their supply deals have been cancelled in the last month.

Anti-dumping probe and Xinjiang ban

Figure 6. Polysilicon capacity by country of origin in 2021.



The US PV industry began 2022 in a tough situation even prior to this latest probe. At end-2021, some 7.35 GWAC of solar PV was delayed by more than six months due to rising commodity prices, uncertainty over US federal tax credit extensions, and unfavourable policies. This included the US government’s decision in December 2021 to ban imports containing goods from China’s northwest region of Xinjiang due to human rights abuses committed against the Uyghur ethnic minority. With 40% of the world’s silicon production based in Xinjiang, this policy almost halves the number of panels that can be imported into the US, making it highly disruptive, though less so than the ADCV probe.

Marceli Tauzowski (Poland), Carla Ribeiro (UK), and Marie-Anne Cowan (UK), Wood Thilsted, discuss the future of Polish offshore wind, considering how government targets will shape the country’s emergence into the sector.



oland has set itself an ambitious offshore wind target to have 10.9 GW of installed capacity, either operational or under development, by 2027. This is enshrined in the recent Polish Offshore Wind Energy Act that came into force in February 2021.1 As bold as this target is, it raises many important questions; especially given the fact that there are not any offshore wind farms currently operational in Polish waters.

Is there enough space? At first glance, the Polish Exclusive Economic Zone (EEZ), which covers an area of more than 22 500 km2 (approximately 6% of the total area of the South Baltic Sea) provides a good amount of sea floor for Poland to achieve its energy targets. However, when considering the competition offshore wind faces, with everything from fisheries to wildlife conservation, not to mention other energy sectors, is this a problem? The Polish government has already addressed this need for balance with the introduction of the Maritime Spatial Development Plan, in April 2021. The Plan co-ordinates spatial use of Polish waters, balancing economic and environmental needs and uses. The combined result of this Plan and the Offshore Energy Act is the designation of three offshore wind farm development areas, with fixed boundaries, which are consented and tendered by the government. At present, offshore wind energy can only be developed in these areas. Interestingly, although there are no defined fixed limits for capacity density generally set by the Polish authorities,2 one of the qualifying criteria in the ongoing seabed lease does set a minimum for this metric. That is to say 8 MW/km2 for any wind farm, and this does not include exclusions such as environmentally protected areas, wrecks, or existing infrastructure. A cursory glance would suggest this seems like an excessively high minimum, given the amount of seabed being offered up. Could this be from a desire to maximise the chances of meeting the ambitious 10.9 GW target? So, to answer the first question: ‘Is there enough space?’ – in short, yes.



The installed capacity required to meet the target of the act can comfortably fit in the three identified areas. The more complex

question then is, what are the challenges caused by this capacity density threshold of the 8 MW/km2 set by the regulatory authorities? This article explores the overall technical feasibility of this target and opens up a key discussion on the potential challenges.

Working out capacity density To start this exploratory work, Wood Thilsted has reviewed the rules of the application process for Polish seabed leases and set them against five other major European offshore wind markets, looking at observed capacity densities for a comprehensive set of operational projects in these countries. The review reveals those regulatory mechanisms in relation to exclusivity, including wind farm rated capacity, and capacity density requirements, which vary considerably among the markets analysed. This provides a thought-provoking spread in observed capacity density and size of wind farms, as shown in Figure 1. Offshore wind farm capacity density by country, size, and maturity. A sample of projects representative of each market has been Figure 1. used for the plot. Each sphere refers to a project, and the size of the However, variations and differing needs across sites spheres depicts the size of the project as installed capacity (MW). and countries means developing generalised conclusions about capacity density is a challenge. From an engineering perspective, maximising array efficiency and therefore energy production is what will drive the design principals around capacity density decisions. In other words, lower capacity density generally delivers lower turbine interaction losses and so maximises energy production. However, it is not actually that simple. Country siting regulations, as shown in Table 1, vary widely which, combined with the development area available, strongly affect the mean wind farm capacity density of each country. Belgium is a perfect example of this, where space is scarce for offshore wind. Developers therefore need to make the most of the available area, resulting in a higher capacity density. For countries with more seabed available, Wood Thilsted sees more freedom to use larger areas. And, in countries where the decision on wind farm installed capacity stays with the developer, lower mean capacity densities are the norm. The UK is a particularly strong example of this, due to its larger exclusive economic zone (EEZ). So, what about Poland? By establishing a minimum capacity density for the ongoing lease auction, the Polish government seems to be signalling that its primary focus is on maximising the seabed, in order to achieve the targeted installed capacity Figure 2. Mean and range of wind farm capacity density per market. for the country. This decision means that Poland may be following the Belgium model, despite the larger EEZ available in this market. Table 1. Selected countries regulatory schemes based on the Baltic LINes publication and WT experience4 However, there is more to it than that. As well as Polish projects having one of the highest turbine Country Development Site boundaries Wind farm total Capacity density areas rated power capacity densities, these projects are mainly at the Developer’s Developer’s upper end in terms of size (area) compared to other BE Fixed Fixed decision decision operational western European projects. For example, in Developer’s Developer’s Developer’s Developer’s the UK, projects of a similar installed capacity are being DE decision decision decision decision constructed, albeit with a much lower capacity density. DK Limited (max) Pre-developed Fixed Limited (min) Furthermore, wind farms in Poland are being planned in NL Fixed Pre-developed Limited (max) Limited (min/max) clusters, where neighbouring wind farms will significantly Developer’s Developer’s Developer’s Developer’s impact each other. So, what does this all mean? In short, UK decision decision decision decision this is something the industry has not really seen before Developer’s and so may require several technical innovations to meet PL Fixed Fixed Limited (min) decision the challenges.




Although using site areas as intensively as possible to meet minimum capacity density requirements may increase the overall energy production, there are downsides: increased turbine interaction energy losses (internal and external wakes and global blockage effects); as well as increased wake-induced fatigue loads for downstream turbines may lead to reduced lifetimes and/or premature damage of the asset. In other words, any marginal gains may be lost, and there may be an increased levelised cost of energy (LCOE). This issue could be further compounded by the ever-increasing turbine rotor blade size. Given the timescale of projects, it is highly likely that the first offshore wind farms in Poland will use larger turbines than those already installed at existing projects, or planned for projects in more advanced stages of development. These larger turbines are trending towards a lower specific power,meaning that although they have longer blades and greater swept areas, the nameplate capacity is not increasing proportionately.4 The trend of decreasing turbine-specific power in the UK offshore wind market has previously been assessed.5 It has been shown to result in better low-wind performance

Table 2. Future turbine technology assumptions and resulting project scenario assumptions Scenario one

Scenario two

Scenario three

Turbine nameplate rated power (MW)




Hub height (m above mean sea level)




Rotor dia. (m)




Wind farm capacity (MW)




Number of turbines




and better capacity factors for offshore wind farms (i.e., the ratio of net energy yield production to the maximum possible energy yield production). Whilst this explains the latest trend in decreasing turbine-specific power, it has exciting implications for layout design and resulting capacity densities.

Further analysis with potential scenarios As a result of this thinking, Wood Thilsted have investigated this further by analysing potential scenarios that consider how the following factors might impact offshore wind farm layout design in Poland: FFThe trend in future turbine technology.

FFHow this translates to project capacity density for Poland’s regulatory approach.

FFWhat this means for the resulting impact on turbine interaction effects. Three scenarios have been modelled based on a theoretical project with the following parameters: FFSite area of approximately 110 km2, seen to be representative of typical offshore project development areas in Poland.

FF1200 MW installed capacity, in order to achieve the minimum 8 MW/km2 capacity density set by Polish regulators.6

FFRegular turbine spacing of approximately 7 rotor dia. in the prevailing wind direction (assumed to be westerly) and 4 dia. in the transverse directions in a rectangular grid.

FFApproximately 10.0 m/sec mean wind speed at the proposed turbine hub heights.

Figure 3. Trend of turbine specific power observed in Europe from 2000. Each sphere refers to a turbine model, and the size of the spheres depicts the rotor dia.

Figure 4. Layout scenarios considered. Ellipses illustrate the 7D by 4D turbine spacing assumed.



The three scenarios have considered future turbine technology assumptions as shown in Table 2. The turbine rotor dia. have been determined to obtain a turbine-specific power of between 340 W/m2 and 360 W/m2, a range defined based on the trend observed in Figure 3. Using the above assumptions, the theoretical turbine layouts shown below have been put forward as working scenarios. The company has also calculated the turbine interaction effects for the scenarios considered using the Eddy Viscosity wake model, within WindFarmer Analyst, with large wind farm correction, including an assessment of the blockage effects. The results are shown in Figure 5. This study indicates that, in this situation (fixed site area, fixed project installed capacity, and minimum capacity density of 8 MW/km2), increasing the turbine size from 15 MW to 25 MW could achieve lower turbine interaction losses, despite the larger rotor dia. However, it appears that there is a sweet spot in terms of turbine size (MW and rotor dia.) for the Polish offshore

wind market. A balance must be reached between the additional energy yield that comes from using larger turbines, and the reduction in yield that comes from having fewer turbines (with larger swept areas but with proportionally lower nominal capacities). In this example, the drop in number of turbines from 60 x 20 MW turbines (in scenario two) to 48 x 25 MW turbines (in scenario three), is not compensated by the additional yield that can be generated by the 25 MW turbine. It should be noted that this study does not take into account any other technical loss factors such as availability and electrical efficiency, which will Figure 5. Indicative energy yield production (after turbine interaction effects) and turbine interaction effect losses estimated for the three also be impacted by the project configuration. Nor does it scenarios considered. consider alternative turbine layout design techniques such as edge-packing or irregular grids, which will have some impact on the resulting turbine interaction effects (both internal wakes and blockage effects). Notwithstanding this, depending on the specific market, this study still serves to illustrate that perhaps ever-larger turbine models may not always be the obvious choice in achieving an ever-lower cost of energy for offshore wind farms. Taking everything into consideration, it seems likely that Poland will not see the large spread of project capacity densities seen elsewhere. When designing layouts, developers will try to maximise energy yield and asset life by spacing the Figure 6. According to Wood Thilsted, developers – when choosing the best solution for Poland – turbines out as much as possible – may buck the trend of adopting turbine models with increasing rated power and instead use whilst still sticking to the minimum turbine models that deliver higher energy yield output. turbine density set. As is, simply by complying with the minimum capacity density requirements of 8 MW/km2, design (impacting electrical efficiency and balance of plant developers will already see increased turbine interaction cost). A holistic approach to all these aspects will be crucial effects in their projects, and all the issues that come with to delivering an optimised project. it (increased energy losses and increased turbine loading Finally, as turbine technology continues to evolve, the primarily). Therefore, logically, they will seek to avoid industry may see more tailored turbines and solutions capacity densities above the minimum prerequisite. offered by manufacturers to adapt to specific market Intriguingly, another possible outcome of the regulatory requirements. Developers should try to take advantage of conditions in Poland may be that developers buck the the relatively low wind and wave extremes seen in this part trend of adopting turbine models with increasing rated of the Baltic Sea, and push the design envelope to focus power, and use turbine models that deliver higher on addressing high waked-turbulence conditions, rather energy yield output, whilst accepting the higher turbine than other design drivers.7 This might assist developers of interaction effects that will bring. Implementation of wake management techniques (for example wake steering or Polish projects to overcome the many technical challenges. axial induction control) could be a solution to mitigate Overall, the relatively benign conditions of the southern those higher wake effects, reduce structural loads, extend Baltic Sea may come to be of great benefit to the offshore project lifetime, and consequently decrease LCOE. wind industry there. Careful layout design will also have a key role to play in the successful optimisation of offshore wind farm projects References 1. Act of 18 December 2020 on the Promotion of Electricity Generation in Offshore Wind Farms. in Poland, whilst meeting regulatory requirements. Though 2. The ratio of the wind farm’s rated capacity to the wind farm’s site area in MW/km 3. Baltic LINes, ‘Capacity Densities of European Offshore Wind Farms’, Report conducted by this can help minimise turbine interaction effects, there Deutsche WindGuard GmbH, (June 2018). are multiple factors that impact the overall optimal design 4. The ratio of turbine nameplate rated power to turbine rotor swept area [W/m ] 5. GOV.UK, ‘Potential to improve load factor of offshore wind farms in the UK to 2035’ (September of a layout. These include bathymetry, soil and metocean 2019). 6. The wind farm area used to derive the capacity density has been calculated using Delaunay conditions (impacting feasibility of certain foundation types, Triangulation, as proposed by the Danish Energy Agency. foundation design, and cost), as well as electrical system 7. ALARI, V., ‘Multi-Scale Wind Wave Modeling in the Baltic Sea’, (September 2013). 2




Borbala Trifunovics, Director, Arup, UK, describes how port infrastructure and supply chains are key for floating offshore wind, but highlights that it requires careful management to create the right conditions for the industry to thrive.


ith huge wind resource potential located offshore in deep waters around the world, floating wind power is expected to play an increasing role in meeting net zero targets. Developing the port infrastructure and supply chain required for building commercial scale floating wind farms is both the biggest barrier to rapid roll-out and one of the greatest opportunities for the supply chain and domestic economies. Such has been the success enjoyed by offshore wind power around the world that some countries, including the UK, have all but used up their supply of suitable near-shore sites in shallow waters. Other countries, such as Japan, have access mainly to deep-water locations. In fact, 80% of the world’s offshore wind resource potential lies in waters deeper than 60 m. A dramatic acceleration in the deployment of floating offshore wind is expected to help developers realise opportunities in these areas. The Global Wind Energy Council (GWEC) predicts that floating offshore wind will reach full commercialisation by 2030 with at least 6 GW installed globally. In its report, Floating Offshore Wind – a Global Opportunity – the council identifies five countries – Ireland, Italy, Morocco, the Philippines, and the US – with significant floating wind potential. The report predicts that they, together with the most mature markets in the UK, South Korea, France, and Japan, could spearhead the next wave of floating wind. However, this dash for floating wind will be from a standing start. While the UK leads the world in terms of installed capacity, its Kincardine and Hywind developments – at 2 MW and 30 MW respectively – are on a demonstration scale. And the country does not yet have its own supply chain and port infrastructure tailored to the needs of large scale floating wind, which differ significantly from those of fixed developments. The floating substructures for both Kincardine and Hywind were manufactured by the Navantia-Windar alliance in Spain and shipped from their Fene shipyard to Rotterdam, the Netherlands, to have turbines mounted before being towed to the installation site from there.

Substructure products and materials Globally, there have been approximately 10 such pilot projects, but nobody is yet building at the larger scale required to make floating wind commercial. Whereas fixed foundations are jacket or monopile structures designed individually, with a standard template adjusted for local conditions, floating substructures are designed by technology providers (as products that can be deployed across geographies). The technologies under development by different companies fall into four key types:

F Semi-submersible: a truss structure that relies on the buoyancy of its hulls and units for stability, meaning it has a wide footprint of up to approximately 100 m.




FFSpar: a long, slender substructure with a large draft of up to 100 m, with stability provided by ballast within its structure.

FFBarge: a single-hull structure with buoyancy and stability provided by its overall structure, its dia. is typically 50 - 70 m.

FFTension-leg: a lighter-weight structure that relies on tensioned cables attached to the seabed for stability. The products with high technology readiness levels include a mix of topologies and materials: FFPrinciple power (semi-submersible, three hulls).

FFStiesdal (tetra semi-submersible, suspended weight spar, tension-leg platform).

FFOlav olsen (concrete semi-submersible). FFSaitec (concrete, barge). FFIdeol (concrete, or steel barge). So, it is clear there is not a one-size-fits-all solution. While semi-submersible and barge-type substructures have been

Figure 1. Ports need to prepare quickly and efficiently for the influx of floating offshore projects.

Figure 2. Countries around the world have ambitious offshore wind targets but lack the port infrastructure required to meet demand.



the most widely used on pilot projects to date, all the different systems have their merits in different met ocean conditions. For example, spars have been used for demonstrator projects in Norway, where the deep water enables the spar to be fabricated in the vertical position. Then there is the question of the material used to fabricate the substructures: steel or concrete. It is likely, at least initially, that steel substructures will be built in areas where the necessary skills are concentrated – for example, in areas of shipbuilding expertise, such as South Korea. Skills in concrete are much more widely distributed, with transferable expertise from the building and infrastructure sectors, and so fabrication is less likely to be tied to particular areas. In addition, while building ships one at a time over a long period is not the same as mass producing dozens of floating wind substructures, the shipbuilding industry is well suited to fabricating steel substructures: it has sophisticated, automated welding techniques and a well-developed supply chain. With concrete, there is more room for innovation and new entrants to the market. This could come from players such as Spanish and Italian companies experienced in large concrete caissons.

Port infrastructure requirements For ScotWind, the first round of offshore wind leasing in Scottish waters for a decade, approximately 50% of developers bid for floating solutions, and they are likely to use semi-submersible or barge substructures. These are designed to be launched at berth and then towed out for installation. This means that, to some extent, the logistical sequence can be designed around the available port infrastructure – for example, by making use of buoyancy devices where port depth is shallower than the optimum. However, there is no getting away from the fact that building commercial scale floating offshore wind installations requires enormous sites with port access, and supply chains established around these sites. As the team at Arup works with clients on port and supply chain appraisals, they have established a clearer picture about what port infrastructure should consist of for a typical project. Ports for marshalling and construction logistics need to be close to installation sites, typically within three days towing time for tugs to ensure they reach the site safely in a suitable weather window. The location of these ports will therefore be dictated by the location of installation sites, and they are likely to be dotted around the coast. For the UK, this means along the coastlines serving the areas of focus in Scotland, North-east England, and the Celtic Sea. Then there is fabrication. Building, for example, 50 or 80 units for a commercial scale floating wind project within a couple of years will require a few centralised facilities that can manufacture cost-effectively and on a high-utilisation basis. Whoever can establish such facilities first is likely to grab the lion’s share of the market in a particular country. This will not be an easy task, though. Countries do not have ports sitting idle, without an existing customer base, and with sufficient hardstanding space with the bearing capacities required, as well as wet and dry storage alongside


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the required depth of quay. An idealised fabrication facility, whether in steel or concrete, is likely to require a site of 20 - 30 ha. and a 10 - 15 m draft unless buoyancy devices are used. These requirements are hard to find in one place, and in their absence multiple facilities are needed to fulfil requirements for single large projects, which in itself brings additional logistical considerations. New facilities will certainly be required, but this is much easier to say than to do. In the UK, a new greenfield port would be considered a nationally significant infrastructure project, and getting it through planning and construction could take up to 10 years. In order to avoid a lack of suitable port infrastructure becoming a bottleneck for the industry, an interim solution is needed. In the shorter-term, there are opportunities to start generating momentum by splitting activities between existing sites. For example, the Philippines has existing oil and gas, as well as existing LNG infrastructure spread across its thousands of islands that could be repurposed. The downside of this approach is that it will increase costs and risks.

Local supply chain opportunities Who, exactly, will be doing all this activity? While technology providers have come up with patented solutions for substructures, and turbines are broadly similar to their fixed counterparts – Vestas, Siemens, GE, and others – it is clear that the real challenge – and opportunity – for the supply chain lies in actually building floating wind at a commercially viable scale. The market’s experience of fixed offshore wind will help, but it can only go so far. For one thing, there are practical differences. Fixed projects have typically geared up for an installation period lasting between 18 months and two years, squeezing it into this tight period because of the expensive equipment required. But floating projects do not require such big, costly installation vessels all the time – meaning the vessel charter profile and cost is different. They require large cranes

Figure 3. Floating offshore wind offers the ability to provide renewable energy in challenging geological conditions.



to install and a lot more tugs to tow them out and install the moorings. As well as different port facilities, equipment, and services, floating wind is likely to have a different supply chain profile as countries look to develop their domestic industries. For fixed offshore wind projects in the UK, most of the large installation and fabrication contracts to date have been undertaken by overseas companies. While UK companies have been successful in winning operation and maintenance contracts, most of the manufacturing has been done abroad. Establishing blade factories in the UK and assembling components quayside after shipping them from overseas has been the easiest way for these companies to meet local content requirements.

Policy and confidence The situation will be different for floating wind. As local content requirements become more stringent and the UK government pursues its levelling up agenda, floating substructures will have to be manufactured in the UK. And this requires port infrastructure. In October 2020, the UK government made £160 million available through its offshore wind manufacturing investment scheme, with half allocated for upgrading port infrastructure – for which Able Marine Energy Park in South Humber received £75 million and Teesworks, the freeport site in the Tees Valley, received £20 million. With the UK government announcing in last autumn’s white paper that it plans to provide similar backing for floating offshore wind, this is a timely reminder that policy intervention can help create the right conditions for the industry to thrive but that it also takes careful management to maintain momentum. Confidence will also be crucial to maintaining momentum, and the shortlisting of companies for ScotWind was notable in this regard. As soon as that announcement came, companies rushed to confirm supply chain relationships, including Memoranda of Understanding (MoU) for port space. With the environmental impact assessments, design, contracts, and investment decisions still to come, they want to ensure they meet the deadline of being on the ground and building within five years. The confidence generated by the early adopters in ScotWind are attracting investment to Scotland. For example, BW Ideol has signed an agreement with Ardersier Port Authority to manufacture concrete substructures for floating wind projects. Here and elsewhere, companies are partnering to make the most of opportunities. In Wales, energy company RWE is partnering with Associated British Ports and the Port of Milford Haven to scale up port facilities for floating wind in the Celtic Sea. Ultimately, those in the industry know only too well that port infrastructure is the biggest barrier to deploying floating offshore wind rapidly at scale. With limited options for building suitable port infrastructure, the companies who are first out of the blocks may well win the race – not only securing the few available facilities but also building and retaining knowledge that will keep them ahead of their competitors.

Capturing green opportunities Carbon capture and storage or utilization (CCS/CCU) is a key strategy that businesses can adopt to reduce their CO2 emissions. By selecting the right technologies, pressing climate change mitigation targets can be met while benefitting from new revenue streams. Sulzer Chemtech offers cost-effective solutions for solvent-based CO² absorption, which maximize the amount of CO2 captured and minimize the energy consumption. To successfully overcome technical and economic challenges of this capture application, we specifically developed the structured packing MellapakCC™. This packing is currently applied in several leading CCS/CCU facilities worldwide, delivering considerable process advantages. By partnering with Sulzer Chemtech – a mass transfer specialist with extensive experience in separation technology for carbon capture – businesses can implement tailored solutions that maximize their return on investment (ROI). With highly effective CCS/CCU facilities, decarbonization becomes an undertaking that can enhance sustainability and competitiveness at the same time.

Bahzad Ayoub, Westwood Global Energy Group, UK, details how the tensions in the offshore wind industry must be addressed in order to accelerate the pace of growth, focusing on turbine OEMs as well as turbine transport and installation companies, suggesting that co-operation is the only way for the industry to succeed.




t has been a turbocharged 36 months for the offshore wind sector, with over 30.6 GW of capacity brought online. The rapid growth of the industry, combined with governmental net zero targets and support for the sector, has increased the confidence of offshore wind project developers. As a result of this, over 46 GW of capacity have been sanctioned between 2019 - 2021, representing a 117% increase relative to 2016 - 2018. In addition to this, Westwood projects over 218 GW of capacity to be installed between 2022 - 2030 outside of Mainland China.

Developers taking bigger risks To get access to this growing market, developers have been willing to make bigger bets. As an example, option fees for the offshore wind Leasing Round 4 in England surpassed initial expectations, with the average option fee at over £108 000/MW. Aside from paying higher prices for lease areas, (near) zero-subsidy bids to develop projects in countries such as Germany and the Netherlands are starting to become more common. More recently, Denmark selected the winning bidder to develop the Thor wind farm using a lottery draw, as more than one bid came in at a price of DKK0.01/kWh. These investments are being made even though some developers have recently faced financial headwinds from their offshore wind portfolios. In 1H21, both Orsted and RWE reported that lighter wind speeds had affected their overall offshore wind profits, whilst Equinor reduced its expected offshore wind rate of return from between 6% and 10% to between 4% and 8% (excluding farm downs).

Supporting a cyclical market An effective supply chain is essential to delivering the growth and return expectations of the wind industry. The cyclical nature of constructing offshore wind farms – typically driven by the timing of leasing rounds – makes this more difficult, as the supply chain must deal with peaks and troughs (when it comes to awarding EPCIC spend). The inconsistency in the way in which supply chain companies are winning work is resulting in the bottom line of some companies to rise and fall in accordance with the lumpy nature of how projects are being developed. Increasing competition within the supply chain, cost inflation from raw materials, and rising energy


prices, coupled with the cyclical nature of the market, means that today there are several sources of cost pressures that the supply chain is facing.

Local content uncertainty adds complexity Offshore wind local content policies are a key tool being used by governments to help increase domestic employment, stimulate the economy, and create a national supply chain that can provide goods and services to wind farms that are being constructed in their respective nations. The UK government has launched a consultation that aims to make changes to the Contracts for Difference (CfD) subsidy scheme to boost local supply chains. Taiwan’s Ministry of Economic Affairs has also set several local content rules for the third round of Taiwan’s offshore wind auction. Turbine OEMs are noticeably looking to set up shop locally in select countries to access local and regional opportunities. Siemens Gamesa and GE have both announced plans to construct offshore wind blade manufacturing facilities, with the former committing to constructing their facility at the Portsmouth Marine Terminal in Virginia, US, and the latter investing in a facility in Teesside in the Northeast of England. Aside from equipment-based local content policies, vessel-specific policies can have a direct impact on turbine transport and installation (T&I) companies. In Taiwan, the local content rules for the third round of auctions state that locally flagged vessels should be used, if not, the vessels should be owned by locally registered companies with local content of more than 50%. The Jones Act in the US has also created its own uncertainties and complications for the turbine T&I sector. An example of this reaction to the Jones Act is Eneti’s recent cancellation of its plans to construct a Jones Act compliant wind turbine installation vessel (WTIV) in the US, instead focusing on its current fleet and project commitments. Collectively, these policies create a further layer of complexity and will likely add financial pressure on developers and the supply chain. Companies will be forced to take decisive steps to optimise their asset base to access local/regional opportunities.

Turbine OEMs: future challenges ahead The combination of developers taking bigger risks, the cyclical nature of the industry, and a greater demand for localisation is a challenge that all stakeholders need to manage to successfully deliver. The performance of turbine OEMs is closely watched as an indicator of the health of the industry. The three major wind turbine OEMs (Siemens Gamesa, GE, and Vestas) have faced financial difficulties, with Siemens Gamesa and GE’s Renewable Energy segment announcing losses in the 3Q21 and 4Q21. Vestas has done comparatively better than the other two OEMs, but nevertheless their profits declined even though y/y revenues increased. However, it is primarily the (much larger) onshore wind business of these companies that have created the



difficulties. Siemens Gamesa’s onshore business has, for example, been affected by ramp-up challenges with regards to its 5.X onshore turbine platform. This has resulted in some necessary design changes, impacting production and the schedule for executing projects. Meanwhile, GE’s onshore wind business in the US was impacted by the expiry of US production tax credits (PTC) in 2021, creating uncertainty resulting in project delays and deferral of customer investments. Siemens Gamesa has been keen to stress that its offshore business is “profitable and growing”. While it is important to acknowledge that the current financial predicament of turbine OEMs may not be attributed to their offshore wind turbine segments, these OEMs would likely exercise company-wide cost discipline, potentially looking at ways to increase profitability via their offshore segments. More broadly, the difficulties in the onshore business are a case study in how things can go wrong. A focused and disciplined growth strategy will be key. A potential future difficulty that the three major turbine OEMs could face is the influx of Chinese players entering the offshore wind market. MingYang has begun making moves outside of Mainland China, with its first turbine already installed at the 30 MW Taranto wind farm offshore Italy. Adding to its international orderbook are contracts to supply a total of three MySE 3.0 MW typhoon-proof turbines in Japan, and a 11 MW hybrid turbine for an unnamed floating wind project in Europe. Aside from supplying directly to European wind farms, the Chinese Turbine OEM has shown intent to set up a factory in Europe to strengthen its presence in the region, with the signing of a Memorandum of Understanding (MoU) with the UK’s Department for International Trade (DIT) to explore investing in a blade manufacturing factory, a service centre, and possibly a turbine assembly factory. Should MingYang successfully entrench themselves in the international market, the three major turbine OEMs will need to contend with a new normal of diluted market share and even more competitive pricing.

Going strong, but for how long? One segment of the supply chain that Westwood sees as doing comparatively well are dedicated turbine T&I companies, with notable examples being Cadeler and Fred Olsen Windcarrier. Certainly, financial performance has been good, as Cadeler reported a net profit margin of over 15% in 1H21. Bonheur, the parent company of Fred Olsen Windcarrier, announced in their 3Q21 results that its Wind Service segment, which includes Fred Olsen Windcarrier, registered an EBITDA margin of 25% in comparison to 18% in 3Q20. The core solution on offer by these companies is WTIVs. The versatilities of WTIVs, primarily used in installing turbines and occasionally installing foundations, has spurred more new-build WTIV orders compared to only five heavy lift crane vessel orders. Demand for WTIVs has resulted in an acceleration in investment in WTIV assets, both in terms of new orders as well as vessel upgrades.

A total of six WTIVs are expected to be upgraded; five of these upgrades have already been confirmed, with the final one being an option. Most of these upgrades are scheduled to be completed between 2023 - 2024, coinciding with offshore wind projects that will begin installing turbines with rated capacities of more than 13 MW. Outside of these vessel upgrades, a total of 12 WTIVs are currently on order (outside of Mainland China), with a further Figure 1. Wind turbine installation vessel (WTIV) deliveries excluding Mainland China orders. three currently under letters of Source: Westwood WindLogix. intent (LOI)/option agreements. Some of these new-builds will be designed to be future-proofed, and broadly power-to-X. These developments present real they will be capable of installing turbines with ratings up to opportunities for the supply chain but will also come with 20 MW. their own set of challenges. Although the current market for turbine T&I companies There are several uncertainties on floating wind appears very positive, the sustainability of their profits and hydrogen/power-to-X, including the pace at which remains a question. As cost pressures increase in the industry, these markets will grow and when the development of and local content bites – both developers and turbine OEMs commercial scale projects will begin. This creates further will look at ways to manage their risk, resulting in pressure difficulties for the supply chain, as they currently do not being placed down the supply chain and potentially affecting know how much investment will be required and when turbine T&I companies. investment decisions will need to be finalised. A review of 2018 - 2021 turbine installation awards shows Therefore, companies will need to invest ahead of the that 64% of turbines (outside of Mainland China) were curve and continue innovating to ensure that they are ready awarded by project developers and 27% of turbines were to take advantage of the opportunities once these markets awarded by turbine OEMs. This shows that both segments of evolve to a commercial level. the market can play a role in exerting pressure on turbine T&I companies. Collaboration to succeed However, any proposed reallocation of risk must be The offshore wind industry is set to explode in the next strategically considered by developers and OEMs, as decade, and is constantly evolving to deliver that growth, reductions in the profitability of turbine T&I companies may taking on more risk and at the same time becoming more cause longer-term harm. Based on the development pipeline, complex. Tensions are rising whilst trying to balance Westwood projects that potential shortages of available delivery, profitability, and creating local economic value. WTIVs could occur either by 2025 (taking into consideration Other renewable industries have experienced and continue only firm orders) or by 2027 if LOI/options are exercised. to experience similar pressures – highlighting the need to In addition to the current order book, more WTIV plans act sooner rather than later. have been announced. Havfram and J.P. Morgan joint Therefore, the industry needs to carefully manage that venture have an LOI in place with CIMIC-Raffles to build a balance going forward. It is important that all companies series of WTIVs, with delivery of the first one expected by involved in the development of offshore wind farms work 2024. Should these plans materialise, the supply tightness together, rather than place pressure on each other, to may kick in by 2029. To avoid a shortfall of available ensure that capacity targets can be met. A collaborative vessels, which could significantly push back development approach will help to reduce the current supply chain targets and have longer-term financial impact, developers tensions – ensuring all can benefit from the sector’s growth. and turbine OEMs will need to take a balanced approach Additionally, government bodies must play an active role towards implementing any cost pressures on the turbine T&I in ensuring that future policies do not hinder continued sector. growth. This highlights the importance of industry groups and other bodies that can bring diverse stakeholders together, Positioning the supply chain for the future as well as the importance of transparency to help solve the Offshore wind technology has been evolving at a rapid issues faced by the offshore wind sector. pace, to which the supply chain has adapted. Future opportunities are now evolving in the industry through the development of floating offshore wind, as well as the Note coupling with other markets – such as hydrogen and more Data accurate as of 28 February 2022.



Thomas Raiser (Switzerland) and Ramnik Singh (US), Global Biobased and Renewables G the production of biofuel, outlining the key aspec



he refining of crude petroleum owes its origins to the successful drilling of the first oil wells in Ontario, Canada and in Pennsylvania, US, in the 1850s. A petroleum refinery depends on crude oil as its main feedstock to produce liquid fuels and chemicals. In the long-term, this dependency is threatened by the depletion of crude oil reserves. In the short-term, the price volatility of petroleum products, due to factors such as regional and global geopolitical instability, is causing additional

Group at Sulzer Chemtech Global, discuss the transition from petrorefining to biorefining for cts that should be addressed to enable this shift. challenges in refinery production. The petroleum refining industry is also under pressure, due to its direct and indirect impact on the environment. Clearly, there is a need for a feasible, sustainable, and environmentally friendly generation process for fuels and chemicals. An oil refinery, or petroleum refinery, is an industrial process plant where crude oil is transformed and refined into fuel products, such as gasoline, diesel fuel, fuel oils, heating oil, kerosene, liquefied petroleum gas, and naphtha. In addition to fuels, petrochemicals



feedstock such as ethylene and propylene can also be produced directly by cracking crude oil. Oil refineries are therefore typically large industrial complexes with chemical processing units, such as fractional distillation columns, and use much of the technology as in chemical plants.

Figure 1. A biorefinery is generally defined as a renewable mirror of a petroleum refinery.

Figure 2. Various plant materials, collectively known as biomass, are a potential feedstock to produce substitutes for petroleum-derived fuels and building blocks for biochemicals.



Replacing fossil fuels with biofuels Fuels produced from renewable organic material have the potential to reduce dependence on unstable foreign suppliers and lower some of the undesirable aspects of fossil fuel production and use, including greenhouse gas (GHG) emissions, the depletion of non-renewable fossil fuel resources, and geopolitical dependencies. Demand for biofuels could also increase farm income by utilising locally grown renewable feedstocks. Analogous to petrorefining, the concept of biorefining is emerging. A biorefinery is generally defined as a renewable mirror of a petroleum refinery, where a variety of fuels, chemicals, and power are produced from one source. The characteristics of the modern biorefinery are parallel to the petroleum refinery: an abundant raw material, consisting primarily of renewable biomass, enters the biorefinery and is converted into fuels, biochemicals, and direct energy. While there are similarities between the biorefinery and the petroleum refinery, there are also important differences. For example, there is more oxygen present in bio-based chemicals, which leads to opportunities for production of certain organic products. Separations are as critical for the biorefinery as they are for the petroleum refinery. Bioprocess separations costs can account for up to 50 - 70% of processing costs. Various plant materials, collectively known as biomass, are a potential feedstock to produce substitutes for petroleum-derived fuels and building blocks for biochemicals. Biomass is abundant and currently is still low in utilisation. Unlike other renewable energy sources, biomass can be converted directly into liquid fuels, called biofuels, to help meet transportation fuel needs. The two most common types of biofuels in use today are ethanol and biodiesel, both of which represent the first generation of biofuel technology. Ethanol is a renewable fuel being produced from biomass. Ethanol is used as a blend with gasoline to increase octane, and reduce carbon monoxide and other emissions. The most common blend of ethanol is E10 (10% ethanol, 90% gasoline) and is approved for use in conventional gasoline-powered vehicles. Furthermore, ethanol can be used as an intermediate for the production of green polyethylene and esters. The vast majority of ethanol is currently made from plant starches and sugars; particularly corn starch in the US, but technologies are being developed and enhanced that would allow for the use of cellulose and hemicellulose, the non-edible fibrous material that constitutes the bulk of plant matter. Biodiesel is a renewable, biodegradable, cleaner burning fuel manufactured from an increasingly diverse mix of feedstocks, such as various vegetable oils, waste animal fats, or recycled cooking oil. Biodiesel is a liquid fuel often referred to as B100 or neat biodiesel in its pure, unblended form. B100 biodiesel can be directly used in existing diesel engines or can be blended with regular diesel, such as B5 and B20, for use in colder climate areas. Biodiesel is made through a chemical process called transesterification whereby the glycerin is separated from the fat or vegetable oil. Currently, ethanol and biodiesel plants are mostly standalone facilities near their feedstock plantations. The biorefinery is still lacking in competitiveness compared to a

petroleum refinery. The paradigm-shift from the oil-based to the renewable resources-based economy must be supported by not only research and development but also by higher-efficiency separation processes. The petroleum industry has improved separation efficiencies over the decades by taking advantage of advancements in mass transfer technologies, such as column internals: distributors, trays, and types of packing materials – structured, random packing, and column supports etc. Sulzer Chemtech has pioneered advancements in these internals since the 1960s with the development, design, and production of packings to find the optimum solution for a variety of applications, including a new structured packing for absorbing CO2 more efficiently from flue gas streams of fossil-fuelled power plants. Distillation is the most commonly applied separation technology. It is critical that the design of these unit operations provides an improved product quality, increased capacity, and lower energy consumption. Design activities are supported by computer simulations, proprietary sizing tools, and pilot plant testing. The simulation models developed from the refining and chemical industries are continuously improved with new empirical data from biofuel and chemical process streams. To improve efficiencies, process intensification techniques, such as extractive distillation, azeotropic distillation, reactive distillation, membranes, and divided wall columns, are being utilised. Similarly, higher energy efficiencies are achieved with heat integration and heat pumps, such as mechanical vapour compression (MVR) technologies.

An attractive solution that addresses both is the integration of bio-feedstock and existing petroleum refineries. Renewable diesel has become the leading alternative as companies invest in a more environmentally conscious energy supply. Completely fungible with petroleum diesel, renewable diesel from biomass-based feeds has lower sulfur and higher cetane than its petroleum-based equivalent and can be used without modification to existing infrastructure. Hydroprocessing units that generate either hydrogenated vegetable oil (HVO) or sustainable aviation fuel (SAF) use bio-based feedstocks from one of three categories – fats, oils, and greases (FOGs). For example, BioFlux® pretreatment technology, developed by Duke® Technologies and licensed by Sulzer Chemtech, is an alternative process designed to economically treat FOGs and enable more efficient hydrotreating operations. Biomass-based FOGs are thermally cracked using conventional refiner equipment and processes.

Conclusions For biorefineries to compete with petroleum refineries, a number of aspects should be addressed. Process intensification, modularity to reduce plant footprint, higher energy efficiency, reduced water usage, including water reclamation, as well as carbon capture and utilisation are some of the key areas where further developments and continuous process improvements are essentials for the success of the emerging bioproducts industry. Utilising some of the already proven separation technologies with a scale down approach will help to reduce the risk of scaling up from small scale for the new bio-based technologies.

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Maria Anez-Lingerfelt, PhD, Pall Corporation, US, outlines the ways in which biofuels can aid the switch to increased renewable energy production, helping to reduce the world’s reliance on fossil fuels.


he need for sustainable energy is accelerating on several fronts. The war in Ukraine has highlighted the precarious availability of fossil fuels and prompted a rethink by many countries of the places from which they are willing to source vital fuels. Additionally, rising oil and gas prices have seen the cost of living soar to the detriment of consumers and businesses alike. Although biofuels are complex and currently more expensive to produce than traditional petrochemicals, it is important to look at how to make the processing of them scalable and more cost-effective. Making biofuels a key part of a wider renewable energy strategy offers the opportunity to reduce reliance on fossil fuels and move towards a greener future. Even though many would agree that biofuels are pivotal to the energy transition, there is little consensus on how to make them commercially viable. There is considerable debate around optimal bio-feedstock and the best way in which to process, deliver, and use them. Concerns are also raised over the cost of production and amount of resulting useable energy when compared to fossil fuels. Technological developments can unlock this conundrum, but more investment is needed in existing solutions, such as filtration, to optimise biofuel processing and to support the scale-up of production to truly industrialised levels.

A complex regulatory landscape There are differing perspectives on what the current situation is, and how to transition to a better energy future. When launching the latest report from the Intergovernmental Panel on Climate Change (IPCC) in April, the UN’s Secretary General, António Guterres, criticised governments and corporations that have impeded climate change reduction measures and increased fossil fuel production because of vested interests. He said that choices made now will “make or break” the commitment to limiting global warming to 1.5˚C above pre-industrial levels. He also stated that investing in renewables would be vital for the global energy mix, and would offer hope to millions of people adversely affected by climate change. In the spring, German MEP, Markus Pieper, put forward several draft amendments to the EU’s Renewable Energy Directive (RED II). He proposed increasing the proportion of energy from renewable sources to 45% by 2030 – up from the current target of 40%. He also urged for more biofuels in transport, an introduction in innovation quotas for the development of renewables, and the removal of a ‘cascading’ principle which limits the availability of biomass. North America has a range of financial stimuli. In the US, there are a raft of federal tax incentives for qualifying renewable energy projects or equipment, including the renewable electricity production tax credit, the investment tax credit, and the residential energy credit. Meanwhile, the Canadian government provides provinces and territories




with funding to administer projects via the low-carbon economy fund. In the UK, the British energy security strategy focuses on increasing offshore wind, reinvesting in nuclear power, and doubling the government’s ambition for low-carbon hydrogen production. Whether by legislative directives or financial impetuses, new measures are being sought in many nations to decarbonise and create a greener future.

Choosing the right biomass The International Energy Agency (IEA) shows that in 2021, global CO2 emissions were split by sector as power generation by coal (29%), industry (23%), transport (23%), buildings (10%), gas (9%), oil (2%), and other (5%). The IEA also forecasts that demand for biofuels will increase 28% from 2021 levels to 2026. Although discussions on renewable energy often centre on wind, solar, and hydropower, biomass as a source accounts for 97% of global renewable heat production and 11% of global renewable electricity production according to the World Bioenergy Association’s Global Bioenergy Statistics 2021 report (based on 2019 figures). Production of biofuels from biomass certainly supports changing energy requirements and emissions standards, but there are challenges to consider, both from environmental concerns of the varying source materials to the way in which they are processed. As a feedstock, biomass varies greatly: it encompasses plants such as edible crops, wood, grass, and other non-edible plant material, known as lignocellulosic biomass (LCB). It also includes non-plant material such as animal waste, residential waste such as used cooking oil, commercial/industrial waste, and algae – non-lignocellulosic biomass (NLCB). It is no wonder there are myriad considerations. If crops such as corn, soy, and sugar cane/beet are grown to be used as a first generation biofuel, their cultivation limits the availability of agricultural land for food production and may be a drain on regional water sources. Additionally, focusing on monoculture or planting genetically modified crops to provide greater yields compromises biodiversity. As such, the use of non-edible plants or waste materials to produce second generation (advanced) biofuels provides a greater contribution to sustainability.

Pre-treatment is the first step The differing molecular composition of wood, non-edible plants, and waste materials leads to varying levels of solid particulates, water content, gels, and waxes, as well as variable particle size, density, and viscosity. Where these materials are processed together in a refinery, volumes of each within the overall mix may differ, depending on the available supply. Pre-treatment is usually required to structurally alter the biomass into a more consistent form before processing, with minimal degradation to vital components. This can involve physical, chemical, or biological processes, and the method used should be tailored to the biomass source. Physical pre-treatment may be done by milling or chipping to reduce particle size and increase the overall surface area, thereby enabling greater access to enzymes to break down the cellulose into glucose. However, this is an energy intensive process and does not remove all the lignin content (complex polymers in plant cell walls). Microwave irradiation and steam explosion may also be employed. Chemical pre-treatment can use alkali or acid additions. Alkali bases increase internal swelling of the biomass to decrease polymerisation and generate lignin breakdown. Acid hydrolysis can improve enzymatic hydrolysis of lignocellulosic material to release fermentable sugars. Biological pre-treatment involves the use of microbes or enzymes – such as from fungi – to break down the lignin particles and depolymerise the cellulose. This is beneficial in that it produces few toxic substances and does not require much energy, but the process is slow and requires a lot of space.

Technology underpins processing There are various options to process biomass into liquid biofuels or biogas, with some residual solids that can be used as fertilizer: FFTraditional hydrotreating: Involves reacting the lipids with hydrogen in elevated temperatures and pressures in the presence of a catalyst in a refinery. Commercial plants currently use this technology.

FFBiological sugar upgrading: This uses a biochemical deconstruction process, similar to that used with cellulosic ethanol, with the addition of organisms that convert sugars to hydrocarbons.

FFCatalytic conversion of sugars: Involves a series of catalytic reactions to convert a carbohydrate stream into hydrocarbon fuels.

FFTransesterification: A chemical reaction used for the conversion of triglycerides (fats) contained in feedstocks into usable biodiesel. Biodiesel produced by the process of transesterification has a much lower viscosity, making it capable of replacing petroleum diesel in diesel engines.

FFPyrolysis: Involves the chemical decomposition of organic

Figure 1. Biodiesel production.



materials at elevated temperatures in the absence of oxygen. The process produces a liquid pyrolysis oil that can be upgraded to hydrocarbon fuels, either in a standalone process or as a feedstock for co-feeding with crude oil

into a standard petroleum refinery. Syngas may also be produced.

FFHydrothermal processing: Uses high pressure and moderate temperature to initiate chemical decomposition of biomass or wet waste materials to produce an oil that may be catalytically upgraded to hydrocarbon fuels.

FFGasification: During this process, biomass is thermally converted to syngas and catalytically converted to hydrocarbon fuels.

Co-processing optimises the value chain Where conversion of biomass into biofuels is done in existing refineries, this is termed co-processing. Many refineries operate below their capacity, making co-processing a viable option to meet sustainability goals and maximise production without making expensive investments in refining assets. Most co-processing happens in hydrotreaters, hydrocrackers, or fluid catalytic crackers. These catalytic processes remove sulfur, oxygen, nitrogen, and metals. It is critical to remove sulfur as this reduces SOX emissions when fuels are combusted; sulfur also poisons downstream noble metal reformer catalysts (<0.5 ppm S is a typical naphtha feed spec). This clean-up also saturates olefins to yield easier-to-process intermediates. The reaction is carried out in a hydrogen-rich environment over a fixed catalyst bed, and the replacement of sulfur or nitrogen contaminants with hydrogen makes the process a

Figure 2. Biofuels power plant with wood biomass.

Figure 3. Biomass processing plant.



consumer of hydrogen. Protection of the heat exchangers and catalyst beds from fouling is critical to maintaining long-term hydrotreating efficiency. Treated products are then stabilised with heat to remove hydrogen sulfide and light ends. Use of direct steam injection is common.

Why is filtration critical to biofuel production? Despite pre-treatment, biomass tends to degrade during transportation and storage. These particulate impurities and gels can cause severe damage to downstream equipment if left unfiltered. In addition, biomass typically contains an abundance of oxygen that gets converted into carbon monoxide, carbon dioxide, and water during hydroprocessing. Depending on the type and proportion of the feedstock inserted into the refinery for the production of liquid biofuels, the volume of gaseous products and moisture generated may differ significantly and impact refinery operations. Some of the challenges include: pressure build-up over the catalyst bed and heat exchanger; additional hydrogen demand; higher gas treatment and removal capacity required; and removal of additional co-produced water. The increased risk of moisture and contamination in catalysts and critical equipment due to biomass processing may lead to frequent downtime to repair or replace these expensive pieces of technology. In addition to solid particulate removal, separation of water from the final biofuel product is an essential step in the biofuel refinery process. To achieve premium diesel quality, Pall liquid/liquid coalescers can be installed downstream of the hydrotreater to separate and remove water content to an acceptable level. For example, a major EU producer of biodiesels and sustainable aviation fuels (SAF) uses Pall Aquasep XS liquid/ liquid coalescer filters to polish the refined biodiesel product to an acceptable water content specification of <100 ppm. The coalescer media agglomerates water molecules as the biodiesel flows through it, creating larger water droplets that can be separated from the feed fluid. The dense coalescer media provides optimum separation capacity (typ. ≤15ppm separation level achievable), protected by appropriate particulate pre-filters that can retain the gels and waxes that might otherwise blind and therefore reduce coalescer performance. The production of biogas happens through anaerobic technology and consists mainly of methane and carbon dioxide. However, it can also contain small amounts of hydrogen sulfide, siloxanes, and moisture, all of which can have a detrimental effect on the production process. To maximise methane output and protect critical equipment such as compressors and membranes, it is important to eliminate as many impurities as possible through particle filtration and liquid/gas coalescence methods. Without efficient filtration and separation technologies, heavily contaminated gases can lead to compressor corrosion, abrasion in moving parts, and degradation of purification units. In the processing of both liquid biofuels and biogas, investing in an efficient, high-quality filtering system is essential to protect downstream equipment and to ensure installations run smoothly with less downtime. Where poor filtration and

separation choices are made, these may lead to million-dollar adverse consequences.

Increasing filter service life and meeting new biofuel specifications The Indonesian government introduced a mandate for diesel to contain at least 30% biofuel, to reduce its emissions, and boost its production of palm oil. As a result, one Pall refinery customer found that with the increased biofuel content, its filter service life reduced to one week. Working with the Figure 4. High performance filtration technology is key to biofuel production. customer, Pall developed a new filtration solution based on its Ultipleat High Flow filter design, which doubled the filter service life and Syngas – a mix of carbon monoxide and hydrogen – can met required cleanliness targets. The filter’s crescent-shaped be applied to many of the same uses as biomethane, in either pleat geometry, combined with its large 152.4 mm (6 in.) dia. hot or ambient temperatures. For ambient temperatures, the and proprietary range of available Pall filter media ratings, process of cooling pyrolysis gas and separating condensable allows customers to use significantly fewer filters and smaller and non-condensable phases requires additional energy to housings for high flow-rate applications. reduce stream temperatures. In this respect, syngas under ambient temperatures is easier to transport and offers a wider The applications of advanced biofuels scope for further treatment, allowing separation of molecules Processing produces liquid biofuels (bioethanol and biodiesel) and their additional utilisation. and biogas, each of which can be used as an alternative to fossil fuels or added as drop-in fuels to mix with the traditional fuel, depending on capabilities and statutory guidelines. Selecting the best filter media for Bioethanol is used in internal combustion engines and hydrotreating can be mixed with petrol to any percentage. It has a 34% A US refinery was using Pall’s Vector filters in the hydrotreating lower energy density than petrol, so more needs to be used to of melted beef tallow and soybean oil to produce HVO diesel. achieve the same level of energy; but it has a higher octane The customer wanted to increase production and so needed rating, meaning that ethanol-driven engines can be designed greater filtration capacity. Pall scientists evaluated both for higher thermal efficiency with better performance and process and performance to establish the best filter media less energy wastage. Analysis by the US Department of solution to arrive at a balance of acceptable filter service Energy found that on a lifecycle basis, greenhouse gas (GHG) life and consistent downstream asset protection (protection emissions are reduced on average by 40% with corn-based of the heat exchanger and extended catalyst life). Pall’s ethanol, and range between 88% - 108% if cellulosic feedstocks polyester Vector High Flow in an 80 in. length, 1-μm rating, with are used – depending on feedstock type – compared with increased temperature capacity of 100˚C (212˚F) was applied petrol and diesel production and use. downstream of the original 25 μm-rated filter. This enabled Biodiesel can be used in its pure form (B100) or blended the customer to increase production capacity and maintain with petroleum diesel in the form of B2 (2% biodiesel, 98% predictable, reliable operation. petroleum diesel), B5 (5% biodiesel, 95% petroleum diesel), or B20 (20% biodiesel, 80% petroleum diesel). One of the main On the path to greater sustainability advantages is that it can be used in existing diesel engines There are examples in many industries of how a willingness without the need for modifications; additionally, it increases to do more is yielding benefits. According to the International engine life as it is virtually sulfur-free. And experts believe that it Air Transport Association (IATA), the mixing of biofuels with a can reduce GHGs by up to 78%. However, biodiesel gels in cold petroleum-based jet fuel to produce sustainable aviation fuel weather, making it more difficult to start engines. This also can reduce emissions by up to 80%, particulates by up to 100%, means that it cannot be transported in pipelines, so has to be and sulfur by 90%. This is a great step forwards until electric conveyed by rail, lorry, or barge. flight by fully renewable energy sources is commercially viable. Biogas – often called biomethane – can be used as direct Every sector has to do more to enhance decarbonisation combustion for heating, cooking, and heating water. It can and reduce emissions, and the conversion of biomass into also be used in fuel cells to produce electricity, in internal biofuels is a key pillar for progress. Challenges on availability combustion engines, and, if suitably cleaned from filtration, of bio-feedstocks remain, along with the volumes of energy injected into existing gas pipelines and used for lighting and to required in the production processes. But the use of technology make steam via turbines. Additionally, via a catalytic chemical and practical solutions, such as filtration of biomass, must oxidation, methane can be used in the production of methanol increase to enable the scaling up of biofuel production to help and thereby to power cars, buses, trucks, and ships. meet climate change goals and enhance global security.



Florian Gruschwitz, MAN Energy Solutions, Germany, considers the potential of power-to-X and green fuels, and the role they will play in the ramp-up to a green hydrogen economy.


here is no doubt that green hydrogen is a key element on the path to decarbonisation. Nor is there even the least surprise these days that green hydrogen – and power-to-X in general – has gained so much popularity and public attention. For good reason, this will not be a flash in the pan. Strong drivers, such as the EU’s Fit-for-55 programme, underline the reality that decarbonisation has now become a serious target and many countries have already published ambitious hydrogen strategies. Companies such as MAN Energy Solutions can


already provide the necessary, key technologies along the power-to-X and green hydrogen value chain and have serious skin in the game through significant investments aimed at further extending the base of necessary technologies. Mature technologies, for instance for eFuel production, are available that enable the use of existing infrastructure, but much remains to be done in order to create more viable business cases. It can be shown how derivative fuels, or eFuels, can successfully complement green hydrogen in its elemental form and be an important enabler in the ramp-up to a green hydrogen economy.



One thing is clear: elemental green hydrogen will not be a one-fits-all solution. Instead, there will be a multi-option scenario where pragmatic approaches will aim at maximum efficiency, whilst at the same time ensuring that a solid base and ramp-up path for long-term transition to green hydrogen is created. To get the full picture, it is helpful to look at the topic from two perspectives: firstly, viewing power-to-X in the context of how it can play an important role in reaching decarbonisation targets; and, secondly, looking at the main hurdles – but also success criteria – in getting a green hydrogen economy ramped up at a global level. If it is agreed that decarbonisation is an underlying imperative in order to save the planet, then a policy comprising four elements can be identified, beginning with replacing fossil-fuelled power generation with renewable energy sources. The use of green hydrogen and employing eFuels (based on green hydrogen) are two further elements. And the fourth – for the hard-to-abate carbon sources – is carbon capture and storage technologies, again combined with power-to-X technologies. These four elements may be viewed as a type of ‘decision tree’ such that, when addressing an application that acts as a considerable carbon source today, all four means of decarbonisation need to be assessed in the order described to find the best fit – i.e., the most effective way to achieve decarbonisation considering all current boundary conditions. Needless to say, decarbonisation is reliant upon an abundant availability of renewable energy. Accordingly, extending the capacity of renewable energy generation is of paramount importance. The first question in the quest for decarbonisation is then: is direct electrification possible? This means, first of all, replacing all fossil-fuelled power generation with renewable energy. However, natural-gas-fuelled power plants, for example, may be tolerated as back-up or peakers as they facilitate the maximum use of renewable energy in the grid while simultaneously ensuring maximum reliability and grid stability. Continuing through the decision tree, for applications that cannot be directly electrified as of yet or even in the longer-term, the use of green hydrogen could be a good option, and many examples exist. However, following the Pareto principle, some prominent areas especially suited for decarbonisation can be identified, such as steel production where production with green hydrogen instead of coal would cut carbon emissions considerably. Another good example of a sector ripe for decarbonisation with green hydrogen is within processes that already require large amounts of hydrogen today. Here, grey hydrogen is currently used and produced by steam reformation with natural gas. One such example is fertilizer production, where ammonia as a main feedstock requires large amounts of hydrogen. Which leads us to the third stage in the decision tree when neither direct electrification nor the use of green hydrogen as a molecule is possible. In such instances, eFuels may be a solution. Derivative fuels or eFuels in this context are carbon-neutral fuels based on green hydrogen. This includes synthetic methane, methanol, or e-Kerosene – or ammonia produced from green instead of grey hydrogen, which provides a carbon-free option.



As such, derivative fuels could play an extremely important role, acting as a bridge technology and replacing their fossil twin, leading to carbon-neutrality, as a carrier medium for green hydrogen, or even as green feedstock as for the prior-mentioned green ammonia for fertilizer production. One of the great advantages in derivative fuels is their direct applicability today.

A power-to-X solution Next is a detailed look at the technologies that are available today. MAN has consistently developed power-to-X technology and offers turnkey plants with a capacity of 50 MW and more. The company’s power-to-X solution is a sustainable solution for synthetic fuel production and long-term energy storage. It responds to the fundamental challenges of decarbonisation. The direct use of synthetic fuels allows the decarbonisation of sectors which currently rely on fossil fuels, such as marine, aviation, or certain industrial processes. Renewable energy is used to run an electrolyser, for example a PEM or an alkaline, which breaks water down into hydrogen and oxygen. The hydrogen is then put into a methanation reactor with carbon dioxide, resulting in synthetic natural gas (SNG). The carbon dioxide can be obtained either by carbon capture from in-house or adjacent industrial processes or power generation using amine scrubbing, pressure swing absorption, or membrane separation. The SNG can be stored, used directly, or injected into the existing gas infrastructure.

Hydrogen production by electrolysis PEM electrolysis is a process by which electricity is used to split water into hydrogen and oxygen. It consists of a proton-permeable membrane, a cathode, and an anode. When water is added to the electrodes, the external voltage causes a catalytic effect, splitting the water. The hydrogen ions diffuse through the membrane. To generate 1 kg of hydrogen, approximately 8.9 kg of water is required. In addition, approximately 7.9 kg of oxygen with a purity of 99.95% is produced. This corresponds to the purity required for further use in technical and medical applications. Water of tap water quality is required for electrolysis. The power requirement for 1 kg of green hydrogen is approximately 53 kWh. H-TEC SYSTEMS is a subsidiary of MAN Energy Solutions and currently offers electrolysers with a nominal electrical output of up to 1 MW. All H-TEC SYSTEMS solutions are integrated, scalable, and containerised. An electrolysis capacity of 1 MW provides enough hydrogen to fill a car tank up to 90 times/d in a 24-hour operation period. These module sizes are particularly suitable for pilot projects and small industrial customers. The electrolyser consists of 110 kW stacks, which can be replaced if necessary, thus extending the service life of the plant. The maximum total electrolysis capacity is currently 10 MW, but will be expanded to 150 MW in the future with the new product Hydrogen Cube Systems (HCS). These are 2 MW modules which make it possible to cater to applications with a high hydrogen demand. H-TEC SYSTEMS electrolysers have an integrated water treatment and deionisation system. Therefore, only water

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Figure 1. Electrolysers from H-TEC SYSTEMS at a wind farm in Northern Germany. Image courtesy of H-TEC SYSTEMS.

that meets industrial standards (tap water) is necessary as a feedstock for electrolysis. In arid areas, additional water generation may be necessary e.g., with desalination plants.

Synthetic natural gas production by methanation Methanation, or the Sabatier process, is a chemical reaction in which carbon dioxide Figure 2. On the left, hydrogen use by production type, and on the right, hydrogen use by is converted into synthetic methane. It is an region. Source: BP Energy Economics 2020. exothermic reaction that has to be accelerated by nickel catalysts. The chemical efficiency is approximately 83%. From 1 kg of H2, approximately 2 kg of SNG and 4.5 kg of water are produced with the addition of CO2. This is a chemical reaction that takes place without additional energy in the form of electricity. The equipment associated with the methanation reactor, such as pumps, requires electricity, so a total of approximately 27.3 kWh is required to produce 1 kg of SNG. The reactor is a boiling water reactor in which process temperatures range from 270˚C - 600˚C. The process by-products are water and saturated steam at a temperature of 270˚C. If this is integrated into other production processes, the methanation process can achieve an overall efficiency of 95%. The outlet pressure is 20 bar(g). Two reaction stages are necessary for high methane Figure 3. PEM electrolyser by H-TEC SYSTEMS. Image courtesy of purity (>95%) in MAN methanation technology. This is due to H-TEC SYSTEMS. the thermodynamic equilibrium that occurs between the two



reaction sides. Water is separated in an intermediate stage between the two reaction stages. This means that, in the second stage, the equilibrium is shifted further to the product side and thus the highest gas purity can be achieved. Since this is an exothermic reaction, external cooling is necessary to allow the chemical process to proceed in a controlled manner. There is no risk of damage to the equipment due to excessive temperatures. In addition, cooling influences the thermodynamic equilibrium in a positive manner and thus contributes to the final high product purity. Continuous cooling increases efficiency (a greater mass of reactants can be converted into products), requiring a smaller reactor and less catalyst material. The overall system is more compact than adiabatic process concepts, which require a total of three to five process steps with intermediate cooling to achieve a methane purity of >95%.

Figure 4. Model of a complete 50 MW power-to-gas plant by MAN Energy Solutions.

The challenges In conclusion, a carbon-neutral world – the desired net zero – to avoid further climate change is within reach and without having to completely change the world, the products used, nor the way of life. Green hydrogen and power-to-X are key elements in this transition. The question then is: how to ramp up the green-hydrogen economy? For this, the whole value chain will have to be considered: the production of green hydrogen and derivatives, its transport to its application, and of course the application itself where – as in the case of direct reduction ovens for green steel production – some considerable investments will be needed. Accordingly, all parts of the value chain need to be pushed and ramped up simultaneously. Large, industry-wide programmes such as Germany’s H2.Giga initiative are helping to scale up electrolysis to industrial levels with accompanying cost-reductions. However, the cost reduction of green hydrogen production alone does not make for a feasible business case when green fuels have to compete with their fossil twin without integrating the external cost of additional carbon introduced to the atmosphere. Thus, respective carbon taxation is needed as well as smart Carbon Contracts for Difference schemes (at least for the ramp-up phase), such as the German H2.Global, to finally make larger power-to-X projects bankable. Setting up a global hydrogen economy is necessary to leverage renewable energy potential in regions where it cannot be otherwise used and in order to not cannibalise renewable energy capacities in regions with high demand. This would also help to bring sustainable prosperity to more parts of the world, and could solve strong global (inter)dependencies in energy trading. Large scale off-takers, such as steel production, have to be created – for example, in line with EU IPCEI projects. Even if they had to rely on blue hydrogen in a starting phase, this means that investments could be made and hydrogen-pipeline infrastructures created. Subsequently, as soon as green hydrogen production is at scale, a switch to green hydrogen would be possible with all the major investments made up to that point in time. As such, it is acceptable for many of the first, large power-to-X projects to rely on derivative fuels since ocean transport of elemental hydrogen is a challenge.

Figure 5. Hydrogen costs from hybrid solar photovoltaics (PV) and onshore wind systems in the long term. Source: International Energy Agency 2019.

Going green As part of a ramp-up to a green hydrogen economy, MAN Energy Solutions’ gas-powered, four-stroke engines are H2-ready and operable in stationary mode with a hydrogen content of up to 25% by volume in a gas-fuel mix. As such, within the power-plant segment, the company’s MAN 35/44G TS, 51/60G, and 51/60G TS gas engines are now capable of exploiting hydrogen to further reduce CO2 emissions. This hydrogen-combusting capability enables the gas engines to meet Level B requirements of the European Engine Power Plants Association’s (EUGINE) H2-readiness standard. The engines can be operated with a hydrogen proportion of up to 25% by volume in the gas mixture. By 2025, the units should also be updated and capable of operation on 100% hydrogen.

eFuels can complement a green hydrogen economy, are an enabler for larger electrolyser plant setups, and can resolve the chicken or the egg dilemma until hydrogen grids become available to provide inexpensive transport, storage, and distribution options. Seen from an industry perspective, companies are ready and eager to shape the future. MAN Energy Systems is taking the risk and investing in the transformation of its portfolios and to provide the necessary technologies. Now the necessary political action is needed in order to ramp-up a global green hydrogen economy and to convert decarbonisation targets into reality.




ow-carbon hydrogen has been spoken about for years. If produced in a clean way, its properties as an energy carrier make it a good candidate to decarbonise high-emitting and hard-to-abate industrial sectors (such as steel) which cannot be electrified, as well as transport where batteries are sub-optimal or unsuitable (such as for long-distance freight, marine, or air). Hydrogen can also be stored and transported, ultimately serving as an energy commodity. Today, the ticking clock of climate change has renewed the focus. To become the world’s first climate-neutral continent by 2050 and making the European Green Deal a reality, the EU has pledged to cut its carbon emissions by 55% by 2030 compared to 1990. While existing renewable energy can get the EU part of the way, hydrogen can play a role too. Recognising low-carbon hydrogen’s potential, the EU has made low-carbon hydrogen a core part of the



European Green Deal and of Europe’s efforts to secure its energy future. As a result, political will is coalescing around hydrogen. In July 2020, the EU announced an ambitious hydrogen strategy that calls for scaling up supply and demand for green hydrogen, supporting the development of new markets and infrastructure, and establishing Europe as a leader in the hydrogen industry, a creator of highly skilled jobs. Following up on this strategy and broader climate objectives, in 2021, the European Commission announced an ambitious set of regulatory proposals to make Europe ‘fit for 55’ (referring to the planned percentage reduction in carbon emissions).

Ambroise Fayolle, Vice President of European Investment Bank, France, outlines the current political and industrial moment for green hydrogen, detailing how it could be a viable alternative energy source for Europe in the transition away from high-emitting fossil fuels.


Hydrogen projects are being included in the list of important projects of common European interest, which allows them to receive public support. These proposals and initiatives feature hydrogen in several ways, and provide further substance and backing for its development. The enthusiasm for clean hydrogen extends to the national level, where EU members such as Germany, France, Portugal, and the Netherlands have designed their own hydrogen strategies. Germany has even promised to back hydrogen development with a public budget of €9 billion. France has committed €7 billion. In several countries, innovative support schemes are emerging to encourage deployment and to mitigate the most pressing issues. Beyond these, the European Commission has also enlisted the support of industry and set up a European Clean Hydrogen Alliance to develop a pipeline of projects and help achieve the objectives of the hydrogen strategy. The Alliance brings together the industry, public authorities, and civil society to identify a pipeline of hydrogen investments. In November 2021, the Alliance announced a list of over 750 projects across Europe, representing billions in potential investment in the coming years. This underlines how much industry has also recognised the opportunity and importance of hydrogen in today’s context.

hydrogen thesis cannot be overstated – in fact, the falling cost of renewables in the past decade – which the European Investment Bank (EIB) has supported through its financing – is seen as one of the key factors that provide a sound footing for hydrogen today. Because a very large proportion of costs is linked to the electricity used for its production, the development of green hydrogen raises systemic questions about how to align low-cost production (for example, where renewable power is cheap and plentiful) with large and predictable use cases, typically in large industrial basins. Across the board, the value of carbon will be a key component to help mitigate the green premium. Ensuring that avoided carbon emissions can be monetised could make or break initial low-carbon hydrogen projects. Conversely, a higher carbon price on fossil fuel-based approaches could make a comparison more compelling for low-carbon hydrogen. In addition, the regulation governing hydrogen transport and storage may need some adaptation to incentivise investment in the necessary infrastructure. When it comes to financing, EIB’s feedback from recent investor consultations highlights that project risks, whether related to offtake certainty, technology performance, or operational risks, will need to be addressed to make low-cost financing available.

Large investments presenting challenges

In the past decade, EIB has invested €550 million specifically related to hydrogen, which has helped generate over €1.2 billion in external investments in the sector. The company’s support has focused on financing research and development (R&D) in hydrogen transformation and application technologies, as well as public transport schemes deploying hydrogen buses and rolling stock and supply/refuelling infrastructure. Today, the company’s energy lending policy focuses on decarbonisation, and features low-carbon gases such as hydrogen. EIB has approximately €1 billion of hydrogen-related projects in its pipeline, and is beginning to see industrial scale deployment projects come through its doors. EIB is nevertheless looking for more projects to finance. To this end, the company has established advisory collaborations with key industry associations, such as the Hydrogen Council and Hydrogen Europe, and national associations such as France Hydrogène or the Polish Hydrogen Cluster, to identify promising projects and facilitate access to its advisory and financing solutions. In the future, EIB wishes to support projects that expand the supply and use of hydrogen at a larger scale, and the company hopes that it will be able to do that with the right policy and regulatory framework at the EU and member state levels. Given sector challenges, the company’s technical assistance and advisory services can play a key role for these projects. Indeed, EIB can help innovators and governments put together projects in a way that can attract financing.

Getting low-carbon hydrogen usage to serve the needs of the economies and industries will require very large investments – the EU’s Joint Research Centre estimates investments required by 2050 could amount to approximately €2 trillion in a scenario of large scale renewable power capacity and electrolyser deployment. Transport, storage infrastructure, and application-level assets will also need investment. Before such investments can happen, low-carbon hydrogen needs to become more competitive against the technologies it could replace. In some use cases, renewable green hydrogen competes against fossil-based grey hydrogen. In others, hydrogen competes against natural gas. Hydrogen may also compete against completely different technologies altogether, in the case of steel production (traditional blast furnaces or electricity-based models) or transport (thermal engines, batteries). In most cases, low-carbon hydrogen tends to be more expensive. It comes with a green premium that needs to be reduced over time by scaling up the low-carbon hydrogen value chain, which may bring costs down through economies of scale and industrial improvements. While some of the core technologies are mature, innovation is likely to remain important because improvements remain necessary in production, transport and storage, and actual usage applications. In the case of green hydrogen, a critical capacity and cost lever will be the availability of very low-cost renewable power. The importance of renewable power for the clean



Investing as a catalyst

The company guides them in sorting through the various financial tools – debt products, guarantees, or equity instruments – that can reduce investor risks, particularly for new technologies or new industries trying to scale up. The company’s support goes beyond financial tools, however, to include market research and constructing new business models. An example is the company’s support for the HyDeal initiative. It involves a number of industrial players – including gas transmission systems operators, electrolyser manufacturers, and solar photovoltaic (PV) developers – that are coming together to build a large scale, integrated hydrogen ecosystem designed to deliver low-cost green hydrogen for industrial clients. The hydrogen produced will come from solar-powered electrolysis, and will be transported via pipelines to a number of storage and delivery hubs. Other industrial or technology deployment projects may benefit from the company’s advisory support to address key technical issues or prepare for financing. The EIB’s support goes beyond specific hydrogen projects. Building the low-carbon hydrogen ecosystem to the point that it could contribute to the replacement of fossil fuels would require enormous investment in renewable energy, such as wind and solar, or substantial new capacity for carbon capture and storage (CCS). There is also the need and scope for further technological progress in hydrogen conversion technologies – from low-carbon electricity to hydrogen (electrolysers) and electricity (fuel cells). This is an area in

which EIB has already accompanied multiple companies – small and large – in their R&D and innovation activities.

Time to act together Active co-ordination among the EU institutions, national governments, and industry is essential to turn objectives into reality. Europe’s transition of its energy systems from high-emitting fossil fuels to low-carbon hydrogen will require massive investment and monumental co-ordination. Launching initiatives to support EU members’ national strategies and to develop new financing mechanisms could help. At the same time, however, there is an urgent need for hydrogen production, storage, and distribution links to be built across EU members. Those cross-border projects will require specific co-ordination and an alignment of public resources. EIB, which already co-operates with the European Battery Alliance, is looking forward to doing the same with the hydrogen industry. Higher-risk financing instruments, developed together with the European Commission, have proved helpful in addressing projects in this sector which entail significant technical and market risk. In addition, EIB advisory services can play a key role to help not-yet mature projects to develop. The EU bank remains committed to continuing its support for investment in clean hydrogen – in line with the indications of the EU taxonomy – which could range from R&D investments to demonstration projects, as well as the building of the necessary infrastructure.

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Brian Pye (Malaysia), Greg Rheaume (US), and Martin Rylance (UK), THREE60 Energy, consider the opportunities presented by geothermal energy, and how these prospects can be realised through the transfer and application of oil and gas expertise.


umans have been using geothermal energy for centuries, with the famous Roman bathhouses as a prime example. It is the thermal energy available from the high internal temperatures of the Earth. It is a potent energy source, as demonstrated by the power of a volcanic eruption. In terms of modern uses for geothermal energy, power production and district heating are the primary applications. Power production uses geothermal heated water or steam to drive generators, while district heating uses hot water to transfer heat to buildings or neighbourhoods.

How does geothermal fit into the energy transition? Governments, organisations, and individuals are all taking significant steps to reduce harmful emissions and limit the impact of climate change. The Paris Accord, which approximately 200 nations have signed, sets a target to limit global warming to 1.5˚C. However, to achieve these targets, global energy use will have to transition away from oil and gas to cleaner energy sources. No one renewable source of energy can replace the current supply of energy from oil and gas. Solar, wind, biomass, and hydrogen are all well-known technologies contributing to the transition. Geothermal is less well-known by the public but is a viable renewable energy source that can help to meet global emission and climate change targets. A unique feature of geothermal energy is that it is always active and available, as opposed to wind and solar that are intermittent depending on environmental conditions. Most, if not all, continents already use some geothermal energy to meet their needs, but there is potential for significant growth in the sector.

Rapid migration of assets and skills from oil and gas to geothermal The energy transition not only requires the migration of energy from non-renewable to renewable sources, but it also requires the repurposing of oil and gas assets. Additionally, the declining oil and gas workforce requirements will leave many skilled resources looking for employment in alternative sectors. Oil and gas wells can be repurposed for geothermal use. This is a significant benefit as the investment will have been written off against oil and gas production. Of course, there will be some modifications needed and challenges to address. Geothermal wells tend to be deeper and operate at higher temperatures than oil and gas wells. These conditions require different and




robust materials for tools and equipment. Nevertheless, the base infrastructure already exists for implementing geothermal solutions. Many engineering disciplines and skills translate directly from oil and gas to geothermal technology. Engineers with expertise in well integrity management, corrosion and erosion, wellbore management, and root cause analysis, for instance, have relevant experience for geothermal projects. They even use the same digital tools for modelling and analysing well performance. Fracturing and stimulation is another area of expertise transferrable to the geothermal sector. Engineers use these tools to open hydraulic communication between wellbores and access that thermal energy.

Figure 1. Drilling performance improvement at FORGE.2

The future of geothermal energy One of the current challenges for geothermal is that the low installed base capacity means that the industry does not yet benefit from economies of scale and technology development. Costs of production range between US$66 and US$75/MWh, but these could drop by 20 to 30%, reaching <US$60 or even <US$50/MWh by 2030.¹ Governments are also contributing to the development of geothermal technology by making funds available. In the US, the Consolidated Land Appropriations Act passed in 2020 seeks to ease access to federal land for renewable energy. It establishes a goal of 25 GW of nameplate capacity and an annual budget of US$170 million for research and development. From a current base of under 4 GW capacity, there is a significant opportunity for growth in the geothermal market in the US alone. With this in mind, THREE60 Energy is collaborating with Professor Silviu Livescu’s Sustainable Geoenergy Research and Engineering Laboratory at the University of Texas at Austin in the US. This initiative aims to accelerate the development of geothermal solutions and create a platform for the migration and application of oil and gas expertise. A key deliverable from this collaboration will be a software tool for analysing a building’s heating and cooling needs and proposing technical and economic geothermal solutions. Some geothermal projects in Europe are already co-producing heat for buildings from oil and gas wells. Future opportunities include the potential conversion of oil and gas wells from depleted fields into geothermal wells, thus making use of existing infrastructure. This step may require deepening and repurposing of the wells, along with modifying tools and equipment for the higher temperatures.

Global effort in geothermal technical progression

Figure 2. Geothermal technologies applicable in the UK.3



There are multiple initiatives in play across the world energy business with regard to specific geothermal considerations. In the US, as well as the University of Texas at Austin as already noted, there has been the formation of the Texas Geothermal Alliance (TGA) and the continued progression also being made at the DoE funded Frontier Observatory for Research in Geothermal Energy (FORGE). Europe and many other parts of the world have similar efforts underway, all of which will support addressing a number of the fundamental challenges of geothermal energy and particularly enhanced geothermal systems (EGS), which will need to be resolved for economic scale power generation to be achieved. The SPE has also newly formed a Geothermal Technical Section, in order to harness the engineering body horsepower in support of this delivery. Of these challenges related to delivery from drilling, one aspect stands out high on the agenda – the achievable rate of penetration (ROP) in these granitic and hard-rock environments given that high-angle wells are required. Recent work from Texas A&M (for FORGE) has demonstrated that a controlled physics-based process applied to PDC bit design has delivered an 80% improvement in ROP (see Figure 1). This translation of oil and gas workflows to the geothermal arena will continue to help make significant inroads.

With the completion and stimulation, the requirements for multiple advances across a range of challenges is just as daunting. For example, the components and materials that are required to prepare wells will need to operate in a very different envelope (350˚C - 450˚C); combine this with the cyclic (temperature) nature of the operations themselves, and integrity/functionality becomes a major issue. While development and advancement of the functional envelopes will occur, it is typically being initiated through government energy sector seed-money. This encouragement is required in the absence of market scale to initiate technical advancement – as the scope for geothermal in all its forms grows, there will be an increasing industry uptake. The same can be said for the EGS aspects, and it can already be seen that many of the lessons that have been learned in unconventional oil and gas have corresponding areas of application in the EGS environment. Finally, surface aspects associated with the multiple processing approaches should not be underestimated. Such processes include dry-steam, flash-steam, and binary-cycle power stations. The majority of such systems present low efficiency <15% and the bulk of global plants <10%. This current inefficiency presents a huge opportunity to the industry to consider a swathe of solutions to moving that by factors of two or more. The true strength of surface-processing will be where the range of offtake and applications can be maximised. So, principal function power generation, then stepping down through to agricultural (greenhouse) heating, for example, as the power-fluid is cooled prior to return to the system.

In addition to the plant efficiency considerations, there are also the chemical aspects that will need to be taken into account. Various scales, depositions, and potential for NORM will need to be assessed on a case-by-case basis, and much like in the oil and gas industry, the area of flow-assurance will be one that will need to be directly incorporated into the overall production system. While the challenges are many, they are also great opportunities and directly reflect similar learning-curves that the oil and gas industry has repeatedly demonstrated an ability to traverse effectively.

A growing geothermal footprint THREE60 Energy is well-positioned to play a part in expanding geothermal energy use. The company’s capabilities cover design, operations, maintenance, and process engineering in addition to subsurface geology, geophysics, reservoir, geomechanical, and petrophysics expertise. The company’s global footprint has opened doors for its involvement in projects all over the world, such as a current conceptual project with a major national oil company in South East Asia, as well as various projects in locations such as the UK, Scandinavia, and the US.

References 1.

2. 3.

NREL, Geothermal Rising, ‘2021 US Geothermal power Production and District Heating Market report’, (2021). DUPRIEST, F., and NOYNAER, S., ‘Drilling Practices and Workflows for Geothermal Operations’, (March 2022) TOWNSEND, D.H. et al., ‘On The Rocks – Exploring Business Models for Geothermal Heat in the Land of Scotch. in 20’, (2020).

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Georgina Ainscow, Reddie & Grose, UK, outlines the role of geothermal in the green energy mix, highlighting its potential to support other renewables with its ability to operate consistently at a high availability rate.


t the 26th UN Climate Change Conference of the Parties in 2021, countries from around the world came together in Glasgow to debate solutions to the challenges posed by climate change. The message at COP26 was clear: urgent action is needed ‘in this critical decade’ to reduce carbon dioxide emissions by 45% and reach net zero by approximately mid-century. Since COP26, the rising cost of oil and the need for energy security has only increased the importance of growing renewable energy sources. This is going to require a radical transformation of the existing energy system over the next 30 years. But while challenging, the need for change presents opportunities for innovative zero-carbon technologies. In May 2021, COP26 President-Designate Alok Sharma visited the new Eden Geothermal site in Cornwall, UK, marking the start of drilling at the project, and signalling a message of support for geothermal energy and its role in the future energy mix. Patent filing statistics provide useful insight into tomorrow’s technology landscape. A joint report by the European Patent Office (EPO) and the International Energy Agency (IEA) shows a trend of growth in patents for clean energy technologies since the turn of the century, as innovators stake claims on the future clean energy space.1 While this growth is encouraging, the figures also reveal an urgent need for further innovation. Overall, the growth seen from 2016 onwards falls extremely short of the rapid rise seen in the period to 2013, which is surprising in light of the urgency of the climate crisis.


With the need for innovative solutions to meet climate change targets, and declining growth in clean energy innovation, comes an opportunity for disruption; for new or underutilised technologies to move to a prominent position on the energy stage.

Geothermal energy Geothermal energy has long been used as a direct source of heat and for generating electricity, with a global installed electricity capacity of 15 608 MW in 2020. To date, however, geothermal sources provide only a fraction of the world’s energy needs. With increased reliance on variable supplies such as wind and solar, policy disincentives for fossil fuels, and developments in energy storage and distribution, the time could now be right for its wider scale adoption, and many experts see geothermal energy as an essential component in the future energy mix. Geothermal energy utilises the Earth’s internal heat – heat generated during the formation of the planet and sustained by radioactive decay. Since it can be used without being depleted, it fits the definition of renewable energy. The flow of heat to the Earth’s surface is estimated at approximately 43 - 49 TW, which more than doubles humanity’s current energy consumption, but geothermal energy extraction has, to a large extent, been constrained to regions with active volcanoes or where plate boundaries merge. Here, the Earth’s

internal heat is accessible at, or close to, the surface. One of the most active geothermal areas is called the Ring of Fire, which encircles the Pacific Ocean and is home to New Zealand, Indonesia, the Philippines, Japan, the West Coast of the US, and Mexico. All of these regions are represented in Think GeoEnergy’s Top 10 Geothermal countries for 2021; a list which also includes Turkey, Italy, Kenya, and Iceland, all countries known for their volcanic activity.2 However, as evidenced by the Eden Geothermal project in the UK, the geographical reach of geothermal energy utilisation has been broadened by developments in deep-drilling techniques, which allow access to high temperatures in the Earth’s mantle 2 - 3 miles down. At these sorts of depths, hot water or rock can be accessed across much of the planet, meaning that utilisation of geothermal energy is not so geographically constrained. Indeed, research has shown that geothermal energy could provide 20% of the UK’s electricity demand, in addition to heating. Research has shown that when geothermal energy is developed, it will be capable of providing approximately 20% of the UK’s current electricity demand plus a vast amount of heating.

Patent trends in geothermal energy Evidence of innovation relating to deep-drilling is supported by patent data, where geothermal energy filings for drilling

Figure 1. Geothermal energy has long been used as a direct source of heat and for generating electricity, with a global installed electricity capacity of 15 608 MW in 2020.



techniques come second only to heat pumps, with over 8000 patents in the last 10 years. There is also substantial patent activity relating to three types of geothermal power station. Each operates in a different way, but implements the same basic design of drawing hot water and steam from the ground to spin turbines and generate electricity. Traditional dry steam geothermal power stations show the most patent activity, with over 5000 patents filed in the last 10 years, while there are nearly 4000 filings for more complex (and more common) flash steam power stations. Both rely on high temperatures: 150˚C or higher for dry steam and 180˚C or higher for flash. By contrast, more recent binary cycle power stations are able to utilise fluid temperatures as low as 57˚C. To date, filings in this area are lower, at nearly 2000. However, lower temperatures bring greater flexibility, and this, coupled with advances in deep-drilling, has the potential to see geothermal energy utilisation more widely deployed in the future. Another key area of development for geothermal energy is remote sensing, where nearly 4500 patents were filed in the last 10 years. These are sophisticated devices and techniques, many using AI to advance geothermal exploration. Technical advances have the potential to drive down the cost of exploration and reduce risk to investors. Heat pumps account for over half of patent filings officially tagged as geothermal energy in the last 10 years. While many of these filings relate to ground source heat pumps which utilise solar energy absorbed at the Earth’s surface rather than geothermal energy in a strict sense, the high patent activity is an indicator of innovation in an area that has potential to reduce reliance on fossil fuels and drive down emissions.

were directly utilised, but geothermal energy generation is still in its infancy, which may explain China’s absence from the top 10 geothermal energy producers, despite a high level of R&D activity in the field. Indonesia and the Philippines also present interesting anomalies. They occupy the number two and three spots in the top 10 geothermal energy producers. Indeed, with measures in place to reduce reliance on coal, Indonesia looks set to move to the number one spot. However, there are very few patent filings in these countries, suggesting that applicants may be neglecting key territories. The finding reflects a challenging patent environment and barriers to licencing and commercialisation of IP assets in both countries. The US Chamber’s International IP Index, which scores countries on the strength of their IP systems, ranks Indonesia 51st out of 55 countries, with a score of 30.42%, and the Philippines 37th, with a score of 41.58%. However, this could change over the 20-year lifetime of a patent, and applicants for geothermal energy technologies would do well to give thought to filing patents in countries where geothermal energy plays a key role in the economy.

Geographical distribution of patent activity


Geographical distribution of patent activity gives insight into the location of technology centres with specialisms in different aspects of clean energy innovation. According to the EPO/IEA report, centres in Europe, Japan, and the US dominate, accounting for more than three-quarters of patent filings since the turn of the century. South Korea and China are some way behind, but show a sustained increase in recent years. Japanese, US, and South Korean companies all appear in the top 10 applicants for geothermal patents in the period from 2010 - 2020, with Toshiba heading the list, followed by Haliburton and GE. However, the top 10 companies account for only 6.5% of total filings, indicating a wide spread of applicants in this open and emerging field. Looking at where these applicants are filing patents, China dominates, followed by the US, Japan, South Korea, Australia, Canada, and Germany. Notably, the geographical distribution of patent activity in geothermal energy does not correlate directly with production. While the US and Japan are both listed in the top 10 producers of geothermal electricity, China is not. The use of geothermal resources in China has a long history, but large scale exploration and development only began more recently. For decades, low-temperature geothermal resources in China

Patent activity by research organisations Another interesting statistic to come out of the EPO/IEA report is that patent filings in the geothermal energy field originating from public research organisations and universities has increased from 2% in the period from 2000 - 2009, to 11% in the period from 2010 - 2019. Although this is not high compared to areas such as carbon capture and bioenergy, an increase in interest by research organisations often precedes increased activity on an industrial scale and should be regarded as a positive sign for geothermal energy.

At present, geothermal energy is a small but important player on the global energy stage. In those countries where geothermal resources are easily accessible, geothermal solutions present a clean, reliable, and consistent source of heat and electricity. And improvements to geothermal exploration, deep-drilling, and utilisation of lower temperatures have the potential to make geothermal energy more widely accessible. Most net zero scenarios rely heavily on wind and solar. The variable nature of these renewable energy sources, which are dependent on seasons and the weather, means that they require support from other technologies which are not quite there yet. Advanced batteries, hydrogen, smart grids, and so on could all fill this gap in time. However, innovators, investors, and policy makers would do well to look at the potential for geothermal energy, with its ability to operate consistently at a high availability rate, to provide support for other renewables.

References 1. 2. 3.

European Patent Office, and International Energy Agency. ‘Global trends in clean energy technology innovation’, Patents and the energy transition, April 2021. RICHTER, A. ‘ThinkGeoEnergy’s Top 10 Geothermal Countries 2020 – installed power generation capacity (MWe)’, (January 2022). US Chamber of Commerce Global Innovation Policy Center, 2022 International IP Index: Compete for Tomorrow, 10th Edition (2022).



Max Brouwers, Getech, UK, identifies the ways in which the geothermal industry could be utilised more as part of the global goal to reach net zero, highlighting the growing pressure for renewables to replace fossil fuels in the near future.


eothermal power generation is witnessing rapid growth worldwide, with installed capacity having grown by approximately 50% in the last five years.1 According to the European Geothermal Energy Council (EGEC), with the right policies in place, geothermal could meet half of the EU’s heating and cooling demand by 2030.2 This would have a material environmental benefit, as heating and cooling in buildings and industry accounts for half of the EU’s energy consumption, the largest energy end use sector ahead of both transport and electricity.3 Geothermal energy is one of the most reliable, sustainable, and efficient energy sources available. It is accessible everywhere in the world and, unlike many other sources, it is not affected by the vagaries of the weather – making it the perfect green baseload energy source. Crucially, it can provide domestic energy security, significantly reducing reliance on imported sources of power. However, despite the fact that Europe rests on a vast amount of geothermal energy that can provide permanent


supplies of renewable heating, cooling, and power, it remains underdeveloped and often out of sight for policy makers. The resources are broadly (and informally) grouped into shallow and deep geothermal, based on the subsurface temperatures and the technologies used for extracting the heat.4 Shallow systems generally require ground source heat pumps to modify the temperature obtained from the geothermal resource for use in domestic or commercial heating and cooling applications. In deep systems, the subsurface is at a high enough temperature to be used directly for heating or electricity generation. According to recent research published by the UK’s Parliamentary Office of Science and Technology (POST), geothermal technologies currently deliver less than 0.3% of the UK’s annual heat demand, using only a fraction of the estimated available geothermal heat resource.4 Despite there being potential to increase this proportion significantly and contribute to the UK’s net zero targets, deep geothermal is currently not included in the UK’s carbon budget or government strategies.

In addition to space heating and cooling applications, the subsurface can also be used for storing excess heat from other sources, including renewables (such as solar thermal) and industrial processes. Systems that pump heat into the ground for storage can address the mismatch between heat supply and demand, and increase the overall efficiency of renewable heating and cooling systems.

Developing a global market for geothermal energy The UK’s Climate Change Committee predicts that approximately 20% of UK heat will need to come from low carbon sources by 2050 if the UK is to meet its carbon targets cost effectively.5 Geothermal technologies, from ground source heat pumps to deep geothermal sources, can be connected to heat networks, and have one of the lowest carbon footprints for space and water heating.6 However, the use of geothermal energy for supplying heat networks is only just emerging in the UK. A recent industry report from The Association for Renewable Energy and Clean Technology (REA) and

Arup suggested that, should the government establish a geothermal development incentive, 12 deep geothermal projects could become operational by 2025.7 The report states that these could provide heating to 50 000 homes, create 1300 jobs, and generate more than £100 million of investment in the UK. Assuming favourable market conditions, including government support, and leveraging the UK’s drilling capabilities in the oil and gas sector (12 - 15 wells/y), the report suggests that 360 sites could be established by 2050, providing £1.5 billion of investment, 15 000 GWh of heat for over 2 million homes, and an annual carbon saving of 3 million t. Geothermal energy has been shown to offer environmental, economic, and technical advantages in comparison to other renewable and non-renewable heating sources. These include a small land area footprint, applications over a range of scales from individual homes to district heating scale, very low greenhouse gas emissions, and the long-term availability of the resource. Paris, for example, has been using geothermal energy for



heating since 1969, today supplying geothermal heat to 250 000 households via 50 heating networks.8

Risk sharing While it can provide a consistent renewable energy source, there are certain risks associated with geothermal energy relative to other complementary low-carbon energy solutions, such as wind or solar. Accessing a new geothermal resource involves not only upfront drilling expense but also geological and operational risks, which could make investment more challenging to attract. Yet the large, long-lived, low land-footprint, baseload and flexible energy supply that can be delivered in a success case is very attractive, both from a cost and environmental perspective. While solar and wind energy models are well understood, geothermal projects are highly specific to their local context. This requires a special kind of expertise. Detailed upfront planning, geological evaluations, and overall technical and commercial strategies to reduce risk are critical to the success of these projects.

Figure 1. Example of subsurface input parameters to help identify geothermal sweet spots in South America.

Figure 2. Machine learning derived geothermal heat predictions compared to existing and planned geothermal developments.



Heat is not easily transported, unless the temperature is high enough to turn it into electricity. Therefore, even a large geothermal resource is not necessarily viable – it also may need to be in reasonable proximity to where the heat is needed. This makes geothermal prospecting very different to mineral or hydrocarbon exploration where a resource, once discovered and developed, can be potentially shipped anywhere in the world. Most deep geothermal exploration aims to identify areas with higher temperatures (high geothermal gradients) where drilling is shallower and thus less expensive. Geothermal developments have sensitive profit margins and, if used for heating rather than electricity generation, they need a local market so early integration with the right information is critical to make projects viable.

Identifying the best areas for geothermal Getech brings together its geoscience data, geospatial software products, and skills in geothermal energy to enable rapid identification of sites highly prospective for this type of energy – lowering risk, increasing profit-margins, and ultimately reducing payback times and returns in geothermal projects. The company’s approach is to apply these unique data, products, and skills to upscale the geothermal opportunity through its Heat Seeker solution, mapping geothermal favourability by combining geoscience and market factors with geospatial machine learning analytics. Heat Seeker incorporates proprietary data as well as public domain sources, using data sets to frame the modelling of temperature, crustal structure, heat flow, and geothermal system boundary conditions (Figure 1). Some of these are derived from gravity or magnetic data using established methodologies, such as the multi-geophysical inversion method for estimation of radiogenic heat production in the crust presented by Hokstad et al., (2017).9 In a recent project, Heat Seeker was used to pinpoint favourable locations for geothermal energy developments in South America. In order to create a surface heat flow prediction map, a variety of machine learning algorithms were tested. This was based on a number of input data sets, such as deep earth structure and temperature constraints, volcanism, and geothermal sites. The model was trained on data sets from the US, a country that has tectonic similarities with the area of interest and already has comprehensive heat flow data useful for crustal scale modelling. Once the accuracy of the algorithm was proven, it was then applied to an area of interest in South America bordering Chile, Bolivia, Paraguay, and Argentina. The resulting machine learning output highly correlates with known volcanic geothermal projects in the area (black dots on the map in Figure 2), modified from Pesce et al., (2014) 10 and Bona and Coviello (2016).11 There are some interesting results worthy of further investigation, including high heat flows in the shared

convective basin system of North Western Paraguay and South Eastern Bolivia, which might hold further opportunities. The success of a geothermal project depends on a lot more than geological heat flow. There are many infrastructure, economical, and social factors that influence geothermal favourability and, ultimately, viability. To map potential sweet spots, Heat Seeker employs a method that combines multiple favourability elements as stacked layers which are then merged to highlight areas of greatest favourability for resource accumulations. The example in Figure 3 looks at the basic drivers of supply and demand. Top basement temperature (a) and the proximity of Holocene volcanoes (c) are indicators of a potential geothermal resource, whilst population density (b) is a simple proxy of heat and energy demand. By numerically combining these factors into a single favourability map (d), there is a correlation with existing geothermal projects (e) – indicating that this approach has merit. Next, the results are refined using further favourability criteria and more detailed data collected in Argentina (Figure 4). In this map, the output from the previous analysis is used as one of the inputs (d), combining it with: FFLocations of high carbon emitting power plants (f).

Figure 3. Initial geothermal favourability map, based on integrating supply and demand parameters.

FFNon-industrial large heat users as proxies for single project customers (g). The resulting favourability map (h) shows potential sweet spots where geothermal demand and supply are present, and where geothermal energy could help decarbonise the existing energy used. This data can be refined further using additional criteria, such as potential competition from other renewables – i.e., wind (i) or solar (j). This example of a full Heat Seeker analysis involved additional factors such as the location of historical mines, deep well data, proximity to power grids, fault slip tendency, location of existing geothermal projects, and the machine learning output described previously. The workflows are tailored to the commercial and technical questions in each area and are limited only by the imagination of the analyst and the data sets available.

Conclusion Geothermal energy is a low-carbon resource that is globally abundant, but still vastly underexploited. Geospatial analysis and machine learning, coupled with comprehensive data sets covering potential supply and demand, can provide unique insights and understanding for policy makers, investors, operators, and stakeholders. Developing the geothermal sector could increase domestic energy security, provide considerable economic stimulus, and contribute to job generation. This includes redeployment of both technologies and workers from the oil and gas industry who have transferable skills and experiences in risk assessment and mitigation, deep drilling, and reservoir development. However, significant upfront capital costs and the geological risks (for example, not achieving the required

Figure 4. Enhanced geothermal energy favourability mapping.

temperatures) present a major barrier to the development of geothermal heat and power projects in the UK. This is where thorough upfront geoscientific analysis is needed to mitigate risk for geothermal projects. Getech’s Heat Seeker solution considers a wide range of factors that combine to make a geothermal resource attractive, including not just technical geoscience considerations but also commercial and social factors that drive energy supply and demand.

References 1.

2. 3. 4. 5. 6. 7.

8. 9.

10. 11.

LUND, J., and TOTH, A., ‘Direct Utilisation of Geothermal Energy 2020 Worldwide Review’, February 2021. European Commission, ‘Heating and cooling’, Energy efficiency, 2022. ABESSER, DR C., and WALKER DR A., ‘Geothermal energy’, UK Parliament POST, 27 April 2022. UK Parliament POST, ‘Heat networks’, PostNote Number 632, September 2020. Houses of Parliament Parliamentary Office of Science and Technology, ‘Developments in Wind Power’, PostNote Number 602, May 2019. The Association for Renewable Energy and Clean Technology, ‘Government urged to help deliver a ‘world leading’ deep geothermal sector to secure the UK’s ‘green recovery’’, 13 May 2021. RICHTER, A., ‘Geothermal – Greater Paris area making better and better use of enormous potential’, Think Geoenergy, 29 July 2020. HOKSTAD, K., TAŠÁROVÁ, Z. A., CLARK, S. A., KYRKJEBØ, R., DUFFAUT, C., FICHLER, C., and WIIK, T., ‘Radiogenic heat production in the crust from inversion of gravity and magnetic data’, Norwegian Journal of Geology, vol. 97, no. 3 (2017), pp. 241-254. PESCE, A., COIRA, B., and CASELLI, A. T., ‘Geotermia en Argentina desarrollo actual y potencial’, Geothermal Energy Workshop Salta, December (2014), pp. 44. BONA, P., and COVIELLO, M. F., ‘Valoración y gobernanza de los proyectos geotérmicos en América del Sur’, CEPAL Report (2016), pp. 178.



Figure 1. In 2019, approximately 83% of Iceland’s primary energy supply came from indigenous renewable sources, of which 65% was geothermal.



Árni Magnússon, Bjarni Richter, and Arni Ragnarsson, ÍSOR, Iceland, explain the current landscape of geothermal research and utilisation in Iceland, outlining the ways in which this renewable resource has positively impacted the country.


celand has a huge geothermal potential (Figure 2) based on the location of the country on a hot spot on the Mid-Atlantic Ridge. The country is mountainous and volcanic, with much precipitation, making hydropower resources also abundant. The population of Iceland is approximately 375 000, of which almost two-thirds live in the Reykjavik capital area. During the course of the 20th century, Iceland went from being one of Europe’s poorest countries, dependent on peat, dung, and imported coal for its energy, to a country with a high standard of living where practically all stationary energy, and approximately 83% of the primary energy supply, comes from indigenous renewable sources (65% geothermal and 18% hydropower in 2019). The rest comes mainly from imported fossil fuel used for the transport sector and fishing fleet. Iceland’s energy use per capita is among the highest in the world and the proportion provided by renewable energy sources exceeds most other countries. The electricity generation per capita in Iceland is by far the highest in the world, mainly due the energy intensive industry that uses over 75% of the electricity generated in the country.

History of geothermal research Utilisation of the renewable energy sources started on a small scale early in the 20th century. Systematic geothermal research was initiated by the Icelandic government in the 1940s with the aim to acquire general knowledge about geothermal resources and make the utilisation of this resource profitable for the national economy. The country built up a group of skilled geothermal scientists


and researchers, especially regarding the development of geothermal district heating systems for heating of houses. A turning point in geothermal development in Iceland occurred in the early 1970s when the sharp rise in oil prices

led to increased heating costs at a time when over half of the houses in Iceland were heated by oil. The government decided to reduce the use of oil as much as possible and further develop the domestic renewable energy sources (hydropower and geothermal), especially by exploring for new geothermal resources and building a new geothermal district heating system across the country. This development was partly supported by a special Energy Fund that was established by the government in 1967 to increase the use of geothermal resources. This fund has granted numerous loans for geothermal exploration and drilling. Where drilling failed to yield the expected results, loans were converted to grants.

Geothermal power plants

Figure 2. Overview of the volcanic zones and geothermal fields in Iceland.

The late 1990s were characterised by increasing interest in geothermal power plants and associated research. Significant progress was achieved in areas such as geothermal exploration and reservoir engineering. The practice of reinjection of the geothermal fluid back into the reservoir is getting more common, especially in high-temperature fields but also lowtemperature fields supplying hot water for district heating. This has improved the sustainability of the production considerably. The early years of this millennia were characterised by construction of new geothermal power plants in high-temperature fields, mainly due to increased demand in the energy intensive industry. In total, seven such plants are now in operation in the country. Four of these plants are in the southwest of Iceland including the largest one, Hellisheidi power plant, producing 303 MWe and 133 MWth for district heating. Three of the plants are in the northeast of Iceland. Additionally, one small geothermal power plant utilising the intermediate temperature resource is located in the south of Iceland. This kind of application is expected to increase in the future. The total power generation from geothermal in 2020 was 5961 GWhe, which was 31% of the electricity produced in the country that year.

Direct uses of geothermal Figure 3. The total power generation from geothermal in Iceland in 2020 was 5961 GWhe, which was 31% of the electricity produced in the country that year.

Direct uses of geothermal energy for different heating applications play a major role in the energy supply of Iceland. Long before power generation by geothermal started in 1969, hot geothermal water had been used for different applications. In terms of energy use as well as economic importance, the main use is house heating. By supplying heat for over 90% of all houses in the country, geothermal has had a huge positive influence on the economic development of the country and at the same time benefited the environment considerably through reduced emission of greenhouse gases (GHGs) compared to using fossil fuels for heating. The remaining 10% of house heating in Iceland is almost solely by electricity. Other important direct use sectors of geothermal energy are the heating of swimming pools, the heating of greenhouses, industrial processes such as the drying of seaweed and fish, aquaculture farming, and snow melting.

How is geothermal used today? Figure 4. Geothermal supplies over 90% of heat for all houses in Iceland.



The total direct use of geothermal energy in 2020 is estimated to have been 9737 GWhth (35 052 TJ). In some cases, the brine


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fraction from the high-temperature power plants is used for hot water production for district heating in co-generation plants. Thus, the energy efficiency is improved considerably. The low-temperature (<150˚C) fields are used mainly to supply hot water for district heating. The current utilisation of geothermal energy for heating and other direct uses is considered to be only a small fraction of what this resource can provide.

Geothermal utilisation at Reykjanes peninsula The Reykjanes peninsula in the southwest of Iceland is an active volcanic area. After nearly 800 years of inactivity, a

Figure 5. The total direct use of geothermal energy in 2020 is estimated to have been 9737 GWhth (35 052 TJ).

relatively small eruption was ongoing in Fagradalsfjall volcano at Reykjanes for a few months in 2021. Geothermal research has been ongoing in the area for decades with important contributions from ÍSOR and its predecessors in the form of geothermal exploration, drilling consultancy, well logging and testing, as well as resource assessment. Geothermal utilisation at Reykjanes on a large scale started by building a co-generation power plant at Svartsengi in 1976. The plant is located 50 km from Reykjavík and serves approximately 30 000 people with district heating. Due to the high salinity of the water (two-thirds that of sea water), it cannot be used directly for district heating as is commonly done in Iceland. Therefore, several heat exchangers are used to transfer the heat from the 240˚C brine to freshwater, which is distributed to the users at approximately 80˚C. The capacity of the plant for district heating is 190 MWth and for electricity 76.4 MWe. The energy company HS Orka also has another 100 MWe geothermal plant at Reykjanes that was commissioned in 2006 for electricity generation only. Expansion of that plant by 30 MWe is ongoing by adding a low-pressure turbine for better utilisation of the resource without extracting more fluid from the geothermal reservoir. A Resource Park has been built near HS Orka’s geothermal power plants at Reykjanes, based on the idea of maximum utilisation of the resource and minimum environmental impact of the activities. The Resource Park consists of spin-offs of different types where the Blue Lagoon, one of the most popular tourist attractions in Iceland, utilises effluent brine from Svartsengi power plant. Among other activities within the Resource Park are a fish farm and a fish drying factory utilising effluent heat from Reykjanes power plant, a methanol factory utilising both electricity and CO2 emission from Svartsengi power plant, and a company producing growth factors for medical research and skin care products by genetic engineering processes.

The role of the government

Figure 6. The low-temperature (<150˚C) fields are used mainly to supply hot water for district heating.



It has been the policy of the government of Iceland to increase the utilisation of renewable energy resources even further for power generation, direct uses, and the transport sector. A broad consensus on conservation of valuable natural areas has been influenced by increased environmental awareness. Thus, there has been opposition against hydropower and some geothermal projects. However, a recent public opinion poll shows that the most preferred type of power plant is geothermal power plants. The ownership of energy resources in Iceland is based on the ownership of land. However, exploration and utilisation are subject to licensing. A master plan assessing the economic feasibility and the environmental impact of selected power development projects was adopted by the Icelandic Parliament approximately 25 years ago. It is a tool to reconcile the often-competing interests of nature conservation and energy utilisation on a national scale and at the earliest planning stages. The master plan is currently in its fourth phase, which is due to be completed soon. Direct involvement of the government in energy research has gradually decreased over the years. While the government still encourages and supports exploration for geothermal and

other energy resources, the power companies, which are mostly in public ownership, have taken the lead in exploration and development of energy projects. In general, Iceland’s geothermal utilisation story is a successful one. Over a few decades Iceland has become largely independent in regards to primary energy use, utilising local energy sources. This has limited the need for importing hydrocarbons in such a way that now Iceland is only using hydrocarbons within the fishery fleet and transport sector. In the attempt to meet the international climate goals, Iceland is now focusing on eliminating the use of hydrocarbons within the fishery sector and transport sector by researching and testing other potential energy use, such as electric and hydrogen vehicles. The government of Iceland has set the goal of carbon-neutral Iceland no later than 2040 and, within the same timeframe, a zero fossil fuel economy. Also, an action was put in place for making the ministry offices a model for climate change and thus influencing institutions, companies, and the general public. All state institutions, municipalities, and state-owned companies must now set climate policies and targets for reducing GHG emissions. A long-term energy policy for Iceland to the year 2050 has been established. It represents a clear vision of a sustainable energy future where security of energy supply is fundamental. It states that energy transition, where fossil fuels are replaced by renewable energy sources, is necessary to combat the climate crisis.

Figure 7. The government of Iceland has set the goal of carbon-neutral Iceland no later than 2040.

Geothermal training programme In the attempt to promote geothermal utilisation around the globe, Iceland has through its International Development Co-operation as well as through the GRÓ Geothermal Training Programme (under the auspices of UNESCO) been providing aid, especially to developing countries, in the form of direct funding of exploration projects, as well as teaching and training experts from those countries. The mission of GRÓ GTP is to give university graduates engaged in geothermal work intensive on-the-job training in their chosen fields of specialisation. The aim is to assist developing countries with significant geothermal potential in building up groups of specialists that cover most aspects of geothermal exploration and development. The government of Iceland funds the operations of the Programme through its official development co-operation.

Contributing to geothermal research ÍSOR (Iceland GeoSurvey) has taken part in all geothermal research, exploration, and development in Iceland to date. Formally established in 2003 through the spin-off of the GeoSciences Division of the National Energy Authority of Iceland, the organisation and its team have decades of experience in supporting geothermal and hydropower development in Iceland and beyond. During these years, ÍSOR built up a substantial inventory of machinery and logging tools for research and measurements. At the same time, the company worked extensively on supporting international geothermal development working

Figure 8. Through various programmes, Iceland has been promoting geothermal utilisation around the globe.

with governments, government agencies, developers, development banks, financial institutions, and partaking in numerous international research projects. The organisation is finding ways to improve and augment geothermal resources, enhancing the environment and contributing to the debate on environmental issues. Also, following the UN Sustainable Development Goals, it is actively promoting geothermal development by increasing public and political awareness and training scientists throughout the world in geothermal science and development. The phrase ‘think globally, act locally’ has never been more appropriate than during the times of climate awareness. To be able to reach the climate goals, energy production in Iceland must be increased by upwards of 100 MWe/y for the next 20 - 30 years. This would entail an effort to increase export as well as a full energy transition.






BNZ to build solar project in Portugal

INVL Renewable Energy Fund I to invest €120 million in solar plants


The INVL Renewable Energy Fund I, managed by INVL Asset Management, is beginning activities in Romania, and plans to invest approximately €120 million in the development of solar farms it has acquired. Under agreements that have been signed, the fund has acquired two companies which are developing solar power plants with a capacity of 166 MW in Romania. “We are growing and diversifying the geography of the portfolio. Romania is a very rapidly developing and promising EU market which is giving increasing attention to green projects. We see huge potential in this market for developing renewable energy projects, and we believe that these investments of ours will not only reduce pollution of the environment but will also allow us to earn an attractive return for investors,” said Liudas Liutkevicius, Managing Partner of the INVL Renewable Energy Fund I. The solar energy projects in Romania that are being added to the fund’s portfolio already have approved grid connection conditions. The solar plants should become operational in 2024. “We constantly monitor electricity markets in EU countries and evaluate varied investment opportunities. We have been watching the Romanian market since the fund’s inception, but only went into action after the state amended electricity legislation to allow the development of power generation facilities on the basis of power purchases agreements, or PPAs,” Liutkevicius notes.

NZ has obtained authorisation in the North Region of Portugal to start the construction of a solar photovoltaic (PV) plant in the Ave intermunicipal community with an installed capacity of 49 MWp. BNZ expects the plant to be operational in 2023. This will be BNZ’s first plant to be built in Portugal, a country in which it expects to install an approximate capacity in excess of 400 MWp by 2024. The aggregated fully permitted capacity of BNZ across all geographies stands at 147 MWp. The electricity production of this project would be able to supply the annual electricity needs of approximately 14 000 people, the equivalent of one-third of Evora’s population. The clean energy produced at this plant will avoid 21 500 tpy of CO2 equivalent emissions, which is approximately 37 000 Lisbon to London roundtrip flights. In addition, BNZ estimates that it will create between 270 and 370 direct and indirect jobs by 2024. The production of reliable and affordable PV solar energy located in Portugal will avoid the importation of fossil fuels such as natural gas from third countries. This will result in greater energy independence and security of supply, in addition to improving environmental sustainability. For example, the energy produced by this BNZ project will save the use of 14 million m3/y of natural gas that were to be consumed by combined cycle gas turbine (CCGT) plants to generate the same amount of energy.

KGAL gains approval for three solar PV projects in Italy


GAL has received the green light for three large scale solar photovoltaic (PV) projects in Italy. The approved solar parks located in the Lazio region and in Sicily will have a total output of approximately 380 MWp. They will be successively connected to the grid from 1Q24. Together with other projects, KGAL is developing solar and wind parks with a total capacity of more than 1.2 GW in the highly attractive Italian market. Institutional investors of the funds KGAL ESPF 4 and KGAL ESPF 5, which is currently being marketed, will participate in these promising investments. The combination of strong solar radiation and



above-average electricity prices make Italy an attractive market in Europe for solar PV projects. In addition, the Italian government has encouraged the expansion of renewable energy generation with the introduction of legislative initiatives in the past year. In doing so, the share of green energy within the total energy consumption is set to rise rapidly from 20% in 2020 to 30% in 2030. “The approval procedures have become much simpler and faster,” explains Michael Ebner, Managing Director of Sustainable Infrastructure at KGAL Investment Management.


GLOBAL NEWS First jackets transferred for Saint-Brieuc offshore wind farm


berdrola has started the transfer of the first jackets for its offshore wind farm in Saint Brieuc, Brittany, France, from the Navantia Seanergies shipyard in Fene, A Coruña, Spain, where the Navantia-Windar consortium is building these structures to support the wind turbines. These are the first four jackets of the total of 62 to be built at the wind farm, which will be the Iberdrola Group’s first major offshore wind energy site in France. The contract for the construction of the jackets was also the largest order to date for the Navantia and Windar partnership in offshore wind energy. The foundations will be transported in a 122-m-long Van Oord barge. They will arrive at their destination in the port of Brest, France, covering the more than 1500 km that separate the port of Ferrol, Spain, from their location in the English Channel. The delivery of the first jackets demonstrates the successful completion of the contract signed two years ago, valued at €350 million. The order included the manufacture and assembly of the 62 structures at Navantia Windar’s facilities in Brest and Fene and the piles that anchor the wind turbines to the seabed at Windar’s facilities in Avilés, Spain. This contract has strengthened a relationship of more than eight years between Iberdrola and Navantia-Windar, which totals contracts worth more than €1000 million, including the award to Windar of the transition pieces for the Baltic Eagle offshore wind farms in Germany and Vineyard Wind 1 in the US, as well as the orders already completed for Wikinger, in the Baltic Sea, and East Anglia One, in the UK.

Technip Energies and Equinor enter strategic collaboration to accelerate floating offshore wind


he strategic collaboration between Equinor as a floating offshore wind developer and Technip Energies as a complete offshore wind solutions provider was signed during the Seanergy conference in Normandy, France. The two companies aim to develop floating wind steel SEMI substructures that accelerate technology development for floating offshore wind, ensures cost reductions, and develops local value opportunities. The collaboration builds on the companies’ joint ambition to drive industrialisation of floating offshore wind. By teaming up at the early design phase of a floating wind farm project, the two parties seek to unlock value from integration and maximum use of fabrication capacities. Growth in renewables is needed to succeed with the energy transition. A large part of this growth will come from floating wind, as approximately 80% of the wind resources offshore are in deep waters that require a floating wind turbine solution. Even though costs have come down substantially, there is still a way to go for the floating technology to reach commerciality. From building the world’s first floating turbine, Hywind Demo, to the world’s first floating wind farm, Hywind Scotland, Equinor reduced the cost per MW by 70%. The strategic collaboration between Technip Energies and Equinor will contribute to industrialising floating offshore wind solutions.

Ørsted’s first Scottish wind project generates first power


rsted’s first Scottish wind project, Kennoxhead, located in South Lanarkshire, south-east of Glasgow, has generated first power. The onshore wind farm has a capacity of 62 MW and will generate clean electricity equivalent to powering over 38 000 Scottish homes. The construction of Kennoxhead is divided into two phases, the first cluster of turbines counting 13 wind turbines with a total installed capacity of 62 MW. The second cluster will be adding up to 112 MW installed capacity, bringing the total capacity at the site to 174 MW. At 174 MW combined, Kennoxhead is one of the most significant onshore wind farm projects in Scotland, making

a valuable contribution to the Scottish government’s target of 50% of electricity to be generated from renewable sources by 2030 as part of the wider target of a decarbonisation of Scotland’s energy system by 2045. Phase 1 of Kennoxhead is expected to reach commercial operation later in 2022. TJ Hunter, Senior Director Ireland and UK Onshore at Ørsted, says: “It has taken a great effort to reach first power on Kennoxhead, and I’m proud of the team and our partners for passing this milestone. We are well on track to reach commercial operation later this summer, and we’re an important step closer to the finishing line of the project.”



GLOBAL NEWS WELTEC BIOPOWER commissions biogas plant in Japan


biogas plant of WELTEC BIOPOWER has gone live in Saitama Prefecture, 40 km north of Tokyo, Japan. The facility – which is equipped with a 450 kW cogeneration power plant – is the fourth project to be rolled out by the German manufacturer in Japan. In terms of substrates, the operator makes use of organic leftovers from the vicinity. Since the raw material mix varies, WELTEC ensures a steady biogas output with its biological service. This service of the biogas specialist also comprises another plant of the same customer. WELTEC BIOPOWER has set up a stainless-steel digester with a capacity of 2823 m3. Its dia. measures 25.34 m, and its height is 6.3 m. The upstream substrate storage tank, which is made of stainless steel, has a capacity of 336 m3, a dia. of 9.31 m, and a height of 5.03 m.

UGI invests in RNG project


GI Energy Services LLC announced an agreement with MBL Bioenergy to fully fund the first set of renewable natural gas (RNG) projects currently under development in South Dakota, US. In total, the project will represent over US$70 million of investment by MBL Bioenergy, of which 100% of the funds will be provided by UGIES. MBL Bioenergy is a joint venture partnership between UGIES, Sevana Bioenergy, and a subsidiary of California Bioenergy (CalBio) with the sole purpose of developing RNG projects in South Dakota. The first set of projects, known as a cluster, will be built at three farms located north of Sioux Falls, South Dakota, and is expected to generate approximately 300 million ft3/y of RNG once completed in calendar year 2024. Dairy waste from the farms will be anaerobically digested and then piped to a central upgrading facility before it is delivered into the interstate natural gas system near Dell Rapids, South Dakota. UGIES, through its wholly-owned subsidiary, GHI Energy, will be the exclusive marketer for MBL Bioenergy. “This project sets a new standard for UGI in terms of scope and size, and represents a huge milestone in UGI’s investments in, and expected earnings contribution from, RNG projects,” said Robert F. Beard, Executive Vice President – Natural Gas, Global Engineering, Construction & Procurement, UGI.



Worley awarded contract by Heartwell Renewables


orley has been awarded a contract by Heartwell Renewables LLC, a joint venture between The Love’s Family of Companies and Cargill, for a greenfield renewable fuels plant in Hastings, Nebraska, US. The new plant will produce an estimated 80 million gal. (approximately 303 million l) of renewable diesel/y from feedstocks such as vegetable oils and tallow. This renewable diesel has the potential to reduce at least 50% of greenhouse gas (GHG) emissions compared to traditional petroleum-based diesel. It can also be used as a drop-in fuel in diesel-powered vehicles without any engine modifications. Under the contract, Worley will provide detailed and field engineering services. Worley’s services will be executed in Houston, Texas, US, with support from its Global Integrated Delivery (GID) team in India. The team will use a full suite of digital tools during project delivery. “To help decarbonise road transportation, North America will be increasing its renewable diesel capacity significantly by 2025. We look forward to working with Heartwell on this important project that will contribute to the ambition of supplying more sustainable fuels to the market,” said Christy Tyer, Senior Vice President, Americans Central Operations at Worley.


Rystad Energy: Egypt invests in green hydrogen economy


STRUCTeam and Ocean Energy develop wave technology


RWE’s largest battery storage project goes live in Ireland

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EXERGY and GDI partner for geothermal development in Japan


XERGY International srl and Geothermal Development & Investment Inc. (GDI), subsidiary of GPSS Group, have signed a partnership agreement for the exclusive distribution of turnkey geothermal power plants in Japan using advanced, highly efficient Organic Rankine Cycle (ORC) technology. Thanks to this partnership, GDI and EXERGY will offer comprehensive solutions for the development and completion of ORC power plants, starting with the design and engineering of the system to the manufacturing, erection, start-up, and aftersales services, leveraging on both companies’ expertise and know-how in their fields. The partnership between EXERGY and GDI will develop joint megawatt scale projects, and contribute to the growth of geothermal development in Japan, which has the world’s third-largest geothermal resource potential. The strategic agreement is also an outset for the collaboration of GDI and EXERGY in other markets, such as South and Southeast Asia and Africa, as well as other applications of the ORC technology, such as waste heat recovery and other heat-related renewable energy applications.

Vallourec invests in GreenFire Energy


allourec has invested in GreenFire Energy Inc., an American start-up developing advanced geothermal systems. This transaction was carried out as part of a Series A funding alongside other major investors, Baker Hughes and Helmerich & Payne. Vallourec and GreenFire Energy have been working together since 2019 on several successful closed-loop geothermal demonstrators in various fields. This investment will further strengthen the relationship between the two companies. Vallourec THERMOCASE® Vacuum Insulated Tubing (VIT) is an enabler of closed-loop geothermal systems: these thermally insulated pipes allow the harvesting of underground heat and bring it to the surface (as hot water or steam) with minimal losses. Vallourec will be able to support GFE by designing and manufacturing bespoke solutions for their downhole heat exchanger. Geothermal energy is expected to play a major role in the energy transition and the decarbonisation of economies, as it is the only renewable source that can always be ‘on’, providing low-carbon and versatile energy. While conventional systems rely on the exploitation of geothermal resources in very specific areas, advanced geothermal systems could unlock the possibility of producing energy virtually anywhere.





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