The magazine for oil and gas professionals in the energy transition
May 2021 – open access articles The following articles are taken from Petroleum Review magazine’s May 2021 edition for promotional purposes. For full access to the magazine, become a member of the Energy Institute by visiting www.energyinst.org/join
Perspective
PERSPECTIVE
Net zero feeds on innovation A Abigail Dombey, Energy & Sustainability Engineer, Communities Director at Carbon13, and Chair of Hydrogen Sussex (UK)
The views and opinions expressed here are strictly those of the author and are not necessarily given or endorsed by or on the behalf of the Energy Institute.
chieving net zero will require ramping up clean technology deployment while continuing to reduce costs through innovations in energy storage, hydrogen and other low carbon fuels, and carbon capture, use and storage (CCUS). Energy storage will play a crucial role in helping to decarbonise the power system, by balancing the grid in real-time and backing up renewable generation, allowing intermittent energy such as solar, wind or tidal power to be stored for later use when it is needed. Meanwhile, hydrogen will be essential to achieve net zero greenhouse gas (GHG) emissions by the UK government’s target date of 2050, according to the latest National Grid future energy scenarios. These scenarios outline four different credible pathways for the future of energy over the next 30 years – Consumer Transformation, System Transformation, Leading the Way, and Steady Progression. In these scenarios, hydrogen could be the solution to many of the hardest parts of the transition to net zero, particularly for long-distance freight, shipping and heavy industry. There is already a huge amount of innovation in and around hydrogen, with focus on a wide range of areas including membranes, electrolysis technologies, fuel cells and hydrogen direct reduction in steel making. Green hydrogen is produced from the electrolysis of water; improvements in efficiency of the electrolysis process and the membranes involved can significantly reduce process energy consumption and the cost of the hydrogen produced. Reducing fuel cell cost is the main challenge to fuel cell commercialisation, currently being addressed in a joint project by Bosch and the start-up PowerCell Sweden. Hydrogen direct reduction is a relatively unexplored process, whereby iron ore is reduced to iron without melting, and hydrogen is used as the reducing agent in steel manufacturing. Start-ups such as Riversimple, Supercritical Solutions and Steamology are among those leading the way in the UK in hydrogen innovation. Riversimple is aiming to offer customers an
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affordable, ‘fun-to-drive’ eco car, with a hydrogen fuel cell car designed from scratch to deliver a step change in fuel efficiency and environmental performance. Supercritical Solutions is developing a highly efficient electrolyser for hydrogen production, claimed to require 20% less energy to produce hydrogen. Steamology produces hydrogen fuelled steam generators, delivering both hydraulic power and electric power. Cost reductions from innovation and economies of scale in clean technologies, including green hydrogen and carbon capture, are emerging. BP, for example, is aiming to build the UK’s largest hydrogen plant in Teesside. The proposed facility will produce blue hydrogen, produced by converting natural gas into hydrogen and CO2, which is then captured and permanently stored, supporting the development of the region as a hydrogen transport hub. By 2030 the plant at Teesside is expected to deliver 1GW of blue hydrogen, 20% of the UK's overall hydrogen target. Meanwhile, in northern Germany, a new project partnership is investing €1.3mn to create a ‘Clean hydrogen coastline’. Companies including ArcelorMittal Bremen (steel) and FAUN (hydrogen fuel cells) are working with utilities companies and grid operators to integrate up to 400 MW of electrolyser capacity, with the capacity to scale up to 2.2 GW of green hydrogen. Entrepreneurship is key As the Climate Change Committee set out in the UK’s Sixth Carbon Budget, greater contributions from innovation and societal/ behavioural change would reduce the challenges in achieving net zero emissions by 2050. However, the future of energy depends somewhat on companies which do not yet exist. While great work is being done by large corporates in the energy sector, certain aspects of the innovation that is required simply won’t be engineered from inside existing organisations. Paul Eremenko, former Chief Technology Officer at both Airbus and United Technologies Corporation (UTC) found it challenging to significantly
advance technical innovation in big companies. ‘I think my track record in both Airbus and UTC suggests that I tried very hard to make step changes,’ he said. ‘From within the aerospace [industry] it is very difficult to do things that are non-incremental.’ Eremenko has co-founded a start-up, Universal Hydrogen, that aims to bring hydrogen-fuel technology and a related supply system to regional airlines as soon as 2024. The new business models, new industries, behaviour changes and value propositions needed to make net zero a reality will come from other equally globally ambitious entrepreneurs, and the economies which enable them to thrive. This observation on the key role of entrepreneurship has come from my work with net zero entrepreneurs at Carbon13. Through the Venture Builder, founders form teams capable of building scalable ventures, with team mates such as serial entrepreneurs, engineers, data scientists, biochemists and people with deep experience and credibility in the carbon emitting sectors. Carbon13 has grown out of Cambridge’s vibrant ecosystem of academia, tech and entrepreneurship and is supported by partners such as Arm, BP Ventures, Cambridge Cleantech and DLA Piper. Noted investors such as ex-Dragon* Nick Jenkins have participated in the Carbon13 SEIS Fund, which invests in ventures generated by the programme. We intend to take 1,000 entrepreneurs through our programme over the next five years, supplying the enablers in terms of expertise and pre-seed investment to launch real emissions gamechangers. The greatest opportunity for driving innovation forward is bringing together the best people from every part of the economy to work together on our shared challenge. Decarbonising the economy and dealing with past emissions offers many opportunities for building new companies. I believe we will never achieve net zero without innovators creating these new opportunities. ● *Nick Jenkins was a ‘Dragon’ on the BBC Two series Dragons’ Den for budding entrepreneurs.
Caspian and Central Asia
ENERGY TRANSITION
Challenges ahead
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Photo: iStockphoto
he Caspian region is wellendowed in oil, gas and other raw materials, and this wealth has helped draw in lucrative foreign investment and driven economic growth in the decades since the collapse of the Soviet Union. However, this over-reliance on a handful of commodities left the Caspian countries greatly exposed to the COVID-19 pandemic and the ensuing impact on markets. Oil prices collapsed to their lowest level since the 1990s in April 2020, when Russia decided to walk away from OPEC+ talks. Russia later saw reason, agreeing with the oil cartel’s other members, which include Azerbaijan and Kazakhstan, to take nearly 10mn b/d of oil supply offline. Even that sacrifice was not enough to offset COVID-19’s impact on prices, and it has taken Brent over a year to return to its pre-pandemic level. As a result, Azerbaijan and Kazakhstan have had to scale back oil supply significantly over the past 12 months, while at the same time fetching far less for their remaining barrels. This contributed to their economies contracting by an estimated 5% and 2.6% respectively in 2020. COVID-19 also took its toll on the gas-producing nations of Uzbekistan and Turkmenistan, both of which generate significant export revenues from selling gas to China. Chinese gas demand saw growth of 6% in 2020 despite the pandemic’s effects early in the year. But the country prioritised domestic supply while slashing its gas imports, with Central Asian supplies bearing the brunt. Considering these challenging circumstances, it is no surprise that the past year has seen muted upstream activity in the Caspian
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While oil prices have rebounded to pre-pandemic levels, the energy transition potentially poses a longer-term challenge for the Caspian’s hydrocarbons sector, writes Joseph Murphy.
region. Some downstream projects have also suffered as a result of the market turbulence. Citing the pandemic, Austria’s Borealis scrapped plans in May last year for a multi-billion dollar polyethylene (PE) plant in western Kazakhstan. Its Kazakh state-owned venture partner United Chemical is now trying to proceed with the venture on its own. Lost in transition Oil and gas markets are now recovering thanks to the easing of lockdown measures and the mass roll-out of vaccines. But countries dependent on fossil fuel revenues face a longer-term challenge from the energy transition, which has gained momentum during the economic crisis. The International Energy Agency (IEA) and others have slashed their long-term forecasts for oil and gas prices, and many of the world’s leading oil companies have written billions off their books to account for the revised outlook. Should these predictions bear out, socalled petrostates like Azerbaijan, Kazakhstan and Turkmenistan stand to lose billions of dollars of economic wealth over the coming decades unless they can diversify. Indeed, a 2021 report by Londonbased think tank Carbon Tracker estimated that the 40 most oil and gas-dependent countries stand to lose $9tn in oil and gas revenues by 2040 as the world shifts to lower carbon energy. It rated Azerbaijan as Tier 5, the category of countries most vulnerable to the transition, and Kazakhstan as Tier 3. At the same time, the Western oil companies that Azerbaijan and Kazakhstan have relied on for their upstream expertise and financial capability for decades are shifting focus. For example, BP announced
plans in 2020 to scale back its oil and gas production by 40% within a decade, while increasing its renewable energy capacity 20-fold. In March 2021 the company confirmed it was dropping plans to explore three projects in the Kazakh section of the Caspian Sea, citing its change in strategy as the reason. As part of its green pivot, BP has said it will not look for oil and gas in countries where it is not already active. This likely means it will not make a foray into neighbouring Uzbekistan either, where it signed a preliminary deal in early 2020 to explore two subsoil blocks in the western Ustyurt region. The company has not indicated that the new strategy will have any impact on its plans in Azerbaijan, where its exploratory work over the past year has been limited anyway because of the market conditions. With Western oil firms less willing to commit to new Caspian ventures, it is conceivable that major players in the region from China and Russia will take their place. Gas hopes While forecasters have warned that oil demand may never again recover to pre-pandemic levels, the outlook for gas is more positive, given that many countries want to use the fuel to reduce their emissions by replacing coal-based power. China will continue drawing significant gas supplies from Central Asia in the long term, as its indigenous supply fails to keep up with surging demand. It is a different story in Europe, however, where the IEA predicts that demand will contract over the coming decades. This does not bode well for a planned expansion in Azeri gas exports to the continent. Azerbaijan hailed the completion of the Trans-Adriatic Pipeline (TAP)
Caspian and Central Asia
at the start of the year, which at full capacity will deliver up to 10bn cm/y of gas to south-east Europe. BP, Azerbaijan’s Socar and the pipeline’s other investors want to double this to 20bn cm/y and are due to hold the binding phase of market tests for the expansion this July. Increased gas supply into south-east Europe will help the region scale back coal-fired generation, providing cleaner baseload capacity to complement renewable sources of power. But it is unclear whether the area will need more gas, especially given the recent development of other import options such as the Krk LNG terminal in Croatia, also launched at the start of this year. Increasingly, Azerbaijan will have to compete with other gas suppliers, not just on price but on climate credentials. This may mean the country has to make progress cutting its CO2, methane and other emissions to convince European buyers that its gas is sufficiently clean. The Southern Gas Corridor, of which TAP is a part, was realised largely thanks to significant EU political and financial support. But it is unlikely that the bloc would be willing to provide anywhere near this level of support for its expansion, given growing antipathy towards oil and gas, and weak demand prospects. Clean potential at home The Caspian nations have also followed other regions of the world in seeking to harness their renewable energy potential. Kazakhstan was an early developer of wind and solar power,
Trans-Adriatic Pipeline compressor station at Kipoi Photo: Trans Adriatic Pipeline
launching its first wind farm, a 50 MW facility near Yereymentau, in 2014. That same year it also brought online its first solar power station, also with a 50 MW capacity. These initial projects were supported by feed-in tariff (FiT) legislation, which Kazakhstan crafted with the help of the European Bank for Reconstruction and Development (EBRD). In 2019, however, the country switched from FiTs to a system of auctions for projects, where developers bid to supply power for the lowest price. In the latest round that concluded last December, Kazakhstan picked developers to build 148 MW of wind, hydropower, solar and biogas capacity, out of a tender target of 494 MW. By the end of 2019, Kazakhstan had 284 MW of wind and 542 MW of solar capacity in operation, according to the International Renewable Energy Agency (IRENA). It added a further 583 MW of renewable capacity, comprised of 12 solar, 10 wind and one hydroelectric plant, in 2020. While not a trailblazer like Kazakhstan, Uzbekistan’s progress has been significant given that its renewable energy drive did not kick off in earnest until the end of the regime of President Islam Karimov in 2016. The country held its first competitively-held tender for solar power generation in 2019, with Abu Dhabi-based Masdar putting in a winning bid for a 100 MW solar plant in the Navoi region. France’s Total Eren was later picked for a 100 MW solar station. Masdar obtained financing for the facility the following year, when the EBRD, the International Finance Corporation (IFC) and the Asian
Development Bank (ADB) pledged over $180mn in funds. The IFC has taken a leading role in Uzbek solar development, having helped Tashkent arrange tenders and draw up power purchase agreements. Construction of the Masdar facility began in January this year. Emboldened by this success, Uzbekistan announced two more tenders for solar generation in December last year. One tender is for a plant at least 200 MW in size in the Surkhandarya region, along with associated infrastructure. The third competition covers up to 500 MW of solar projects in the Bukhara, Namangan and Khorazm regions. Uzbekistan has made similar strides in wind energy. After landmark deals in 2019 with Saudi Arabia’s ACWA Power and Masdar for 1,000 MW and 500 MW of wind capacity respectively, Uzbekistan launched a tender in April last year for a 100 MW plant in the Karakalpakstan Province. But although the competition attracted interest from 70 companies and consortia, according to the Uzbek Energy Ministry, a winner was never announced. Nevertheless, authorities went on to reach power purchase and investment deals for the aforementioned two ACWA projects, bringing them closer to realisation. Uzbekistan’s strategy calls for the deployment of some 5 GW of solar capacity by 2030, as well as up to 3 GW of wind energy and 3.8 GW of hydroelectric power. But its ailing grid will need significant upgrading to handle so much intermittent renewable energy. In tandem, though, Uzbekistan is also looking to improve gas-fired generation over the decade, replacing some 6.4 GW of older gas-based capacity while building or modernising a further 15.6 GW. Ample baseload gas-fired generation will help the Uzbek energy system support more renewable input. Azerbaijan, meanwhile, is looking to develop its first largescale solar power plant, with talks currently underway with Masdar for the 230 MW facility’s development. Others in Central Asia, like Tajikistan and Kyrgyzstan, boast significant hydroelectric capacity, much of it built in the Soviet era. But neither has made a foray into wind or solar yet. Turkmenistan might have the biggest solar power potential in the region, but its authoritarian and isolationist regime prevents the country from attracting the necessary international financing and expertise to kickstart its renewables programme. l Petroleum Review | May 2021 15
Finance
ENERGY TRANSITION
Unlocking capital for net zero infrastructure The challenges of aligning policy and private capital for net zero infrastructure investment are examined by Colin Smith and Adrian del Maestro of PwC.*
T
he UK government is leading the way on decarbonisation. It was the first major economy to set a legally binding commitment to net zero emissions by 2050 and it has seen CO2 emissions fall by some 30% over the past decade since 2010. The government has recently unleashed a raft of policymaking to underpin its ambitions from the 10 Point Plan for a Green Industrial Revolution and the Energy White Paper to the more recent North Sea Transition Deal. Investing in infrastructure such as power systems, buildings, industry and transportation will be essential to meet net zero ambitions. However, more needs to be done and quickly. This decade will be pivotal if the world has any hope of meeting the 1.5oC pathway. So where should capital be deployed in the UK? How much will it cost? Who has the capital to deploy to support
Figure 1: Typical investor by asset class
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this drive for decarbonisation? And what role should the government play in enabling this investment? As part of a report commissioned by the Global Infrastructure Investor Association (GIIA), PwC explored these questions by interviewing a number of leading infrastructure funds. Some of the key findings that emerged from the interviews are highlighted below. Infrastructure funding needed now According to PwC research it is estimated around £40bn/y is required, on average, to be invested in new low carbon (power systems £15bn/y, buildings and industry £18.5bn/y, transport £1.5bn/y) and digital (£6bn/y) infrastructure over the next 10 years. With private capital contributing around £20bn of UK energy and utility infrastructure financing in 2019, this represents a doubling in capital requirements for UK infrastructure investment across energy, water and telecoms. Each of these segments have their unique nuance. The UK power system has already transformed significantly, delivering a 56% reduction in emissions since 1990. Nevertheless, to fully integrate
and manage even greater levels of renewable and flexible energy sources, the power grids (at both transmission and distribution levels) will require further innovation to deliver a smarter grid infrastructure. This will require the largest allocation of infrastructure funding, not all of which can be delivered by a public sector which is facing record levels of borrowing and pressures on the public balance sheet due to the COVID-19 pandemic. Carbon-intensive industrial processes still present some opportunities for emissions abatement through energy efficiency measures and the use of low carbon heat alternatives, such as hydrogen. In addition, significant investment will be required to capture the CO2 from these processes. However, the largest investment required will be in the residential sector, to decarbonise the millions of homes reliant on gas-fired heat. In transport, the roll-out of electric vehicle (EV) charging infrastructure has begun, but is currently limited as is the opportunity for investors due to the high-risk and nascent stage of the technology in the UK. This critical infrastructure will
Source: PwC Strategy& research
Finance
require continued investment to ensure national coverage with the capacity for millions of EVs to be using networks by 2030. Other forms of low carbon transport, such as hydrogen for aircraft, shipping, heavy goods vehicles (HGVs) and/or rail are also vital for meeting net zero targets. Looking at digital and the roll-out of next generation networks, namely 5G, fibre networks and smart meters, this is largely expected to be complete by 2030. Good progress is being made across all asset types, but significant additional investment will be required in the 2020s. However, the regulatory system currently overly favours the incumbent, which obstructs competition in the market for fibre broadband. 5G will require the most funding per annum, on the back of increasing network densification and industry-specific use-cases. However, the magnitude of these investments is not the only challenge. How these investments will be funded is equally complex. According to PwC research, only around 50% of the net zero asset investment required will be able to access low-cost capital. This is because technologies like hydrogen, carbon capture, use and storage (CCUS) and EV charging may still be immature and present a combination of high technology, business model or policy risks. As a result, these types of investments will more likely attract venture capital and private equity funding (which have a higher cost of capital). Infrastructure funds have around $200bn in dry powder globally but are accustomed to lower risk and lower returns and are thus reluctant to venture into higher risk investments, as highlighted in Figure 1. Critical source of capital While our interviews with infrastructure funds confirmed that many businesses are exploring new energy technology investments, there were major concerns around the business models being presented, with funds struggling to see the viability of revenue streams. In the case of EV charging, some respondents encouraged the government to develop a more detailed roadmap to address charging infrastructure needs in cities and rural areas. We need to recognise that funds are important for infrastructure development. Net zero infrastructure needs to be delivered at scale, quickly and
at the lowest cost to maximise the benefit of net zero and to keep the costs to consumers and taxpayers down. Harnessing capital from investment-ready private infrastructure funds and corporates will also avoid further burdens on government finances, which are stretched to record levels following the government response to the coronavirus pandemic. Indeed, the HMG Infrastructure Finance Review is clear that over the next 10 years, around half of the £600bn infrastructure pipeline is forecast to come from the private sector in electricity, digital, airports, water and waste. In short, there is a deep pool of low cost and private capital already primed to accelerate investment. In this context, government policy can act as a catalyst to enable the deployment of this capital. Enabling role of government The UK government is no stranger to successfully attracting private capital and enabling new sectors to thrive. During our interviews, for example, infrastructure funds unanimously recognised the UK government’s success in creating an offshore wind industry. It set a clear ambition to become a world leader, defining targets and enabling investment through Contracts for Difference (CfD), which in turn attracted private sector investment. Having started this journey in the early 2000s, the UK saw offshore wind capacity reach about 10 GW in 2020. Now the UK government is seeking to reach 40 GW by 2030. Those interviewed also noted more broadly that the UK was seen as a clear leader with mechanisms like CfD, the Regulated Asset Base (RAB) regime and capacity markets. Importantly, government support will be required if the necessary net zero investments are to be realised. More specifically, it has a vital role to play in derisking the roll-out of net zero infrastructure assets to make them more attractive for institutional investors. So, what are the key policy recommendations for government? •
Create a detailed net zero infrastructure roadmap for each of the asset classes identified. This will mean the UK government identifying and publishing a targeted level of investment for each technology, articulating the pace of development required and, where relevant, the
location of that development to achieve net zero targets. The recent internal combustion engine (ICE) ban on sales of new diesel and petrol vehicles by 2030 is a good example and a step in the right direction. •
Identify and further develop revenue support mechanisms to drive the efficient, timely, scaled roll-out of each net zero asset class. The UK government should strive to avoid ‘crowding out’ private finance by focusing on revenue support mechanisms rather than financing support for the rollout phase. For each technology, it will need to identify, consult and publish proposals on the revenue support mechanisms. Not all asset classes will require support and the government should be transparent about the triggers for removing support mechanisms at the point they are no longer necessary or efficient.
•
Work with private investors to deliver increased public/ private investment in emerging technologies. Early-stage infrastructure asset classes which require development phase support through a combination of public and private financing will need to be identified. The announcement in the March 2021 Budget to launch a new National Infrastructure Bank with £22bn of funding is welcomed, particularly given its mandate not to crowd out existing private funding. Nevertheless, the government, in collaboration with the private sector, will need to identify the quantum of funding necessary to deliver the required impact for each targeted technology.
The UK government is clearly setting the pace for decarbonisation. It continues to raise its ambitions as illustrated by the recent 10 Point Plan announcement, Energy White Paper and Industrial Decarbonisation Strategy. However, the scale of transformation required for UK infrastructure is daunting. The key to success will be public and private partnership, with government policy unlocking the deployment of low cost and scalable capital at pace. l *This article is based on a PwC Strategy& report titled Unlocking capital for net zero infrastructure.
Petroleum Review | May 2021 17
Energy storage
AMMONIA
Future energy storage solution A mmonia (NH3) and hydrogen (H2) are currently considered to be among the two most promising solutions available for long-term storage in a low carbon economy. We believe that ammonia, as an energy vector of hydrogen, is preferable to pure hydrogen from economic, environmental and technological perspectives. Various ammonia generation techniques are analysed here, as well as the conditions under which zero carbon ammonia makes sense economically. Renewables-dominated energy systems are characterised by high levels of variability and uncertainty. In addition, in many places, peak demand for heating and/or cooling does not coincide with peak renewable generation. There are also studies arguing that climate change itself may increase the likelihood of long periods of low wind generation, leading to increased seasonal variability or intensified fluctuations of wind power generation from year-to-year. These all mean that, in a renewable energy dominated power system, storing large volumes of energy for a long period of time is likely to be crucial in addressing the challenge of meeting peak demand. While there are multiple technologies allowing for the large-scale preservation of energy (ie electrical, electrochemical, mechanical and chemical), the future of energy storage is more often associated with either electrochemical storage (eg batteries) or chemical storage (eg hydrogen or ammonia). Despite the gradually decreasing production cost of electrochemical storage, the cost of storing energy per kWh for a chemical storage such as hydrogen is significantly lower in comparison with most long-lasting batteries. On the other hand, despite often being viewed as an option to address the challenge of long-term, large-scale energy storage, pure hydrogen poses a number of challenges associated with the way in which it is kept and delivered. This has resulted in a growing interest in exploring ammonia as a more advantageous storage option. Although ammonia has the potential to be used as a fuel in a direct combustion process or in ammonia-fuelled fuel cells for land and marine transport or power 24 Petroleum Review | May 2021
Can ammonia be viewed as an economically efficient and technologically suitable solution to address large-scale, long-duration storage in the decarbonised energy systems of the future? ask Aliaksei Patonia and Rahmatallah Poudineh of the Oxford Institute for Energy Studies (OIES).*
Ammonia best fits in the energy system as an energy vector of hydrogen, representing a more economical way of delivering hydrogen over long distances than the conventional way of transporting it in compressed or liquefied forms Photo: Shutterstock
generation purposes, its highest product value can be achieved when used as a hydrogen carrier. Ammonia could thus be appropriate for most power and energy systems. In places with intermittent energy resources, such as wind and solar, ammonia can help to balance the energy system, while sporadically augmenting a country’s energy exports if there is excess generation. A matter of cost and safety Hydrogen and ammonia have roughly the same energy intensity and costs. However, as liquid ammonia has over 50% more volumetric energy than liquid hydrogen – more than twice the volumetric energy of hydrogen gas at 700 bar – it seems to be more economically advantageous, according to a study by the US
Department of Energy (2010). In addition, in comparison to hydrogen, ammonia is easier and less dangerous to handle. Specifically, its vapour pressure is much lower (10 bar at 25oC), which to a great extent simplifies the design of storage tanks for transportation purposes. Therefore, if it is generated through a carbonfree process, ammonia can be used for storing large amounts of energy for a long time in a transportable form because of its specific physical features – this is essential for achieving a low carbon future. Siemens, a company which is working on the extended integration of renewables and energy storage, says: ‘For bigcapacity, long-duration storage, chemical fuels are hard to beat.’ And among chemical storage solutions, ammonia takes a special place due to its unique features. As mentioned, ammonia is relatively easy to handle. Of all the chemical storage options, ammonia produced by means of electrolytic hydrogen generation stands out as a ‘green’ solution that is easier to handle than hydrogen, being less flammable. In addition, with a boiling point of –33.36oC, ammonia is easily liquefied and requires less energy for storage and transportation than hydrogen, whose boiling point is –252.9oC. Finally, its characteristic smell, though offensive in higher concentrations, provides an invaluable early warning of potential lethal emission – a feature not found in hydrogen. Furthermore, ammonia is rapidly deployable. Being one of the most important commodity chemicals in the world, it also represents one of the most widely generated chemical products. That is why ammonia’s handling and shipping infrastructure, including regulations for transportation, are already in place. Traditionally, ammonia is transported and contained in tanks under a modest pressure, which means it could be rapidly deployed to the part of the energy system where it is needed, via pipelines, railroads, barges, ships, road trailers and storage depots. Thus, scaling up ammonia production and distribution does not need extensive investment in infrastructure development. In addition, ammonia bonds
Energy storage
together one nitrogen atom and three hydrogen atoms, which means a litre of liquid ammonia carries a greater mass of hydrogen than a litre of liquid hydrogen itself. As a result, liquid ammonia is a more efficient hydrogen carrier than liquid hydrogen, as more energy can be delivered within the same volume of storage vessel. Finally, ammonia potentially produces no carbon emissions and can be produced carbon-free. Although the traditional process of producing ammonia – steam reforming – normally utilises either natural gas or coal as the main fuel, if it is produced from green hydrogen there would be no CO2 emissions. However, in order to gain wider use, the zero carbon process of ammonia production needs to be proven economically efficient. Disadvantages Ammonia also has a number of disadvantages. For instance, the direct burning of ammonia is technically impeded by its low flammability and radiation intensity. These characteristics hamper ammonia’s self-sustained burning and heat transfer in a combustion process and turn it into a challenging fuel to rely on. At the same time, even with successful ammonia incineration, there is high fuel NOx (nitrous oxides) emission, (whereas hydrogen combustion simply produces water). That is why, to abate NOx emissions, some more advanced technologies, such as selective catalytic reduction, are needed. This will lead to additional cost. Therefore, with the currently available ammonia incineration technologies, this fuel is unlikely to represent a first-choice option for a combustion process. Another disadvantage is that green ammonia production is not yet fully established. As of 2018, pilot plants for the production of green ammonia had just started in the UK and Japan. New demonstration plants have more recently been announced in Australia, Denmark, Morocco and the Netherlands. This reflects the limited popularisation of unconventional ammonia production to date, and its generation based on electrolysis is yet to be well established. Furthermore, despite being less flammable than hydrogen, ammonia is a highly toxic chemical associated with coma and convulsions at a blood ammonium concentration of 200 µmol/l. This toxicity factor appears to be one of the major impediments to deploy these technologies, as public perception is very formative. That is
why, despite its highly identifiable odour making leakage detection easier, proper storage of ammonia and prevention of its leakage should be viewed as a priority – not only by ammonia producers, but also by its storage operators, transporters and end users. This is particularly important as ammonia has a tendency to concentrate near the ground and quickly dissolve in water, which would pose a significant threat to public health. Companies organising ammonia transportation and storage in tanks also need to take measures to avoid ‘ammonia stress corrosion cracking’. In addition, due to the tendency of an ammonia-air mixture to explode when exposed to high heat, preserving the right temperature is crucial. In this context, with a broader use of ammonia in the future and an increased number of actors involved in its handling, undertaking the required safety measures will not only presuppose additional indirect costs but also require a more comprehensive approach to safety training, public education and policymaking. Uses of ammonia and future potential Currently, global production and trade of ammonia is driven by the fertiliser industry, and accounts for roughly 80% of globally generated ammonia. Ammonia is also widely used in the chemical and other related industries as a precursor to nitrogen-containing substances; as a precursor for explosives; softening cotton in synthetic fibres; in antibacterial drugs and more complex commodities. In addition, it is used in industrial refrigeration processes. The application of ammonia in the energy sector is currently very insignificant. Such a low level of penetration of ammonia into the energy sector could be viewed as an opportunity for further progress, especially as ammonia’s physical properties could offer significant room for energy-based applications. For instance, with a significant further improvement of ammonia combustion technologies, pure ammonia can potentially serve as an alternative to fossil fuels in internal combustion engines and generators. Due to the absence of carbon in its chemical structure, the incineration of ammonia does not generate CO2, carbon monoxide, hydrocarbons or soot, but only nitrogen and water. Nevertheless, further technological improvement of the existing combustion engines is needed to increase their
efficiency, to deal with ammonia’s narrower flammability range, higher ignition temperature and lower combustion efficiency when compared to common hydrocarbons. More important, however, ammonia combustion technologies need to be improved in order to enable a complete elimination or minimisation of NOx emissions (caused in all forms of air combustion). Looking forward With further technological progress, ammonia could become an attractive propellant for land transportation and a sustainable alternative to bunker fuel which is currently used in maritime transport. However, new vessels will have to adjust to this type of marine fuel, as ammonia occupies substantially more volume than diesel for the same propulsion amount. Furthermore, although the direct consumption of ammonia is less complex from a technical perspective, measures still need to be taken to address NOx emissions. At the moment, the issue of using ammonia for carbon-free shipping appears to be at an early stage of development. The use of ammonia in fuel cells rather than in internal combustion engines could effectively address the NOx pollution challenge and provide better overall performance – but there’s a greater level of technical challenges to overcome. Ammonia best fits in the energy system as an energy vector of hydrogen. As a hydrogen carrier, ammonia represents a more economical way of delivering hydrogen over long distances than the conventional way of transporting hydrogen in compressed or liquefied forms. In this sense, green ammonia producers could also benefit from the integration of their product into the hydrogen energy economy of the future. Apart from the intrasectoral alignment of different elements of the energy industry across territories and geographic areas, spreading the use of ammonia as a means of long-term large-scale energy storage could allow for cross-sectoral integration, which would offer new benefits to other sectors (such as transport). ● *Ammonia as a storage solution for future decarbonised energy systems, published by OIES, 2021.
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