Also in this issue: Integrating offshore energy systems to secure a low carbon future
Decommissioning deferral doldrums
Portfolio realignment key to decarbonising global energy systems
The magazine for oil and gas professionals in the energy transition
October 2020
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VOLUME 74 | NUMBER 881
Contents
Editor Kim Jackson MEI +44 (0)20 7467 7118 kjackson@energyinst.org
Also in this issue: Integrating offshore energy systems to secure a low carbon future
Deputy Editor Brian Davis +44 (0)20 7467 7142 bdavis@energyinst.org
Decommissioning deferral doldrums
Portfolio realignment key to decarbonising global energy systems
The magazine for oil and gas professionals in the energy transition
October 2020
Digital Officer Elliot Tawney +44 (0)20 7467 7117 etawney@energyinst.org Editorial enquiries +44 (0)20 7467 7118 editorial@energyinst.org
The road to net zero Reducing greenhouse gas emissions is a top priority
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Update & regulars 2
Perspective
3
Upstream
Membership For all membership enquiries please contact membership@energyinst.org or visit www.energyinst.org
5 Downstream
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Terms of control: Petroleum Review is circulated free of charge to all paid-up members of the Energy Institute. To libraries, organisations and persons not in membership, it is available on a single subscription of £330 for 11 issues in the UK and £520 for overseas subscribers. Single issue £30 (UK), £45 (overseas). Agency Commission – 10%. ISSN 0020-3076. Energy Institute Registered Charity No.1097899, 61 New Cavendish Street, London W1G 7AR, UK. © Energy Institute 2020. The Energy Institute as a body is not responsible either for the statements made or opinions expressed in these pages. Unless specifically stated, the magazine is not a partner with, agent of, or in any other way affiliated with any of the advertisers in the publication; nor does it endorse any of the products of such advertisers or external inserts included with the magazine. Those readers wishing to attend future events advertised are advised to check with the contacts in the organisation listed closer to the date, in case of late changes or cancellations. To view the full conditions of this disclaimer, visit http://tinyurl.com/pdq4w7d
Photo: Shell
Magazine of the
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Abbreviations The following are used: mn = million (106) t/d = tonnes/day bn = billion (109) kW = kilowatts (103) tn = trillion (1012) MW = megawatts (106) cf = cubic feet GW = gigawatts (109) cm = cubic metres kWh = kilowatt hour km = kilometre b/d = barrels/day boe = b arrels of oil sq km = square kilometres equivalent t/y = tonnes/year Abbreviations go together eg 100mn cf/y = 100 million cubic feet per year.
Emissions mitigation is a top priority for the oil and gas sector as it moves to a low carbon future
7 Industry 10 Energy Institute
Features
IN THIS ISSUE… We are pleased to announce that Petroleum Review is now available in a new online, easy-to-view, page-turning flipbook format at bit.ly/PRmag_home It’s the best of both worlds – see the magazine online and turn the pages with a click. Also, for this month only, we’ve made the magazine free for everyone to read. Our sister magazine, Energy World, has done the same. EI members can also download pdfs of individual articles, or the whole magazine, in the usual way from bit.ly/PRmag_home This month’s issue of the magazine includes a look at the key role that emissions mitigation will play on the road to net zero and how substantial portfolio realignment will be needed for traditional oil and gas companies to succeed in the energy transition. We also highlight decommissioning developments in the North Sea; review the impact COVID-19 has had on Europe’s gas sector; and shine a spotlight on Spain’s energy transition. We close with a look at the EI Technical Department’s role in supporting the development of a new aviation fuel cleanliness control system that has been adopted by global operating standards. Kim Jackson, Editor
Energy transition 12 An integrated energy future Oil and Gas Authority
Decommissioning 27 Decommissioning deferral doldrums Elaine Maslin
Emissions mitigation 14 Innovation towards net zero Brian Davis
29 A new challenge for offshore wind Elaine Maslin
16 Mitigating methane emissions Mark D Hall 18 Tackling methane emissions reduction Brian Davis 22 Moving towards a cleaner future Berta Gomez Business management 24 Avoid falling off the edge Stephen Rogers, Rodolfo Guzmán and
Daniel Monzón
Europe 30 Deflated gas market Dr Anouk Honoré 32 Energy transition second time round Maria Kielmas EI Technical 34 Meeting a global challenge Martin Hunnybun See also online... Renewable finance – Africa’s last chance? Visit bit.ly/EWOct_Africa
Perspective
PERSPECTIVE
The race to net zero T Tristan Chapman, Vice President of Clean Energy, Lloyd’s Register
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.
he UK Continental Shelf (UKCS) has an important role to play in moving towards a low carbon future. Much progress has been made, from groundbreaking research to substantial funding that will accelerate the energy transition. However, continuous momentum is needed to drive innovation, collaboration and standardisation. The Oil and Gas Authority (OGA) recently published its Energy Integration Project report (see this issue, pp 12–13), in collaboration with Ofgem, The Crown Estate and the Department for Business, Energy and Industrial Strategy (BEIS), which was made possible by a detailed technical study conducted by Lloyd’s Register. The findings are a positive step forward in the journey towards use of 100% clean energy sources. Although this shows progress, the UK, along with global counterparts, still lags in its commitment to achieve net zero targets by 2050. The latest report by the Committee on Climate Change (CCC) was a stark reminder and called for an increased focus on enabling technologies to reduce carbon emissions, as well as highlighting the importance of integrated energy hubs. On a positive note, the net zero commitments have captivated governments, policy makers and private institutions as the ‘North Star’ that unites them. European oil majors have made significant progress, with the likes of Shell, Equinor, Total and Repsol making great strides. More recently, BP took the lead in August, announcing a major new capital commitment that will multiply its investment in renewable energy sources 10-fold by 2030. (See Petroleum Review, September 2020.) The news was welcomed broadly and showed how BP plans to meet the ambitious targets. Its decision to lift the lid on its net zero strategy is an indication that pressure from shareholders and climate activists is making an impact. To date, we have seen progress stalling with the national oil companies (NOCs) abroad who, unlike their European counterparts, are not motivated by public scrutiny. However, it was positive to see PetroChina recently
2 Petroleum Review | October 2020
become the first NOC in the world to announce plans to meet 'near zero' net emissions by 2050, and invest in geothermal, wind and solar power, as well as hydrogen projects (see p7). With more NOCs on board, we could really turn the dial when it comes to creating a cleaner, more sustainable future.
Competitive advantage It could be argued that the UKCS has a competitive advantage in the race to net zero. Firstly, policy drives change, and UK legislators have shown strong support for a low carbon future. With this support, follows proactive and highly engaged trade bodies and think tanks. In July 2020, for example, we saw the formation of The Energy Transition Alliance by The Oil and Gas Technology Centre and the Offshore Renewable Energy Catapult. This collaboration will help drive a programme to develop advanced technologies for hydrogen production and floating offshore wind. Oil & Gas UK (OGUK) is also active in bringing key industry stakeholders together to develop solutions to the net zero challenge. As an active member of OGUK, Lloyd’s Register contributed directly to its Economic Report Roadmap 2035. Furthermore, the offshore wind sector is a real UK success story, with the country boasting the world’s largest installed capacity of offshore wind. Indeed, the ScotWind seabed leasing round for offshore wind projects is expected to surpass £6bn, saving more than 6mn t/y of CO2. In addition, the UKCS benefits from existing infrastructure from decades of oil and gas development. According to Boston Consulting Group, we can expect a potential surge in accelerated shutdowns over the next three years if oil prices stay depressed, which may see a rise in ageing assets being repurposed for the energy transition. The OGA’s latest report includes recommendations for the use of existing pipelines for offshore wind cable installations. Finally, the extreme weather that challenges North Sea oil and gas design can be considered a benefit, presenting a golden
opportunity for offshore wind operations. More to be done Despite the UKCS benefiting from many advantages there is still work to be done. First, more government support and funding is required if the UK is to meet its net zero targets. We have seen some progress recently with the Scottish government’s £62mn support package to aid green recovery, as well ambitious plans from Innovate UK to develop solutions for crosssector decarbonisation by the time COP26 comes around in November 2021. However, the risk is that the funding reaches the front end only for project developers and technology innovators but fails to support the wider supply chain. A mature, sustainable supply chain is essential if we are to achieve scale that makes a real impact. Furthermore, we must continue to explore the options for an integrated energy future. The UK is not in a position to back one horse in this regard. Iceland, for example, was fortunate that it had a clear frontrunner in geothermal energy, allowing the country to swiftly transition to net zero. For the UK, however, there is no clear winner so we must cover all bases from a foundation of oil and gas, offshore and onshore wind, to a mix of blue and green hydrogen, and carbon capture and storage (CCS). Ultimately, the key to the UK’s success in creating a sustainable energy mix lies in standardisation and international collaboration. This must be addressed not only at a policy level, but in the creation of common practices and technical standards worldwide. The progress that has been made to accelerate the energy transition, despite the setbacks caused by COVID-19, is commendable. However, the pressure is on and the targets are clear with a fast-approaching deadline. ●
UpstreamUpdate
How decomm costs compare Removing a steel platform in the North Sea, excluding subsea infrastructure, costs more than double than in Southeast Asia
P
latforms may be similar in characteristics and configuration, but the cost of decommissioning them can differ significantly depending on location, climate and regulations. In its most recent analysis, Rystad Energy estimates that the cost of removing a steel platform in the North Sea, excluding subsea infrastructure, is more than twice the cost of the same task in Southeast Asia. The study is based on two similar steel platforms, one in each region, located in 60 metres of water with four piles, a topside weight of 1,500 tonnes and a jacket weight of 800 tonnes. Facility removal for the platform described above would cost $22.35mn in the North Sea, comparing to just $9.08mn in Southeast Asia, mainly driven by the higher spread rates as well as weather conditions which can represent a significant operational challenge, according to the market analyst. The removal costs include elements such as heavy lift vessels, support barges and tugs, and cutting and diving crews. The entire topsides would be removed in one piece. The substructure removal is the costliest phase of the demolition process. It depends on several factors such as the age of the platform, water depth, climate conditions, structure weight, the number of lifts required and the number of piles. For this study, as the structure is located in less than 100 metres of water and weighs less than 2,000 tonnes, it has been assumed that the four piles would be cut below the seabed and the structures would be removed in a single lift. The structures would
then be transported to shore for disposal using a transport barge. For the Southeast Asian field, a derrick barge with a 2,000-tonne lift capacity would be mobilised from Singapore, requiring two days to reach the field’s location. In the North Sea, a dynamic positioning vessel would be required instead of a derrick barge, as it is better suited to the volatile winds and waves in the region. The day rates for a dynamic positioning heavy lift vessel are on average more than 50% higher than for a derrick barge with the same lifting capacities. To estimate the same mobilisation time, Rystad has assumed that a dynamic positioning vessel would be mobilised from Rotterdam and require two days to reach the field, but it is worth noting that mobilisation from farther away is not uncommon in this region. The removal cost per platform can also vary within the same region depending on the time and scale of the decommissioning campaign. Removing multiple facilities at the same time can help optimise costs by spreading the mobilisation and demobilisation costs across different assets. In addition, flexibility around timing can allow for more attractive rates. Rystad expects vessel rates to hit bottom in 2021 before starting to rise again. As the material disposal cost is heavily dependent on the price of steel, flexibility around the disposal time could help bring down costs further by waiting to dispose of the steel until steel prices are high. With more than 280 assets approaching the end of their lifetime, Southeast Asia faces a
surge in decommissioning in the years ahead. Most of the offshore platforms due to be retired in the region at present have less than 3,000 topside tonnes and are located in less than 75 metres of water. Most Southeast Asian countries do not have fully developed decommissioning legislation in place, and decommissioning projects are therefore dealt with on a case-by-case basis. For example, Petronas implemented a rigs-toreef solution for two platforms at the Dana and D-30 fields off the coast of Malaysia in 2017. On the other hand, the North Sea represents a more mature market where regulations governing the removal of offshore structures are more formalised and consolidated. Consistent with the OSPAR Decision 98/3, facilities have to be fully removed in the North Sea. This prohibits dumping or leaving in place disused offshore installations, effectively requiring that they are completely removed to be reused, recycled, or disposed of on land.
Allsea’s Pioneering Spirit heavy lift vessel removing Shell’s Brent Alpha topsides in the North Sea earlier this year Photo: Allseas
For more information on North Sea decommissioning, see pp27–28 of this issue.
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Petroleum Review | October 2020 3
UpstreamUpdate
Decarbonisation
Investment critical if UK to lead in net zero energy tech The UK’s Oil & Gas Technology Centre (OGTC) has published a comprehensive roadmap setting out the critical technologies needed to deliver an integrated net zero energy system on the UK Continental Shelf (UKCS), highlighting the major economic opportunity this transformation offers. Closing the gap: Technology for a net zero North Sea, produced by Wood Mackenzie for the OGTC, with support from Chrysaor and the Scottish government, outlines how accelerating the development of new energy technologies can dramatically reduce emissions, and how adopting new technologies will harness the full potential of the UK’s world-class natural resources from renewable power sources and oil and gas, to hydrogen and long-term carbon storage. Maximising the opportunities to innovate across the renewable and fossil fuel sectors could create more than 200,000 new jobs across the UK and contribute more than £2.5tn to the nation’s economy by 2050, suggests the study. It would also create a diversified energy sector, support a new generation of highly skilled jobs and open up exciting export potential. The oil and gas sector, including its workforce, supply chain and infrastructure, can enable and accelerate the growth of the renewables sector, while renewable energy sources will be critical in supporting the oil and gas industry on its journey to net zero, states OGTC.
Realising this integrated vision will require £430bn of new investment to close the gap on a number of crucial technologies and accelerate their deployment. These include: •
Oil and gas platform electrification, methane leak detection and flaring mitigation.
•
Larger blades, taller towers and automated inspection technology for fixed offshore wind.
essential for the UK and Scotland to achieve their net zero ambitions. But we need to invest now to close the gap on the key technologies needed to make this ambition a • Innovative hydrogen reality. We need to digitise our membranes and CO2 sorbents offshore energy sector and solve to improve blue hydrogen yield. big challenges like energy storage, infrastructure redeployment, • New saltwater electrolysis technologies to reduce the cost transmission systems and cost-competitive floating wind of green hydrogen production. structures. By doing this, we can • Advanced catalyst materials for create strategic advantage and hydrogen fuel cells to reduce valuable export opportunities.’ costs and improve durability. She continues: ‘With its decades of energy expertise, the UK has • New solvents, sorbents, a huge opportunity to become a membranes and conversion leading manufacturer, designer, solutions to reduce the cost of installer and operator of net zero carbon capture and storage. energy systems. Leveraging our • Power take-off solutions and strength in oil and gas, we can also support systems for marine partner with the renewables sector renewables such as floating to accelerate the delivery of the solar. next generation of energy in the UK – and internationally. This is where Colette Cohen OBE, CEO at OGTC, governments and industry should focus investment at pace in the says: ‘Reimagining the North Sea coming years.’ as an integrated energy system is •
Optimised and standardised floating offshore wind foundation designs.
The oil and gas sector, including its workforce, supply chain and infrastructure, can enable and accelerate the growth of the renewables sector, while renewable energy sources will be critical in supporting the oil and gas industry on its journey to net zero Photo: Chrysaor
IN BRIEF
Shenhai 01 hybrid emergency rescue vesssel Photo: ABB
China’s first Chinese designed and built hybrid emergency rescue vessel, Shenhai 01, has been delivered to Shenzhen Maritime Safety Administration (MSA) by Huangpu Wenchong Shipbuilding. The 78-metre long vessel will be deployed to provide emergency response at sea and carry out rescue operations. The vessel can be fully powered by batteries for up to three hours of operations. Energean has signed 1.4bn cm/y gas supply agreements with the Ramat Hovav power station in Israel. Combined, the agreements increase total firm contracted gas sales from Energean Israel’s flagship Karish project to approximately 7bn cm/y
4 Petroleum Review | October 2020
on plateau. The company is now looking to secure further contracts with the aim of filling the 8bn cm/y capacity of the Energean Power floating production, storage and offloading (FPSO) vessel. First gas is expected in 2H2021. Eni has announced a new gas discovery in the Great Nooros Area in the Mediterranean Sea offshore Egypt. Located in the Abu Madi West development lease, the Nidoco NW-1 exploratory well indicates further extension of the gas potential to the north of the Nooros field. Gas in place at the Great Nooros Area is now estimated in excess of 4tn cf, reports Eni. Eni, through its subsidiary IEOC,
holds a 75% stake in the lease, BP holding the remaining 25% stake. The operator is Petrobel, an equal joint venture between IEOC and the state company Egyptian General Petroleum Corporation (EGPC). Shell is to acquire Kosmos Energy’s participating interests in blocks offshore São Tomé & Príncipe, Suriname, Namibia, and South Africa. The deal consists of an upfront cash payment of approximately $100mn, plus contingent payments of $50mn payable upon each commercial discovery from the first four exploration wells drilled across the assets, capped at $100mn in aggregate.
DownstreamUpdate
Biofuel import restrictions dispute Indonesia is challenging the legality of EU palm oil biofuel restrictions
A
World Trade Organisation (WTO) disputes panel is to assess whether import restrictions created by the European Union (EU) to reduce the use of carbon-intensive biofuels comply with global trading rules. The Indonesian government is challenging portions of the EU’s renewable energy directive (RED) linked to EU guidance limiting the indirect land use change (ILUC) of biofuel feedstock cultivation, writes Keith Nuthall. ILUC presupposes that when land is given over to biofuels, there is pressure to clear virgin forest for displaced food production, increasing carbon emissions and decreasing carbon sinks. The EU considers palm oil production to have a significant environmental impact in this way,
and as a result, under the RED, is calling for EU palm-oil biofuel usage to be phased out by 2030. Indonesia, the world’s largest palm oil producer, has challenged this rule at the WTO, claiming it breaks the general agreement on tariffs and trade (GATT), and agreements on subsidies and technical trade barriers. It is being supported in this case by the US, Malaysia, Norway, Turkey, Singapore, Thailand, Russia, Japan, Korea, India, Honduras, Guatemala, Costa Rica, Colombia, China, Canada, Brazil and Argentina. Indonesia says that EU ILUC calculations mean only palm oilbased biofuels are subject to this phase-out, so they ‘discriminate against palm oil and oil palm cropbased biofuels, which are primarily imported into the European Union,
in favour of like products that are either of EU origin or imported’. Moreover, Indonesia claims the ILUC restrictions were ‘adopted without any adequate statement on the underlying scientific evidence or impact assessment’, a key issue at the WTO where scientific validity often needs to underpin legal trade restrictions. Should Indonesia win its case, the EU may have to review its ILUC rules and its RED restrictions, perhaps allowing the longer-term use of palm-oil biofuels – not just from Indonesia, but also from other WTO member states, including Malaysia, another major producer.
Photo: Pixabay
Emissions reduction
Is carbon neutral LNG setting a new standard? Shell and Jera recently made a number of ‘carbon neutral’ LNG deals. So far, six carbon neutral cargoes have been delivered or agreed, and one long-term supply tender has been launched. But what is carbon neutral LNG? Lucy Cullen, Principal Analyst, AsiaPacific Gas & LNG, Wood Mackenzie, set out to answer this question at the Gastech virtual summit in September. ‘Carbon neutral does not simply mean a cargo creates zero emissions but rather that emissions are measured, certified and offset,’ she told delegates. ‘There is no consensus yet on which emissions should be offset. Various definitions have been applied so far, ranging from an ambitious objective to offset full life-cycle emissions of LNG cargoes, to offsetting part of the value chain.’ While the concept of carbon neutral LNG is still in its infancy, Cullen said there is a need for industry to consider how best to achieve carbon reductions in the long-term. ‘Regardless of how we define carbon neutral LNG, emissions measurement and transparency on these emissions is a challenge which must be addressed. Measurement methodologies and standardisation will be critical if carbon-neutral LNG is to become more mainstream.’ She continued: ‘Gas will play
an important role as a transition fuel globally, even under the IEA sustainable development scenario, which envisions aggressive carbon reductions. The continued rise of renewables will change the competition space for gas and LNG. By bringing greater lower carbon competition, focus will increasingly shift to emissions. Gas is cleaner on a combustion basis, but is it clean enough? That question will be especially important for LNG, as Wood Mackenzie expects its share of the mix to grow at a faster rate than gas overall.’ ‘Full life-cycle carbon offset makes a great news headline. It is ambitious, but can it be adopted widely by the industry? Perhaps not, although it may be achievable for a smaller subset of cargoes or for certain players who have visibility over the full value chain emissions. A more focused approach targeting emission reduction in the upstream/ liquefaction segment – by adopting carbon capture and storage (CCS), and increasing plant efficiency, for example – may be a more achievable long-term objective that can be adopted more widely across the LNG industry.’ While sellers are looking to make projects as carbon competitive as possible, what is motivating buyers? Cullen said there is an element of early mover advantage
at play and good news headlines. ‘These first deals have offered participants experience with carbon neutral transactions. This is important as we move into a lower carbon future. But these deals were not solely motivated by green ambitions and future proofing. Economic and strategic realities still weighed heavily on these decisions and ultimately innovative ways of minimising the impact of the carbon neutral cost premium for buyers helped to create the right opportunities. Until firmer regulation comes into play, these factors will continue to be considerations.’ Cullen added that as LNG demand continues to grow, so will demand for greener LNG. ‘Targeting emissions reductions in certain segments of the LNG value chain seems an achievable route to carbon neutral LNG and wide-scale adoption in the industry,’ she said. ‘But more needs to be done on emissions measurement, standardisation and policy to increase participation and confidence and to encourage buyers. We may very well see that – at the very least – proof or visibility of supplier carbon credentials will become as norm. This will lead to greater buyer scrutiny and differentiation between projects, and prices.’
Targeting emissions reductions in certain segments of the LNG value chain could be an achievable route to carbon neutral LNG and wide-scale adoption in the industry Photo: Shutterstock
Petroleum Review | October 2020 5
DownstreamUpdate
Fuel retailing
Electric forecourt first to open in UK Gridserve is to soon open what it is calling the world’s first Electric Forecourt, located at Braintree, Essex, UK. Household brands including WHSmith, Costa Coffee, the Post Office, Booths, and Gourmade, together with technology partners Tesla, ABB and the AA have joined forces with Gridserve to deliver ‘a “world class” customer experience of the future’. The vision is to make electric vehicle (EV) charging as simple and stress-free as using petrol stations, but with a radically improved customer experience, designed for the modern age, according to Toddington Harper, Founder and CEO of Gridserve. Up to 30 electric vehicles can be charged simultaneously with high power chargers that will enable people to add 200 miles of range in just 20 minutes, and much faster in the future as battery technologies within the cars mature. While vehicles charge, drivers will be able to relax and shop in a state-of-the-art facility that will cater for all their needs. The two-
story building houses a waiting lounge, free superfast Wi-Fi, highend washrooms, a dedicated kid’s area, wellbeing area and business meeting room pods. On the ground floor, a comprehensive retail space includes a coffee shop, convenience supermarket, as well as fresh and frozen food. The AA will be providing customer support via a dedicated team of electric vehicle experts. Drivers will be able to call a dedicated helpline from each supercharger and receive industryleading advice on any technical questions related to the charger or even their vehicle. Some 24 of the high power chargers – half of which can deliver up to 350 kW of power – are provided by ABB, and will be able to charge every EV on the market today. In addition, there are six Tesla superchargers specifically for Tesla vehicles. More than 100 further sites are to be built in the UK in the next five years, at a cost of £1bn. The next two are expected to be located in Norwich and Uckfield.
The network will be powered by zero carbon solar energy and battery storage projects, ensuring carbon emission targets can be met, whilst also keeping prices low, says Gridserve. To achieve this, the company is developing several large solar farms, supported by grid-scale batteries, as part of its ‘Sun-to-Wheel’ initiative to ensure that 100% of the electricity used at its forecourts is renewable and, from the grid’s perspective, sustainable. It recently acquired the UK’s first subsidy-free solar farm – the Clayhill Solar Farm in Bedfordshire.
Artist’s impression of the Braintree, Essex, Electric Forecourt, which is due to open soon Photo: Gridserve
IN BRIEF
Photo: Amber Petroleum/Greenergy
Photo: ADNOC
Greenergy has agreed to acquire Amber Petroleum, an independent fuel distributor and retailer based in the Republic of Ireland, for an undisclosed sum. Amber’s operations include company-owned and dealer-owned forecourts, comprising a network of 35 sites around the country, along with fuels distribution and home heating depots. ADNOC Onshore, a subsidiary of the Abu Dhabi National Oil Company (ADNOC), has awarded two engineering, procurement and construction (EPC) contracts to upgrade two main oil lines and crude receiving facilities at the Jebel Dhanna terminal in the Emirate of Abu Dhabi.The EPC contracts have a combined value of around $245mn and were awarded to China Petroleum Pipeline Engineering Company and Abu Dhabi-based Target Engineering Construction. The capacity of the two main oil lines which transport ADNOC’s premium grade Murban crude oil from its oil fields at Bab (BAB), Bu Hasa (BUH), North East Bab (NEB), and South East (SE) to Jebel Dhanna terminal will be increased by 30%. The upgrade at the terminal will
6 Petroleum Review | October 2020
enable it to receive Upper Zakum and non-system crude for delivery to the nearby Ruwais Refinery West project. A total of 12 companies comprising the UK’s producers of liquid renewable fuels and the majority of the green gas used in UK transport have formed the Renewable Transport Fuel Association (RTFA) which aims to be the ‘go to’ voice for UK renewable transport fuel producers and suppliers. RTFA’s founder members are Associated British Foods, ABSL, Alco, Argent Energy, Calor, CNG Fuels, Ensus UK, Gasrec, Greenergy, Nova Pangea, Olleco, and Velocys. The trade body is calling for rapid action to decarbonise transport through use of bioethanol, biodiesel, biomethane and biopropane, to help achieve the UK government’s net zero emissions by 2050 target. It says the UK cannot afford to wait for the uptake of electric vehicles (EVs) and hydrogen to achieve this goal. In the next 30 years, the UK power sector needs to build 48 natural gas units, 66 biomass facilities, six nuclear power stations and 6,520 offshore wind turbines, as well
undefined unit numbers for 20 GW of onshore wind, 80 GW of solar, and 15–30 GW of energy storage in order to meet the UK’s net zero 2050 target, according to a new white paper from Atkins. The study calculates that the UK is currently achieving 43% of the required build rate and says the future energy system will rely heavily on three industries still in their infancy – carbon capture and storage (CCS), energy storage and hydrogen production. For more details, visit bit.ly/PROct2020Atkins Russia is expected to witness the highest global working gas storage capacity additions, contributing around 21% of global additions by 2024, according to the latest analysis from GlobalData. Russia is likely to increase working gas storage capacity by 585bn cf by 2024, of which nearly 573bn cf has received necessary approvals for development. China is expected to be the second-highest contributor to the global working gas storage capacity additions, contributing around 17%, or 473bn cf, by 2024. Visit bit.ly/PROct2020Gas
IndustryUpdate
EC proposes 55% emissions cut by 2030 The European Union needs to ‘go faster and do things better’ if it is to achieve its goal of becoming the first climate-neutral continent by 2050
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t the heart of the European Green Deal, regarded as the blueprint for Europe’s energy transition, is the mission to become the first climate-neutral continent by 2050. However, when presenting her 2020 State of the Union address to the European Parliament Plenary on 15 September, European Commission President Ursula von der Leyen, stated: ‘We will not get there with the status quo – we need to go faster and do things better.’ She went on to state that following a wide public consultation and an extensive impact assessment, the European Commission is now proposing to increase the 2030 target for emissions reduction to at least 55%, up from the previous target of 40%. ‘Our impact assessment
clearly shows that our economy and industry can manage this,’ she said, adding that meeting the target would put the EU ‘firmly on track for climate neutrality by 2050 and for meeting our Paris Agreement obligations’. She also noted that: ‘If others follow our lead, the world will be able to keep warming below 1.5oC.’ Von der Leyen also announced that 30% of the €750bn NextGenerationEU budget will be raised through green bonds. And 37% of funding will be invested in European Green Deal objectives, including ‘lighthouse’ European projects – hydrogen, green building and 1mn electric charging points. In the rest of her address, von der Leyen pledged that the European Commission will drive a sustainable and transformational recovery that will give Europe
Forecasting
In her State of the Union Address to the Euroepan Parliament Plenary, European Commission President Ursula von der Leyen presented the key issues that the EU needs to focus on over the next year Photo: European Commission
Emissions reduction
Shell rethinks energy in 2020s The COVID-19 pandemic is changing the world in significant ways. There will be three dramatic tensions at play in the 2020s – between wealth, security and health – according to the latest analysis from the Shell Scenarios team, which explores the potential impact of the crisis. People will seek all of these to some extent, suggests Shell, but what societies choose to prioritise may differ. These priorities, along with different societal capabilities, such as public health, could shape the decade. The analysis – titled Rethinking the 2020s – forecasts that future energy demand will grow again as populations increase and economies develop, but growth will be slower than in the past and will vary in all pathways. COVID-19 has reset the starting point for growth, and the nature of that growth will depend on economic recovery, government policy and consumer choices. For example, in a world that prioritises security, relatively depressed economic development puts growth in demand for total primary energy over the decade at only around half the level of other pathways. Shell sees high growth in solar and wind energy in all pathways, but the energy system will still depend significantly on fossil fuels in the 2020s. In all pathways, demand for
a global platform to lead economically, environmentally and geopolitically, outlining the key issues the European Union needs to focus on over the next 12 months.
gas will continue to grow, but coal will peak sometime this decade. The outlook for oil varies. Oil demand is hit harder than natural gas or coal as the COVID-19 lockdown affected personal mobility most, which accounts for about 40% of overall oil demand, mainly in road and air transport. In the past 20 years, the fossil fuel share of global primary energy demand has remained steady at around 80%. This falls by around 2.5% in the wealth and security pathways and more than twice that in the health pathway by 2030. All pathways see a pause in the growth of CO2 emissions, with the longer-term CO2 profile determined mainly by populations and GDP growth, and furthermore by the choices societies make as they emerge from this crisis. Energy transitions do not go backwards, regardless of what society chooses to prioritise. Transitions are strongly technologydriven – which requires long lead times – and in most cases are already in progress. In a world that prioritises health, the major reshaping of the global energy system could provide the trigger to reach the goals of the Paris Agreement, suggests Shell.
PetroChina unveils ‘near zero’ emissions ambition PetroChina has become the first national oil company (NOC) in the world to announce plans to meet ‘near zero’ net emissions by 2050 and invest in geothermal, wind and solar power, as well as pilot hydrogen projects. Commenting on the news, Wood Mackenzie’s Principal Analyst Max Petrov says: ‘PetroChina’s announcement is illuminating even if details are lacking. It reveals one of the more ambitious paths the company could take to remain competitive and relevant in 30 years’ time. A statement of intent from the world’s largest oil and gas spender and one of the biggest hydrocarbon producers should not be dismissed lightly.’ He continues: ‘PetroChina has started to address its ambition on climate change risk mitigation, but not the transition plan. It currently spends approximately $300mn on new energy initiatives, just 1% of overall budget. Management plans to raise this to $500–750mn over the next five years, increasing again to $1.5bn in the second half of this decade. But even as absolute spend rises, PetroChina will need to go further given its scale and global reach. Low carbon investment will need to greatly accelerate beyond 2025 if the company is to get close to its near zero carbon ambition.’ For more on this, see Petroleum Review’s forthcoming November 2020 issue.
Petroleum Review | October 2020 7
IndustryUpdate
Forecasting
BP scenarios for global energy to 2050 The recently published 2020 edition of the BP Energy Outlook looks out to 2050 – a decade further than in previous editions – and is focused around three main scenarios: ‘Rapid’, ‘Net Zero’ and ‘Business-as-Usual’ (BAU). In all three scenarios, global energy demand grows, driven by increasing prosperity and living standards in the emerging world. Primary energy demand plateaus in the second half of the outlook in Rapid and Net Zero, as improvements in energy efficiency accelerate. In BAU, demand continues to grow throughout the period, reaching around 25% higher by 2050. All three scenarios see a decline in the share of the global energy system for hydrocarbons and a corresponding increase in renewable energy as the world increasingly electrifies. The scale of the shift varies significantly across the scenarios, with the share of hydrocarbons in primary energy declining from around 85% in 2018 to between 65–20% by 2050 and renewable energy rising to 20–60%. The scenarios all see oil demand fall over the next 30 years – 10% lower by 2050 in BAU, around 55% lower in Rapid and 80% lower in Net Zero – driven by the increasing efficiency and electrification of road transportation. In all three scenarios the use of oil in transport peaks in
the mid- to late-2020s. The share of oil in meeting transport demand falls from over 90% in 2018 to around 80% by 2050 in BAU, but to 40% in Rapid and to just 20% in Net Zero. Global demand for gas varies significantly across the scenarios. It peaks in the mid-2030s in Rapid and in the mid-2020s in Net Zero, and by 2050 is broadly similar to 2018 and around a third lower, respectively. In BAU, gas demand increases throughout the next 30 years to be around a third higher by 2050. Natural gas can potentially support a shift away from coal in fast growing, developing economies where renewables and other nonfossil fuels may not be able to grow sufficiently quickly to replace coal; and combined with carbon capture, use and storage (CCUS) as a source of (near) zero carbon power. Gas combined with CCUS accounts for between 8–10% of primary energy by 2050 in Rapid and Net Zero. Renewables are the fastest growing source of energy over the next 30 years in all the scenarios, growing from around 5% of primary energy in 2018 to 60% by 2050 in Net Zero, 45% in Rapid and 20% in BAU. Decarbonisation of the energy system leads to increasing amounts of final energy use being electrified. By 2050 the share of electricity in total final consumption increases
from a little over 20% in 2018 to 34% in BAU, 45% in Rapid and over 50% in Net Zero. As the energy system progressively decarbonises, there are increasing roles for both hydrogen and bioenergy. Use of hydrogen increases in the second half of the Outlook in Rapid and Net Zero, particularly in activities which are harder or more costly to electrify. By 2050, hydrogen accounts for around 7% of final energy consumption (excluding non-combusted) in Rapid and 16% in Net Zero. The shift away from traditional hydrocarbons also leads to an increasing role for bioenergy, which, by 2050, could account for around 7% of primary energy in Rapid and almost 10% in Net Zero. The scenarios show that achieving a rapid and sustained fall in carbon emissions is likely to require a series of policy measures, led by a significant increase in carbon prices. The scenarios outlined in this year’s Outlook represent a notable shift from those presented in 2019. Bernard Looney, BP CEO, noted that the report had been ‘invaluable’ in helping the company ‘better understand the changing energy landscape’ and had been ‘instrumental’ in helping BP develop its new strategy.
BP’s new strategy includes the goal of reducing emissions from its operations and those associated with the carbon in its upstream oil and gas production by 30–35% and 35–40% respectively by 2030 Photo: BP
IN BRIEF
Photo: Pixabay
BP and Equinor have formed a new partnership to develop offshore wind projects in the US. This includes the development of existing offshore wind leases on the US East coast and jointly pursuing further opportunities for offshore wind in the country. BP is also to purchase a 50% interest in the Empire Wind and Beacon Wind assets from Equinor, at a cost of $1.1bn. The agreement comes a month after BP announced its new strategy, including plans to increase its annual low carbon investment 10-fold to around $5bn/y and grow its developed renewable generating capacity from 2.5 GW in 2019 to around 50 GW by 2030. Equinor, Jera and J-Power have partnered and entered a joint bid agreement prior to Japan’s upcoming Round 1 offshore wind auction. The three companies will jointly evaluate and work towards
8 Petroleum Review | October 2020
submitting a joint bid in the Round 1 auction once the Japanese government officially opens what will be country’s first offshore wind auction. Establishing this consortium is in line with Equinor’s renewable strategy of building scale in core regions and developing growth options in selected markets to become a global offshore wind major. For more details, visit bit.ly/PROct2020Equinor Total and Macquarie’s Green Investment Group have concluded a 50:50 partnership to develop a portfolio of five large floating offshore wind projects in South Korea with a potential cumulated capacity of more than 2 GW. The first project of around 500 MW will be launched by the end of 2023. With the announcement of its new Green New Deal plan in July, South Korea has re-affirmed its strong ambitions to develop renewable
energies that will account for at least 20% of the country’s power mix by 2030, including 12 GW of offshore wind capacity. Europe has reached a stage where big-scale carbon capture and storage (CCS) projects make financial sense and could trigger up to $35bn in development spending until 2035 – by which time up to 75mn t/y of CO2 could be captured and stored on the continent, according to Rystad Energy analysis. In Europe alone there are around 10 larger projects with CCS that are planned and have a high chance of being operational by 2035. Total capital investment for these projects is expected to reach $30bn, in addition to operational expenditure totalling $5bn until 2035. For more details visit bit.ly/PROct2020CCS
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EI News
Record interest in EI Awards
Maria McKavanagh, CEO of Verv, accepts her EI Young Energy Professional Award at the 2019 EI Awards Ceremony
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record 162 entries have been received for the Energy Institute (EI) Awards 2020, from projects and individuals as far flung as the US, UAE, Singapore and Nigeria. This year also brings three new award categories – Low Carbon; Access to Energy; and Talent, Development and Learning – to help accommodate the wide-ranging entries the EI has received in past years. This is the 21st year of the Awards, which are recognised as one of the energy industry’s most prestigious competitions.
Showcasing the most ground-breaking work in the energy sector, they provide a platform for the industry to celebrate those businesses and individuals who innovate, communicate and drive up the standards of professionalism. And for the first time, the ceremony this year is free to attend as an online event, so put on your glad rags, fire up your laptop and join us on the 26 November to celebrate the best there is in the world of energy. Register at energy-inst.org/ei-awards-booking-link
EI Library Members once again can access hard copy items held in our London Library collection. Although the Library continues to be closed to the public it is now being staffed from Tuesday to Thursday each week. This means that our Library team are able to loan hard copy items by post on request. As always, the entire Library catalogue, including online and physical resources, can be searched and either accessed or requested through the EI Knowledge Service website at knowledge.energyinst.org
Member update: renewals If you are an EI member you should be receiving annual renewal information in the next few days. In the renewal notice, Louise Kingham OBE FEI talks about the last few months and the EI’s concentration on services to support members during the COVID-19 pandemic. Membership subscriptions are frozen for 2021 and there is also news of some new services and initiatives to expect over the coming year. As with last year, members who pay by Direct Debit will receive an email rather than a letter, but you can read a copy of Louise’s message at energy-inst.org/Louiserenewals. If you are a UK taxpayer and pay your own fees you may be able to Gift Aid your membership subscription –it helps us do more with your money at no cost to you, and you can sign up online. More information is at energy-inst.org/manage-your-membership
10 Petroleum Review | October 2020
Deceased members The EI is sad to report the deaths of the following EI members: Born Mr P A Bense CEng FEI 1905 Dr M Bosio CEng FEI 1922 Dr J R V Brooks CBE MEI 1938 Mr H W Dean FEI 1928 Mr C G Faultless MEI 1938 Mr D Ford MEI 1931 Mr P R Johnson MEI 1945 Mr J P Lauder CEng FEI 1917 Mr G Lonie CEng FEI 1929 Mr G R Loram FEI 1927 Mr W A Mellor CEng MEI 1923 Eur Ing D H Napier CEng FEI 1923 Mr M G Nash CEng MEI 1923 Mr K R Parker CEng FEI 1933 Mr L F Riley CEng FEI 1929 Mr F D Routledge FEI 1937 Mr I Taylor FEI Mr P J Watson FEI 1928 Mr J Williamson FEI 1931
EI News
EI in Westminster and Whitehall
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upporting the quality of energy policymaking is a central part of the EI’s social purpose and, in the UK, September saw external engagement by EI Fellows with policymakers in both Parliament and the civil service. At a special meeting of the Parliamentary Group on Energy Studies entitled ‘Success at COP26 starts at home: leading by example on net zero’, the EI convened an expert panel to present the findings of this year’s Energy Barometer. EI Chief Executive Louise Kingham was joined by Steve Holliday FREng FEI, President of the EI, and Professor Robert Gross FEI, EI Council Member and Director of the UK Energy Research Centre. Kingham urged parliamentarians to listen to the views of energy
professionals: ‘They’re engineers, technicians, scientists and economists, driven by the evidence and the practicalities of what it takes to keep the electrons and molecules flowing to our homes, businesses and vehicles. They know what they’re talking about, and they’re also the people we’re looking to to deliver net zero.’ Holliday made a powerful connection between what happens at home in the UK and next year’s climate talks in Glasgow: ‘Without immediate domestic policy steps from ministers, the UK’s international credibility is on the line. Orchestrating the international "race to zero" will call for every bit of credibility we can muster.’ And Professor Gross made the Barometer’s central case for enduring
action on energy efficiency: ‘It’s singled out as the biggest missed opportunity of the past decade and is consistently seen as the best measure to meet the shortfall in the fifth carbon budget. Retrofitting our existing housing stock would have big economic, social and environmental cobenefits as part of a resilient recovery from the pandemic.’ Steve Holliday separately joined Lord Deben, Chair of the Committee on Climate Change, and Alice Barrs, Head of UK Political Affairs at RWE, to speak to the All Party Parliamentary Group on Energy Costs, discussing the question, ‘Delivering net zero by 2050: Does government have an effective plan?’. Meanwhile another expert panel of EI Fellows was lined up to provide complimentary training for policy officials new to energy in the Department for Business, Energy and Industrial Strategy (BEIS). The ‘Energy Fundamentals’ course has been developed by the EI to provide an introduction to the basic concepts and interconnections within the energy system between heat, transport and electricity. The sessions always generate much interest and interesting questions from new joiners in the department. In the hot seats on this fourth occasion were Dr Joanne Wade OBE FEI of the Association of Decentralised Energy, Professor Matthew Leach FEI of Surrey University, Philip New FEI of the Energy Systems Catapult and Prof Peter Taylor FEI of Leeds University. You can watch recordings of the two parliamentary sessions at https://bit.ly/2ZBQNDD
Energy Efficiency and Heat conferences back
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he COVID-19 pandemic may continue to prevent face-to-face events taking place, but it’s been full steam ahead over the past month for the EI’s conference programme, with the return of two regular fixtures. The Energy Efficiency conference was back, bringing together the EI’s community of energy management practitioners with key figures working on policy and delivery in this vital field. Speakers discussing ‘the road to net zero’ came from diverse organisations including BEIS, Ofgem, IBM, Co-op, National Grid, Ørsted, Rolls-Royce,
Nestlé, Lightsource BP and Keltbray. And Heat and Decentralised Energy 2020 was held in collaboration with the Association for Decentralised Energy. The event focused on ‘levelling up with local energy’, with participants from central and local government, industry and civil society discussing the sector’s benefits to both decarbonisation and localised jobs, skills and industrial strategy. Meanwhile, the busy programme of free EI LIVE webinars continues apace. In September, Past EI President Professor Jim Skea CBE FRSA FEI was joined by Andy
Samuel, CEO of the Oil and Gas Authority to discuss ‘the new context for energy in Scotland’. A special event took the Generation 2050 initiative to Climate Week NYC 2020, seeing young energy innovators and entrepreneurs from around the world discussing how tomorrow’s energy leaders are shaping up. And a webinar held in collaboration with IBM drew together expert views from across the world of energy on business continuity during COVID-19 and beyond. Forthcoming free EI LIVE webinars are at energy-inst.org/EI-LIVE Petroleum Review | October 2020 11
Energy transition
STRATEGY
An integrated energy future Integration of offshore energy systems, including oil and gas, renewables, hydrogen and carbon capture and storage (CCS), could contribute about 30% of the UK’s total carbon reduction requirements needed to meet the 2050 net zero target, according to a recent Oil and Gas Authority report.
I
Burbo Bank wind farm development in Liverpool Bay Photo: Ørsted
ntegration of offshore energy systems, including oil and gas, renewables, hydrogen and carbon capture and storage (CCS), could deliver about a third of the UK’s total carbon reduction requirements needed to meet the government’s 2050 net zero target, according to the recent Oil and Gas Authority’s (OGA) Energy Integration Project report. Co-authored by Ofgem, the Crown Estate and the Department of Business, Energy and Industrial Strategy (BEIS), the report also highlights the additional potential for offshore renewables (wind, wave and tidal) to contribute a further 30% towards the UK’s net zero goal. This means the UK Continental Shelf (UKCS) could support, in combination with complementary investments in onshore energy infrastructure, around 60% of the UK’s decarbonisation requirements – contributing significant muscle to the nation’s energy transition. Over 30 energy integration projects are already underway across the UKCS, with more than 10 actively being engaged by the OGA alongside this study. Importantly, the report concludes that not only is the close coordination of these technologies valuable in terms of energy production and cutting greenhouse gas (GHG) emissions, but their integration would help new and
12 Petroleum Review | October 2020
innovative technologies become more attractive economically and support significant new job creation. New focus In his introduction to the report, Dr Andy Samuel, OGA Chief Executive, notes that the OGA has increased its focus on the energy transition in favour of the former emphasis on maximising economic recovery (MER) on oil and gas resources on the UKCS. The Energy Integration Project began in early 2019 with a £900,000 grant from the Better Regulation Executive’s (BRE) Pioneer Fund, to explore how different energy systems (oil and gas, hydrogen and CCS) could be coordinated across the UKCS for environmental and efficiency gains, including identifying technical, regulatory and economic hurdles. Working with BEIS, The Crown Estate, Ofgem and others, an interim report was published in December 2019. Notably, since the project began, the UK became the first major economy to set a target of net zero emissions by 2050. In response, the OGA began to refresh its core strategy to integrate net zero and develop benchmarking to track and monitor emissions performance. The focus of this project also progressed to include quantifying how energy integration could contribute to emissions reduction.
‘[Energy] integration has the potential to make a deep and meaningful impact, with a possible 30% contribution towards the country’s overall net zero target, primarily through CCS plus hydrogen,’ emphasises Samuel. ‘Adding offshore renewables (wind, wave and tidal) could take that up to 60% of the abatement required in 2050; demonstrating that the UKCS is a critical energy resource.’ The OGA is working with other regulators, government and industry to ensure this potential is delivered at pace as part of the UK green recovery. He continues: ‘The project has focused on identifying the opportunities and specific barriers that organisations can address. But also sits in the context of wider UK government policy, such as the work on business models and carbon pricing, which will be important in shaping progress.’ Samuel recognises that energy integration can help the oil and gas industry reduce production emissions, and accelerate the progress of CCS and hydrogen in support of the net zero target – which are essential for the sector’s ‘social licence to operate’. Furthermore, offshore renewables offer real opportunities for increased collaboration with oil and gas skills and supply chain expertise for further expansion.
Energy transition
Let’s take a look at some of the components of the report in more detail. Emissions abatement The UKCS is a critical energy resource that could play a significant role in achieving the UK’s net zero target. Working from a 2018 baseline, energy integration technologies (offshore electrification, CCS, blue and green hydrogen) could contribute around 30% of the UK emissions abatement needed. In addition, these technologies could support expansion of offshore renewables, which could deliver a further 30% contribution to the net zero target. The remaining 40% could be delivered through onshore measures. Offshore oil and gas installations emit about 10mn tCO2e/y to generate power, equivalent to about 10% of total UK energy supply emissions. Therefore, offshore platform electrification will be key to cutting upstream oil and gas emissions. The report suggests that offshore electrification may unlock faster growth of renewables, expansion of offshore transmission infrastructure, and the establishment of floating wind power technologies in the UK, contributing to the ambition for 75 GW capacity by 2050. Putting some figures in context, UKCS oil and gas installations required ~21 TWh of power in 2018 (equivalent to the domestic electricity consumption of Wales). Generating this power from natural gas or diesel led to emissions of ~10mn tCO2e (~10% of the UK energy sector). As power accounts for ~70% of all offshore oil and gas emissions, replacing thermal generation with power from shore or offshore renewables will be crucial for realising meaningful cuts to the sector’s GHG emissions. Production of blue hydrogen, from methane reforming of natural gas to low carbon fuel, can also accelerate the growth of CCS, to eliminate emissions while leveraging operational and logistical efficiencies from co-location, making this one of the lowest cost technologies for net zero today. Green hydrogen, produced by electrolysis using renewable electricity, will be critical to support the expansion of offshore wind power in the 2030s and beyond, addressing issues with power intermittency and long-distance transmission losses (ie from northern North Sea areas). Development of CCS is seen to be critical to achieving net zero and the removal of 130mn tCO2 from
Key energy assumptions BEIS reported that estimated UK GHG emissions were 415.5mn tCO2e in 2018 and projected GHG emission reduction until 2032 according to the fourth and fifth UK Carbon Budgets. From 2033, GHG emissions are forecast to decline linearly to net zero in 2050. According to BEIS’s UK CCS deployment pathway (2018), an estimated 130mn tCO2e/y of negative emissions technologies are needed to reach net zero emissions in 2050. The 2019 Committee on Climate Change (CCC) Net Zero: The UK's contribution to stopping global warming report estimated that the UK needs to abate up to 175mn tCO2e through CCS by 2050, of which 125mn tCO2/y will come from blue hydrogen (produced from natural gas) and power and industrial combustion sources. National Grid’s Future Energy Scenarios (NG FES) Two Degrees pathway (2019) projects conversion of 377 TWh/y of natural gas (28% of UK demand today) to blue hydrogen by 2050, in a process which generates 70mn tCO2/y to CCS. As a result, the OGA projects CO2 injection rates growing to 130mn tCO2/y by 2050, with a 70–60 CO2 source split between blue hydrogen and post-combustion capture. This rate of growth reflects that pilot-scale projects will be deployed in the 2020s, followed by a linear progression of commercial-scale plants in the 2030s and 2040s. ● UK emissions, in line with the BEIS UK CCS deployment pathway, to reach net zero emissions by 2050. It is estimated that the UKCS has enough CO2 storage capacity to fully support UK needs and oil and gas infrastructure which can be reused to support energy integration. The CO2 storage capacity in UKCS reservoirs is estimated at 78 Gt, sufficient for hundreds of years of UK CCS needs. The UK oil and gas industry is considered to be well positioned to redeploy its skills in this area, with strong capabilities and existing infrastructure available to accelerate CCS deployment. Combining these technologies into ‘energy hubs’, linked to existing and future onshore net zero clusters, can accelerate deployment and improve project economics through scale and sharing of facilities. Economics Offshore technologies can provide efficient ways to abate the UK CO2 emissions, with a broad range of levelised costs per tonne of CO2 abated – in the range of ~£10 to ~£100/tCO2. Costs will not only depend on location and logistics, but also on a number of factors that can be influenced, including infrastructure availability and access to market; re-use of existing infrastructure, which can offer ~20–30% capex efficiency for selected CCS projects; and new technology development (eg abating costs of electrolysis/ green hydrogen and floating wind power).
Regulation The OGA report maintains that effective regulations are in place covering individual energy sectors on the UKCS (including oil and gas, electricity generation and transmission from wind power and other renewables sources). As new technologies emerge, the regulators are engaged in further work to help unlock energy integration opportunities, eg to manage new technologies and operations (like CCS and hydrogen); supporting crossindustry collaboration (eg oil and gas and wind power); and to accelerate efficiencies (eg offshore transmission infrastructure sharing). Next steps To realise the vision of the UKCS as a critical enabler for net zero, the Energy Integration Project recommends: •
Accelerating and enabling early energy integration projects.
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Leveraging oil and gas assets and capabilities, essential for CCS, and preserving existing infrastructure value.
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Taking anticipatory steps to co-ordinate regulatory processes for the deployment of UKCS energy integration technologies.
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Harnessing the power of digitalisation and Big Data to enhance visibility of cross-industry opportunities, accelerating planning and regulatory activities.
To take this forward, the OGA, together with project partners, is implementing a number of actions, including accelerating progress on pioneering projects to ensure cross-industry opportunities and timely regulatory engagement; enhancing regulatory co-ordination, to anticipate and address regulatory barriers and/or enablers for CCS, hydrogen and offshore electrification; and improving data availability, quality and access through co-ordinated efforts across government and relevant industries. With the above in mind, following analysis of technical options for energy integration in 1Q–2Q2019 with Lloyd’s Register in Phase 1, and economic and regulatory assessment in partnership with EY in 3Q2019 and 1Q2020 in Phase 2, Phase 3 of the Energy Integration Project is proposed to implement recommendations accelerating UKCS energy projects. ●
Petroleum Review | October 2020 13
Emissions mitigation
TECHNOLOGY
Innovation towards net zero I n order to meet the Paris Agreement goals many countries are targeting to curb global warming and reach net zero emissions by the second half of the century. However, in many cases this will only be possible with significant drive and innovation. In a recent report* the International Energy Agency (IEA) analysed over 400 clean energy technologies and commented that: ‘Although renewable technologies are in use and can deliver significant emissions reduction, they will not be sufficient on their own to meet the ambitious targets.’ In particular, few technologies are currently available to reduce emissions to zero in sectors such as trucking, shipping, aviation and heavy industries. IEA Executive Director Fatih Birol commented: ‘Without decarbonising the transport sector there is no chance whatsoever of meeting climate targets. Around half of emissions reductions that are needed still require major innovation of clean technologies.’ The most critical technologies needing innovation are battery technologies, carbon capture and storage (CCS) and low carbon hydrogen, which are currently mostly in the development phase and/or costly. In a wide-ranging report the IEA looked at the ‘Fastest Innovation Case’ and asked: How far could innovation take us? It is an exciting vision, given that the IEA’s Sustainable Development Scenario aims to reach net zero emissions from the energy sector within five decades on the back of ambitious technological change, demanding the fastest and most successful energy technology innovation in history to meet the Paris Agreement goals. Many technologies are still in the laboratory or early prototype stage and will require relatively short and successful routes towards commercialisation, despite risk of market bottlenecks and resource constraints along the supply chain if co-ordination fails during rapid expansion. ‘There is little or no precedent for the required pace of innovation’, notes the IEA. The Fastest Innovation Case needs to enable 9 GtCO2 of additional net emissions savings 14 Petroleum Review | October 2020
Huge acceleration of clean energy innovation is required on the road to net zero, according to the International Energy Agency. Looking forward, Brian Davis presents a selection of key technologies which are being addressed.
compared to the Sustainable Development Scenario in 2050, which is equivalent to tackling almost 30% of today’s energy sector emissions. Key clean energy technologies at demonstration or large prototype stage today, including hydrogen-based steel production, electrolytics hydrogen-based ammonia-to-fuel vessels, and carbon capture for cement production, are assumed to reach market only six years from now under the Fastest Innovation Case – twice as fast as the IEA’s current Sustainable Development Scenario. The only case of such rapid progress historically is LED development, which are small enough to be mass produced and require a relatively low level of capital expenditure during the prototyping and demonstration phase. Electrification is key Electrification is a key strategy, which would see the share of electricity in total energy demand reach 45% by 2050 under the Fastest Innovation Case, compared to about 20% today. Transport and electricity will be responsible for about 95% of additional electricity demand. Faster battery manufacture and improved smart charging infrastructure is required. Without advances in alternative chemistries to lithium-ion, the use of batteries for transport to move beyond road vehicles and shortdistance shipping and aviation will be difficult. Gravimetric energy densities (at cell level) will have to triple from current levels. At least two alternative battery chemistries – lithium-sulphur and lithium-air – have the potential to provide such advances, although both are at the small prototype stage today. These
developments promise more rapid uptake of electric vehicles (EVs), with potentially 80% and 60% of light- and heavy-duty vehicles on the roads in 2050. Nearly 3.5 times more battery-electric heavy vehicles could be deployed in this scenario. Electric heating Large-scale electric heating would also have to penetrate more deeply into the industrial sector under the Fastest Innovation Case. Rapid advances are underway to demonstrate large-scale hightemperature electrical heating for industrial processes, that do not involve electricity-conducive materials. However, most of the electromagnetic technologies are at the concept validation stage and would have to reach markets within a decade, with average deployment maintained at a new 1mn tonne installation (equivalent to half the capacity of a
conventional integrated steel mill) every two months up to 2050. In the buildings sector, around 30 GW thermal capacity from integrated heat pumps would need to be installed every month on average from 2030 to 2050, a big challenge.
Photo: Shutterstock
Hydrogen and hydrogen-derived synthetic fuels Meanwhile, demand for hydrogen and hydrogen-derived synthetic fuels (including ammonia) would have to grow by almost 25%, relative to the current Sustainable Development Scenario, with most demand coming from the industry and transport sectors. To put this in perspective, almost two new 1mn tonne steel plants based on full hydrogen reduction would
Emissions mitigation
EI pledged to net zero The Energy Institute (EI) has pledged to net zero. EI President Steve Holliday FREng FEI says: ‘The climate emergency demands changes in behaviour across the board – from governments, businesses and societies. The EI is resolved to end its own impact on the climate and is joining a growing number of organisations on an ambitious but managed journey to net zero. We do not yet have all of the answers, but I hope our members, partners and customers will be inspired to follow.’ Work to date Apostolos Gkrimpas, EI Training Manager, explains: ‘Following the successful submission of our science-based targets at the end of May 2020 as one of the signatories of the “Pledge to Net Zero”
need to be installed every month from today to 2050. This would call for radical changes to existing steelmaking capacity. While in transport, over 60 ammoniafuelled large vessels will need to be put into service every month on average until 2050. Bioenergy The share of bioenergy in total final energy demand would have to increase by about 25% under the Fastest Innovation Case, driven mostly by industrial and transport-related applications. Fortunately, such an increase would not present a technical challenge on the demand side, as biofuels are dropin fuels for most applications. But such growth in demand would put additional stress on biomass supply chains. Rapid innovation in biofuel conversion technologies and agricultural practices is essential. Algae-based biofuels, for example, are currently only at the small prototype stage. Rapid development is required of advanced biofuels production technologies for biodiesel and bio-jet through gasification and Fischer-Tropsch, to boost aggregated production capacity by an average rate of 40% through to 2050. Carbon capture and storage Deployment of carbon capture and storage (CCS) will also have to be boosted by 50%, with the amount of CO2 stored almost 200 times greater than today, according to IEA estimates. Negative emissions technologies, such as direct air capture (DAC) and bioenergy CCS, would account for the bulk
scheme, we are now working closely with our topic experts and our internal team in formulating our carbon reduction plan moving forward.’ ‘The initial focus will be on i) setting up the required procedures to be able to capture data efficiently and ii) carrying out behaviour change and building control optimisation activities. A particular area of focus will be the reduction of carbon emissions through our flights by setting up carbon budgets for our relevant teams/ departments.’ ● More information on the EI’s journey to net zero can be found at https://www.pledgetonetzero.org/case-studies-energy-institute
ambitious innovation efforts to maintain cost and performance trajectories, with the cost of an average battery dropping 68% in the Sustainable Development Scenario, while gravimetric energy densities at cell level increase by 160% compared with current levels. From a current perspective, electric aircraft of the size and range needed for commercial passenger aviation are still not practical on a significant scale by 2070, mainly due to the high power density required during take-off. With current battery technology, an Airbus 380 would Opportunities at laboratory scale need batteries with an overall There are also opportunities weight 30 times greater than its for development of innovative current fuel intake, making lift-off technologies which are still at impossible. But early concepts the laboratory or small prototype stage today. The IEA maintains that for 10-seaters and electric taxis, including electrical vertical takefocus should be on technologies that are modular and small enough off and landing aircraft, have been developed by Rolls Royce, Uber to be mass produced and have potential for ‘high spill-overs’ from and a number of start-ups. An all-electric commercial passenger and to other net zero emissions aircraft capable of operating over technologies. 750–1,100 km would require Furthermore, technologies battery cells with densities of should be addressed that have 800 Wh/kg, more than three a high potential to unlock times the current performance of supply constraints, such as those lithium-ion batteries. impacting bioenergy and rare or Innovative battery recycling higher demand materials. Several could also be commercialised such technologies are considered over the next decade, reducing important, including advanced demand for primary lithium and battery chemistries and battery accelerating the electrification of recycling technologies; innovative the transport sector by lowering practices to boost biomass costs. resources; iron ore electrolysis for making steel; and advanced Indeed, accelerated innovation cooling. could reduce the gap between theoretical and current Decarbonising transport performance in many areas of Decarbonising transport relies technology on the road to net heavily on electromobility and zero. ● installed battery capacity for these applications increases 500-fold *Energy Technology Perspectives 2020: Special Report on Clean Energy Innovation; by 2070 in the IEA’s Sustainability IEA July 2020. Development Scenario. But in gridscale applications, the capacity of the battery fleet increases 260-fold from today over the same period. This level of deployment assumes of this. Both technologies would likely become critical in offsetting residual emissions from longdistance transport and heavy industry. Almost 16 DAC facilities of 1mn tonnes capture capacity would need to be commissioned every year on average to 2050, compared with about five such facilities in the current Sustainable Development Scenario. The largest DAC plant currently being designed is of 1mn tonne capacity, and only pilot-scale plants less than half that size have been demonstrated so far.
Petroleum Review | October 2020 15
Emissions mitigation
METHANE
R
eduction of methane emissions is expected to have the greatest immediate positive impact the oil and gas industry can have on climate change.1 New approaches and technologies are becoming available; however, preventing emissions as they arise requires not just detection but prediction. Methane detection and monitoring needs to be integrated into a corporation’s larger energy management and sustainability programmes, including operational workflows to model, predict, recommend and optimise emissions in near-real time. This can be done at the level of a single asset, an entire region, business unit, or indeed the whole enterprise. A business imperative Environmental sustainability, while remaining a corporate social responsibility (CSR) issue, has become a business imperative tied to a company’s licence to operate and, therefore, investor confidence in long-term viability. Environmental strategy choices, as a subset of a broader sustainability agenda, increasingly define a company’s prospects in today’s competitive marketplace. Many major oil and gas companies have announced plans and committed to a portfolio of initiatives to decrease their greenhouse gas (GHG) emissions intensity by 2050 or earlier. Uncertainty in carbon markets, as well as more stringent environmental regulations linked to financial risks, drive the need for new ways of monitoring, controlling and reporting emissions.
16 Petroleum Review | October 2020
Mitigating methane emissions Prediction, in addition to detection, is required to help cut greenhouse gas emissions and meet net zero targets, writes IBM’s Mark D Hall. Technology innovations such as artificial intelligence (AI), 5G, the Internet of Things (IoT), cloud, blockchain and others, will accelerate this progress and enable a transformation in how flaring, methane leaks, energy usage, and other types of GHG output can be reduced. This transformation follows a phased approach – manage, model, predict and assist, and optimise – each of which is explained in more detail below.
Figure 1: Holistic and incremental approach to optimise operations and reduce greenhouse gas emissions Source: IBM
Phase 1: Manage The manage phase is typically based on ISO 50001:2018, Energy Management Systems and related standards and is a strategic tool that helps organisations put in place an energy management system to use energy efficiently and effectively. The guidelines set out an energy management framework for establishing policies, processes, procedures and
specific energy tasks to meet a company’s energy objectives. They are also designed to help improve energy performance. ISO 50001 does not fix targets for improving energy performance. A business, regardless of its current level of energy performance, can implement the standard to establish a baseline and improve performance at its own pace. A comprehensive ISO 50001 programme requires an organisation to define its desired energy performance and work towards stated objectives through the effective measurement, monitoring, visualisation and reporting of energy and emissions targets across a wide variety of areas. These include functions such as production operations, fuel combustion, transportation, drilling operations, well services, water production and consumption, hazardous waste disposal, and grid usage. Traditional and emerging technologies such as fixed sensors on operating equipment, smart meters, sensors mounted on rigs, satellites and drones, are becoming available to detect and capture emissions and energy consumption with varying degrees of precision and scale. These technologies need to be integrated into a data management platform as part of a sustainability platform to receive raw data from disparate sources, provide real-time data cleansing and consolidation, act as a trusted source for historical data, and also provide the basis for data analytics and in later phases – modelling, predictions and optimisations.
Emissions mitigation
Phase 2: Model To deal with the vast amounts of available data and handle the complexity of different measurements and reporting requirements, the model phase provides additional capabilities – to infer composition and process properties and measurements (virtual metering), identify missing and out-of-spec/invalid measurements, include additional data sources such as weather conditions (eg wind direction, humidity, temperature, etc), energy costs, maintenance activities, and production schedules, future performance, events and upset conditions based on historical performance data or thermodynamic principles. IBM recommends a combined first principles and data analytics approach to ensure physical constraints can be met within the operational requirements (operating envelopes) while providing cognitive data insights through AI and machine learning techniques for process prediction, regression-based optimisation and scenario analysis. The latter may not be available in a traditional process model. Data and digital technologies – especially the ability to capture data in real time with an unprecedented degree of granularity – provide new levels of insight into changes in the physical environment. The model phase can make use of process data, production plans, operating protocols, technical operating envelopes, weather, economic and maintenance data to model and simulate emissions and energy intensities in near real-time, provide alerts when potential opportunities or events are identified, and provide actionable insights that are driven by advanced analytics. Examples of combined first principles and data analytics based prediction models include: •
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Correlation and clustering analysis to identify similar historical operational states with operating modes that prioritise high performing assets. Combinatorial optimisation to prioritise producers to meet demand with less energy. Predictive machine learning/ deep learning models to project deviation from optimal efficient point. Explanatory models to highlight operational factors resulting in predicted inefficiencies.
The model phase has the ability to scale from modelling individual equipment and assets up to operations at the regional or corporate level. Phase 3: Predict and assist The predict and assist phase identifies emission sources and energy intensities based on similar operating conditions and advises on actions based on past experiences and the output of the combined first principles and data analytics prediction models. Examples of prediction and actionable insights include: •
Higher utilisation of assets through ‘smart’ steam production modes resulting in reduced energy consumption.
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Recommendation on steam production modes to achieve minimal energy inputs while meeting production demand.
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Ability to flag predicted deviation from optimal efficiency point for rotating equipment and highlight operational factors causing predicted inefficiencies.
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External financial incentives (electric utility, third-party financing, tax benefits and others).
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Integrating energy management processes into business practices.
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Optimisation of energyconsuming assets.
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Improving operations and capital cost decisions.
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Reducing GHG emissions and other future environmental impacts of climate change, through the systematic management of energy.
This requires the need to capitalise on measured and inferred data, analytical and process models, and effective knowledge management to reveal new insights and underpin new solutions to existing problems.
Going digital In order to execute on the sustainability imperative, businesses need to be ‘digital’. They need to integrate analytics, AI and automation in intelligent workflows, to Recommended minimum flow rate to achieve required recovery deliver on sustainability goals. The combination of business rate. model transformation and a Recommendations on new environmental governance integrated site operation to structure can be applied to optimise heat recovery. environmental sustainability through a holistic, structured and Improved steam temperatures progressive approach as shown for maximum thermal in Figure 1, based on solving the efficiency. problem (quantifying the impact), Optimised heat recovery per breaking down silos, and scaling process/production asset. across the enterprise to:
Phase 4: Optimise The optimise phase leverages the capabilities defined in the previous phases to provide anomaly detection, recommend set-points to optimise throughput and can deliver automated responses. This advanced approach leverages advanced analytics capabilities to simultaneously optimise emissions, environmental performance and energy intensity in support of corporate sustainability programmes while ensuring production optimisation and meeting operational targets through: •
Improved cost savings.
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Energy efficiency and compliance.
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Co-ordinated energy programmes (energy efficiency, energy production, renewable/ alternative energy sources).
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Engage in industry-led initiatives and policy actions supported by financial investment.
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Reduce GHG and related emissions.
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Optimise the energy mix and allocation.
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Identify production optimisation opportunities while reducing energy consumption.
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Optimise production process settings based on energy intensity.
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Deliver on corporate sustainability targets and goals.
Methane emissions from oil and gas, IEA, 2020.
1
For additional IBM recommendations on sustainability, ‘The rise of the sustainable enterprise: Using digital tech to respond to the environmental imperative’ can be downloaded from https://ibm.co/sustainableenterprise Petroleum Review | October 2020 17
Emissions mitigation
METHANE
Tackling methane emissions reduction M ethane is a potent greenhouse gas (GHG) which accounts for a quarter of today’s global warming, and also plays an important role in natural gas in the transition to a low carbon future. The oil and gas industry is a leading source, releasing over 75mn t/y of methane emissions. In response to priority areas highlighted for action in the International Energy Agency (IEA)’s World Energy Outlook 2017, a coalition of industry players, international institutions, nongovernmental organisations and academics developed the Methane Guiding Principles (MGP). Signatories including BP, Statoil (now Equinor), Shell, Eni, Total, Repsol and ExxonMobil, as well as supporting organisations like the IEA and Energy Institute (EI), committed to undertake the principles and implement a well-defined action plan to increase focus on cutting methane emissions. So what progress is being made? ‘Methane emissions are an enormous problem for the oil and gas value chain and every business who has a stake in its future,’ says Ben Ratner, Senior Director at the Environmental Defense Fund (EDF). Methane is a super-potent GHG – 86 times more powerful than CO2 at warming the planet over a 10–20-year period. And the oil and gas industry is one of the largest global emitters. ‘We are in a race against time and every day or year matters,’ he continues. ‘Despite promising steps by some MGP signatories, the oil and gas industry overall is not doing nearly enough to limit methane emissions.’ However, there are a number of courses of action with straightforward solutions. ‘Routine flaring of natural gas must be stopped. Flaring is an incredibly wasteful practice that destroys shareholder value, wastes a natural resource and is a significant contributor to methane and CO2 emissions,’ notes Ratner. Another key action is broad implementation of methane mitigation technologies and 18 Petroleum Review | October 2020
Continuous reduction of methane emissions from the oil and gas industry is essential to address global climate change. Leading authorities explain key measures that are underway to identify, monitor and mitigate leaks worldwide. Brian Davis reports. practices like leak detection and repair. Ratner emphasises the need to optimise operations in the field, to better monitor and control pressure and keep emissions in the pipe and out of the atmosphere. However, he is concerned that even companies who are taking some leading steps are generally giving themselves a ‘free pass’ for emissions from their non-operated joint ventures. Companies that are serious about methane management need to bring real field data to the table, to demonstrate to investors, the public, customers and others that they are really reducing methane emissions. Ratner claims many companies rely on desktop estimates which ‘grossly underestimate’ methane emissions rather than field estimates. ‘The killer app for measuring methane emissions is not a calculator but a sensor. As we move to a world of satellite monitoring, there will be increasing transparency about where methane emissions are
Engineer monitoring methane emissions at Shell’s Appalachia gas operations, US Photo: Shell
coming from,’ he says. EDF affiliate MethaneSAT is being developed in partnership with Harvard University and the Smithsonian Astrophysical Observatory, as a compact new satellite resource to pinpoint the location and magnitude of methane emissions globally, for launch in 2022. The high-profile Oil and Gas Climate Initiative (OGCI) has committed to a methane intensity target of 0.20 by 2025. However, Ratner considers the OGCI’s methane mitigation efforts must demonstrate progress towards that target with science-based measurement rather than desktop estimates. Nevertheless, the EDF recognises the early leadership of companies like BP, who have committed to take on methane emissions in their own operations and non-operated joint ventures. Shell has also taken a leadership role in the Methane Guiding Principles (see Box) and has been outspoken in calling on the US government and the European Union to tackle methane emissions. Notably, Gretchen Watkins, Shell Oil President in the US, stood up against the Trump Administration’s roll-back of an Environmental Protection Agency (EPA) rule in mid-August, designed to reduce methane emissions from oilfield operations. ‘The negative impacts of leaks and fugitive emissions have been widely acknowledged for years, so it’s frustrating and disappointing to see the administration go in a different direction,’ she said. Shell is committed to continue reducing methane emissions. However, the oil industry remains split and many smaller companies say the requirements are too expensive for them. Maarten Wetselaar, Director Integrated Gas and New Energies for Shell, has also made the case publicly for the European Commission to develop strict performance and procurement standards on methane emissions for all gas sold in the Europe Union. Ratner doesn’t pull his punches either. ‘Donald Trump may be the most reckless anti-environmental president in the history of the US,’ he says. ‘It is a tremendous error for the future of natural gas, to wipe away the only remaining nationwide rule limiting methane emissions from industry.’ And EDF President Fred Krupp recently announced plans to sue the Trump administration over the roll-back of methane standards.
Emissions mitigation
The Energy Institute and methane emissions
Nevertheless, there has been a mixed reaction from the oil and gas industry to the Trump EPA roll-back. Several companies have had the courage to oppose move, including BP, Shell, Pioneer, Equinor and some electric and gas utilities. But they are not ubiquitous. ‘Many companies have remained silent,’ comments Ratner. ‘Gone are the days when qualitative statements alone got the job done. Companies need to deliver proof of action in a more transparent way on the specific progress they are making, conducting inspections, improving operations, incentivising workers and contractors to do a better job which will ultimately reduce methane emissions.’ Government has a pivotal role to play ‘The scale of methane emissions has to be put in the context of the larger problem of CO2 emissions,’ says KC Michaels, Legal Advisor at the IEA. ‘From our Sustainable Development Scenario, which is part of the IEA’s annual World Energy Outlook, we see methane abatement from oil and gas as a critical step alongside larger action across different field emission sources.’ The IEA estimates that the oil and gas industry needs to reduce its emissions over 60% by 2030, which is technically possible to achieve and amounts to about 80mn t/y methane. ‘This will require a smorgasbord approach, with
different opportunities across the sector tailored to specific sites. Some approaches are cheaper than others, such as replacing pneumatic pumps with electric motors; electrifying sites; and improving leak detection and repair programmes’, he says. Michaels stresses the need for governments to take action in the regulatory space in line with the Methane Guiding Principles. ‘So far, 23 oil company signatories have joined the MGP and committed to advocating for sound methane regulation. But we really need to get a solution across all sites, all countries and all operators.’ Part of the challenge is the numerous sources of methane emissions, in different locations, with different types of gas, and the most cost-effective solutions. There are also potential regulatory options that can drive different types of abatement. The Global Methane Alliance, which started in 2019, is a UN environment programme which brings together governments, financing institutions, international organisations (including the IEA) and nongovernmental organisations, and industry to support ambitious methane reduction targets for the oil and gas industry. Countries that join the Alliance will commit to include methane reduction targets for the oil and gas sector in their Nationally Determined Contributions (NDCs) in the next COP26 round, as part of their GHG
Methane is a potent greenhouse gas and the EI is playing an active role in the reduction of emissions as part of its wider work to support safe, efficient and environmentallysound operations in the energy industry. When the EI surveyed international oil and gas professionals in 2018 it found awareness of the issue to be surprisingly low. Four in five of those asked were not fully aware of the technically and commercially viable possibilities for reducing methane emissions through the oil and gas lifecycle. Methane emissions mitigation is now a permanent feature of EI work, in collaboration with others across the industry. EI President Steve Holliday FREng FEI told oil and gas executives gathered at IP Week in February 2020: ‘It is hard to think of a more obvious place for this sector to start [acting on climate change] than fugitive methane emissions in its production and transportation facilities. I’m pleased to say a large body of operators and supporting organisations like the EI are working hard to overcome the technical issues and to raise awareness. The industry must bear down on this most potent of greenhouse gas emissions.’ As a Supporting Organisation of the Methane Guiding Principles initiative, the EI technical team is part of crossindustry work to develop reducing methane emissions best practices across both the upstream and downstream industry, including work to improve real-time monitoring of emissions and to take advantage of developing technological capabilities. The EI is also using its channels and influence to raise awareness within the professional community. Methane emissions mitigation is high on the agenda of the EI conference programme, with dedicated sessions at IP Week. Methane is regularly featured within the EI knowledge output, including its authoritative podcast ‘Energy in Conversation’ and both magazines, Petroleum Review and Energy World. And the EI training team will soon be hosting Methane Masterclass training developed by Imperial College. ● reduction targets. The reduction target is at least 45% reduction in methane emissions by 2025 and 60–75% by 2030. For COP26 each country is expected to submit an NDC that will include climate goals for the next five years. In the past Paris Agreement, targets were largely focused on reduction of CO2 emissions. But the current efforts of the UN Environment Programme, the IEA and MGP members is to get countries to include methane intensity under their reduction plan. So, has the Global Methane Alliance been sabotaged by President Trump’s roll-back of EPA rules on methane emissions? Michaels is diplomatic and insists there is still a role for governments across the world to take action on methane emissions reduction. ‘Every country and operator has to do its part. But really the effort is focused on the low hanging fruit, where the best opportunities are.
Methane is a super-potent GHG – 86 times more powerful than CO2 at warming the planet over a 10–20-year period Photo: Shutterstock
Petroleum Review | October 2020 19
Emissions mitigation
Methane emissions reduction in action Shell has set a target to maintain methane emissions intensity below 0.2% by 2025, covering all oil and gas assets for which Shell is operator. Maarten Wetselaar, Director of Integrated Gas and New Energies, Shell, emphasises: ‘The long-term role of gas in the global energy mix depends on good measurement, transparency on and management of methane missions. Urgent and ambitious industry action is needed to stamp out emissions to near-zero.’ The company has embarked on a comprehensive course of action. It has introduced a range of new technologies and methods to help find and stop methane emissions in its operations. At Shell’s gas-to-liquids facility in Qatar, 33,000 components were scanned, 48 leaks detected and the majority repaired immediately. At its LNG facility in Oman, unintended methane emissions are now more than 99% lower than previously estimated due to improved reporting. In 2019, Shell Canada’s Groundbirch natural gas project reduced 330 tonnes of CO2e by replacing old valves with electric valves. A new well design with zero emissions was introduced at 25 wells at
What’s going on in one country doesn’t necessarily need to roadblock others taking action.’ Michaels highlights the MGP initiatives. Resources under development include a best practices toolkit and education programme, principles for sound and effective methane policy and regulation, and a web-based information portal developed by the IEA.
the project. Meanwhile, improvements in maintenance procedures on 2,600 wells at a Shell-operated QGC site in Australia, reduced methane emissions by about 4,000 tonnes from July to December 2019. Shell’s Appalachia gas operations replaced four gas-assisted pumps with electric versions in 2019, reducing methane emissions by 625 tonnes. Shell also encourages industry-wide action on methane emissions reduction by participating in a number of initiatives, including the MGP coalition. It is a member of the OGCI, which has set a methane intensity target of 0.25% by 2025. Shell is also a member of the Climate and Clean Air Coalition (CCAC)’s Gas Methane Partnership (OGMP), whose principles provide a reporting framework that supports transparency on action and results. In 2018, Shell announced a target to keep its methane emissions intensity, for oil and gas facilities where Shell is the operator, below 0.20% by 2025. Since 2019, Shell’s senior executive pay is now linked with progress against its net carbon footprint ambition. ●
The 2020 IEA Methane Tracker incorporates a comprehensive set of estimates of national level emissions and abatement opportunities within each country. ‘Essentially, the problem for most countries is the lack of measurement of methane emissions,’ admits Michaels. ‘We are hoping that a large number of countries will take the call of the Global Methane Alliance seriously,
to increase their ambition on methane emissions reduction in the next reporting period. Methane is an important source of global warming that needs to be considered alongside CO2, and is potentially one of the most cost effective because methane is the main component of natural gas and has clear monetisation.’ ●
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Emissions mitigation
OIL SANDS
Oil sands operators are sharing intellectual property, technology and best practices in order to improve environmental performance, including a reduction in greenhouse gas emissions. Berta Gomez, Senior Communications Advisor, Canada’s Oil Sands Innovation Alliance (COSIA), reports.
Moving towards a cleaner future C anada’s oil sands account for the third-largest oil reserves in the world and have a role to play in powering the future, combating climate change and contributing to economic recovery from COVID-19. Innovation is key to achieving a sustainable energy future. According to a recent report from BMO Capital Markets1, the oil sands sector has invested more than $9.3bn in innovation and environmental improvement since 2009, which is significantly higher than global majors’ average spend on a per-barrel basis.
Satellite technology is being tested by the oil sands industry to measure fugitive emissions Photo: GHGSat
Industry collaboration The launch of Canada’s Oil Sands Innovation Alliance (COSIA) in 2012 marked the starting point of an unprecedented level of collaboration among oil sands operators to accelerate oil sands environmental innovation. ‘COSIA was created following the principle that oil sands producers could go further and faster together through collaboration,’ says Wes Jickling, Chief Executive. ‘Sharing intellectual property, technology and best practices has resulted in significant improvement in the environmental performance of the sector.’
22 Petroleum Review | October 2020
COSIA has become a global innovation hub which brings together leading minds from Canada and around the world – industry, government, scientists, academia and service providers – to create the breakthroughs needed to significantly decrease greenhouse gas (GHG) emissions, reduce water usage and reclaim land faster. Its nine member companies represent more than 90% of oil sands production. Between 2012 and 2018, they invested $1.4bn to develop over 1,000 distinct innovations, technologies and scientific know-how. This has driven significant environmental performance improvements, including, for example, the reduction of freshwater use intensity at in-situ operations by 42% and at mining operations by 18%. Game-changing technologies COSIA and industry recognise the complexity of global climate change, a challenge that is bigger than just one industry or one country. Addressing climate change requires action from individuals, governments, organisations and industries
around the world. Within this context, the oil sands industry believes that technology will be the driver to continuously decrease GHG emissions in the sector. While production from Canada’s oil sands accounts for just 0.15% of global emissions (according to NRCan Energy Fact Book 2019–2020 and Environment and Climate Change Canada, 2019), producers have been steadily reducing their GHG intensity per barrel of bitumen produced over the years and continue to do so through implementing energy efficient technologies throughout oil sands operations; installing new energy sources for low carbon heat and power; researching, investing in and deploying new technologies for carbon capture, utilisation and storage (CCUS); and developing innovative oil sands extraction technologies. As recently reported by BMO, the GHG intensity of the sector has declined approximately 24% since 2012 and advanced technology deployment on the horizon could see further improvements of another 30% or more by the year 2040. ‘A global transition to a lower carbon future is ongoing, and industry is aiming to be part of that future,’ says Matt McCulloch, COSIA’s GHG Director. ‘COSIA and oil sands producers are advancing a range of potentially game-changing clean technology innovations. As a suite, these have great potential to change the
Emissions mitigation
Innovation opportunities COSIA is always on the lookout for new technologies that are related to the environmental needs of the oil sands industry. Priority opportunities are listed on COSIA’s website in relation to each of its areas of focus – GHGs, land, tailings and water. Specifically, within the GHG area, COSIA has helped develop numerous innovation opportunities, including natural gas decarbonisation, post-combustion capture of CO2 and optimal CO2 transportation system design. ● More detailed information can be found at cosia.ca/innovationopportunities/greenhouse-gases
emissions trajectory of the sector.’ Some of the breakthrough technologies that have potential to help achieve ambitious emissions targets – and even net zero – are profiled below.
CERT Team, from the University of Toronto, is testing a technology to convert CO2 emissions into fuels and chemical feedstocks Photo: XPRIZE
CCUS projects Quest, a carbon capture and storage (CCS) facility near Edmonton, Alberta, recently achieved a historic milestone. Since its start-up in 2015, it has captured and safely stored 5mn tonnes of CO2 underground (equivalent to taking 1.25mn cars off the road for one year) and at a lower cost than anticipated. The project has enabled industry to advance and share knowledge about CCS, a technology that can be applied to a wide range of industries, including steel, cement and power generation. The Quest facility has stored the most CO2 of any onshore CCS facility globally with dedicated geological storage. Within the CCUS path, the NRG COSIA Carbon XPRIZE initiative is advancing technology development to create products
from CO2 emissions. A $20mn, cross-industry, international effort, the competition is in its final year. A total of 10 finalist teams from Canada, the US, UK, China and India will demonstrate that their advanced technologies can convert CO2 emissions from coal and natural gas combustion into valuable products, including a greener concrete, carbon nanofibre that could eventually replace steel and concrete, graphitic nanoparticles that could strengthen materials such as plastics, and even ethanol that is being used to make vodka. Solvents breakthrough The oil sands industry is advancing the use of solvents as a potential breakthrough for reducing carbon emissions associated with oil sands extraction. The use of solvents (naturally occurring lighter hydrocarbons) reduces, and may potentially eliminate, the need for energy-intensive steam production during in-situ bitumen extraction. Companies are working on pilots to evolve steam-based processes into solvent co-injection with steam, and over time towards pure solvent, non-aqueous extraction processes. Solvent enhanced recovery is viewed as one of the most promising technologies to achieve long-term reduction targets within the sector. This view is shared by independent industry experts, with a 2020 report by BMO Capital Markets projecting a 50–90% reduction of GHG emissions and water handling through the use of solvent technologies. Satellite technology With Montreal-based GHGSat, COSIA is advancing the use of
satellite technology to obtain more accurate and reliable measurements of local fugitive GHG emissions. The satellite data could help producers more reliably monitor when and where GHG emissions are occurring, whether at active mine faces, tailings ponds or other operating locations. This is just one of a suite of technologies for measuring emissions that allow more effective development of emissions reduction strategies, and is another example of technology developed for the oil sands with potential for application in industries across the world. Molten carbonate fuel cells As part of the industry’s efforts to reduce GHG emissions, COSIA members are also exploring the on-site application of molten carbonate fuel cells (MCFCs), a technology that captures and concentrates CO2 from exhaust gas at natural gas-fired processing facilities while generating low GHG-intensive electricity. This innovative combination of MCFCs and once-through steam generators (OTSGs) will cogenerate steam and electricity and enable CO2 capture at oil sands in-situ facilities. The electricity generated by this technology could be used onsite and exported to the Alberta power grid, further reducing the emissions footprint for all electricity consumers in the state. In addition, water that is produced from reactions within the fuel cell can be conserved and re-used at oil sands facilities, displacing other water sources. Future role Acknowledging the uncertainty of oil demand in the short term due to COVID-19, most scenarios on global energy consumption forecast an increase of use of fossil fuels in the next two decades. COSIA and its members believe that the oil sands sector is positioned to respond to a growing global energy demand while addressing climate-related risks. According to Jickling: ‘Oil will still be part of the global energy mix for decades to come. However, it is crucial to develop these resources in an environmentally sustainable way, supported and fuelled by accelerated and focused technology implementation.’ ● The 400 billion barrel opportunity for friendly oil and Canada’s evolving role, BMO, March 2020.
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Petroleum Review | October 2020 23
Business management
POST-PANDEMIC
Avoid falling off the edge T
Traditional oil and gas companies can only succeed in the decarbonising energy ecosystem of the future through substantial portfolio realignment, write Stephen Rogers, Rodolfo Guzmán and Daniel Monzón, Energy & Utilities Practice, Arthur D Little.
he global lockdown triggered by COVID-19 pushed a transforming industry into a state of major crisis. Progressive weakening of global oil demand during early 2020 was exacerbated by growing structural oversupply caused by a struggle for market share between Russia and OPEC. These two factors together sent oil prices to a 20-year low. Although OPEC, Russia and other producers later agreed on some production cuts, these price-support efforts have had a relatively modest impact.
The coronavirus pandemic has created a perfect storm for the global petroleum industry, combining oversupply with a dramatic fall in demand – all at a time when ongoing requirements to decarbonise economies are gathering pace
Structural transformation With the oil and gas industry currently locked into a cycle of oversupply, low prices and volatility, the economic downturn created by the COVID-19 crisis is likely to deal a major blow to many companies. Investors have found the sector increasingly unattractive over the past 10 years. Any further, prolonged period of low oil prices is likely to see them divert their capital elsewhere as the traditional oil and gas business model becomes even riskier and less commercially attractive. Although the global economy will eventually recover, it is unlikely that it will return soon (if at all) to its pre-COVID-19 ‘business as usual’ state. Instead, the oil and gas industry is likely to be faced with prolonged substantially reduced demand, thanks to lower economic activity and growing pressures to use greener energy sources. Similarly, the sector must also grapple with oversupply issues, whether due to burgeoning oil volumes from US shale, or the struggle for market share between OPEC and Russia. Figure 1 outlines four potential scenarios based on these factors. A ‘Back to Normal’ scenario depends on an early, ‘V-shaped’ bounce-back of the global economy, combined with failure to progress the climate-change/renewables
24 Petroleum Review | October 2020
agenda. At the same time, it requires major oil producers to agree production cuts that are sufficiently rapid and deep that current oversupply is reduced. Achieving these conditions seems unlikely. The ‘Stagnation’ scenario, in which the global economic rebound and oil-demand impact is ‘L-shaped’, seems much more probable. In this case weak demand recovery is held back by continued adoption of renewables and low carbon energy forms. Nevertheless, in this scenario producers are gradually able to reduce oversupply to support modest prices that ensure the viability of many new projects. The worst potential scenario is undoubtedly ‘Severe Injury’. In this case, a slow, ‘L-shaped’ economic recovery, perhaps blended with accelerating demand destruction driven by the renewables transition, combines with persistent oversupply, due to major producers’ repeated failures to agree to sufficiently deep production cuts. On the positive side, any lasting demand drop would provide OPEC and other major producers with strong political and financial motivation to adjust supply to an adequate price level. This makes this scenario less likely than Stagnation. Accordingly, the level of injury inflicted on both individual players and the wider industry will largely depend on whether OPEC (and/or Russia) can commit to supporting prices in this way, perhaps at the expense of market share. Given these factors, another likely outcome is the ‘New Normal’ scenario. In this case, if the economy bounces back after a few months (with a ‘U-shaped’ recovery), coupled with relatively slow demand erosion due to tightening of climatechange policies, oil prices should strengthen. This will be the case even if OPEC and other producers fail to curb supply as much as in the past.
Varying impacts A closer examination of sub-sectors within the oil and gas industry reveals the degree to which each will be affected (see Figure 2): •
International oil companies (IOCs) will find it increasingly difficult to grow organically, with certain high-cost and stranded assets being written off. However, there will be more merger and acquisition (M&A) opportunities as smaller players struggle to compete.
•
National oil companies (NOCs) with large, low-cost reserve positions will push to accelerate production, but those with higher cost structures will struggle. Due to reduced oil and gas revenue, lower national budgets will intensify debate about prioritisation between oil reinvestment and social needs. Some governments may use the crisis to spur support for energy transition programmes.
•
Refiners will face low margins and returns for many years due to structural overcapacity, heterogenous demand evolution and stricter product-quality standards. Accordingly, some small-scale plants will not even be able to recover their operating and maintenance cash costs.
•
Oilfield services players face very low asset utilisation because of project cancellations or deferrals and production shutdowns. Severe capacity cutbacks and massive employee layoffs are likely to continue in this segment.
Emerging business models Under almost any scenario, the postCOVID-19 world will see the oil and gas industry accelerate its transition towards cleaner energy sources, products and service offerings, and
Business management
Figure 1: Petroleum industry scenarios – impact on economy versus oil oversupply
away from its traditional business models. The pandemic has created a perfect storm that, along with an ongoing need to reduce CO2 emissions, will transform the industry. The future survival and success of many players depends not only on their achieving greater focus on renewable energy, but also upon an ability to deliver still-lowercost solutions. We expect the following seven hydrocarbon business models to co-exist in the future, with a player’s chance of success depending largely on its ability to transform after the crisis. Diversified energy holdings: IOCs will respond to the twin challenges of low prices and decarbonisation by moving rapidly away from their increasingly unattractive traditional business models, becoming energy-holding companies with more diverse interests. They already foresee that oil demand will peak, and after COVID-19 they
Figure 2: Impact by player under each scenario
Source: A D Little
will increasingly grow organically beyond hydrocarbons. They will transform their global oil and gas operations into truly diversified energy holdings that are robust in a world that is evolving towards cleaner energy sources. IOCs will also look to strengthen their natural-gas value chains and integration into petrochemicals. XL oil companies: Low-cost production and a large reserve base will underpin the predominance of the XL model, which is already being adopted by some IOCs and the large national oil companies. This model prioritises scale in monetising existing, ultra-low-cost oil and gas resources. The largest and most competitive NOCs may therefore emerge as major winners from this crisis. Regional ‘mini-majors’: Most regional players will leverage their geopolitical, cultural, logistical and commercial advantages to transform their businesses into
Source: A D Little
regionally tailored, integrated and diversified models. They may become diversified ‘mini-IOCs’, or perhaps be more strongly oil and gas focused. Special-purpose vehicles (SPVs): Oil and gas companies will increasingly create SPVs to provide greater financial flexibility within their portfolio-restructuring strategies. US drillers: These companies have been most damaged by the COVID-19 oversupply crisis. They need to manage their portfolios in a highly dynamic way, maintaining cashflow while trying to keep opportunities alive for immediate rebound in the event of price recovery. They face shrinkage and a significant challenge for mediumterm survival. Global oilfield service companies: This business sector underwent major efficiency gains in 2015, leaving little room for further improvement. Their business models will be extremely challenged by much lower levels of drilling activity. If they are to maintain growth, they need to pivot into energy transition support through rapid innovation and development of new solutions for energy producers and consumers. Retailers: Fossil-fuel demand will take time to recover even if gross retail margins are not impacted in the long term. This segment will need to prioritise investment in non-fossil energy and other related customer-service areas to ensure viable returns. Although there isn’t one single business model that will enable future success, the journey Petroleum Review | October 2020 25
Business management
towards the ‘energy company of the future’ requires companies to adopt transformation strategies now that will prepare them for an uncertain and changing world. They need to think carefully about their long-term survival paths, identify growth options, and take deliberate, meaningful and strategic actions to protect themselves against what is now the very real risk of early obsolescence. Companies need to improve capital returns in their traditional business segments, while exploring options for future growth into renewables through a combination of acquisitions and new-venture pilots. They also need to undergo deep transformation of their cultures, skills and capabilities if they are to survive and create long-term, sustainable competitive positions. The challenges are huge, and not all of today’s oil companies are likely to succeed. Insight for the executive All sectors of the industry are affected by the COVID-19 crisis, with some companies at risk of bankruptcy and many more unlikely to survive in their current forms if oil prices and margins remain at depressed levels. Companies dominated by high-cost
assets, led by weak management teams, or carrying high debt burdens will face increasingly severe challenges, with many such companies disappearing or being acquired. Most oil companies have already reduced their planned shortterm capital spend, but need to also undergo strategic rebalancing of their portfolios to give them the best-possible chance of weathering the COVID-19 storm and emerging fitter and more secure in the long term. In this transformation, they should not only divest high-cost upstream developments, including shale or tar sands, concentrating instead on low-cost assets, but also curtail high-risk exploration. They should cancel or carefully review new construction of refining projects or plant upgrades, considering the very limited time window to secure returns from such investments. They will need to rebalance their businesses through stronger positions in the natural-gas value chain and petrochemicals, while delivering more robust emissions-efficiency initiatives. All oil and gas companies should also now develop expansion opportunities in the energy transition, electricity and renewables space, pushing harder
in this direction and investing further into decarbonisation and renewables as such projects become more sustainable and attractive. These changes certainly apply to international and regional oil companies, as well as to US drillers, but global oilfield service companies will need to make the most urgent and profound responses to the COVID-19 pandemic. As they are the most severely impacted by the drop in global oil-sector activity, they will need to rapidly pivot towards renewables-sector support, as many have already done. All players will also need to accelerate their automation and digitalisation initiatives to gain new levels of operational efficiency. Such transformations are the only way to ensure the long-term viability of the petroleum sector. Participants need to completely rethink their roles in the future industry ecosystem as traditional business models become progressively untenable. ●
Asset Management 10 – 11 March 2021, online
This timely conference will explore the latest industry thinking, best practice, research, lessons learnt and innovation (e.g. application of internet of things, robotics and analytics) with relevance to asset management of oil and gas assets.
Abstract deadline: 30 October 2020
energy-inst.org/asset-management Asset 2020 - Aug.indd 1
10/09/2020 15:25:16
Decommissioning
OIL AND GAS
Decommissioning deferral doldrums
Forecasting decommissioning activity has been notoriously difficult. COVID-19 and the resulting oil price crash has not helped, and a fall in activity is also generating concerns around the health of the supply chain that will one day be required to do the work, writes Elaine Maslin.
D
Allseas’ Pioneering Spirit heavy lift vessel removing Shell’s Brent Alpha topsides earlier this year Photo: Allseas
ecommissioning is a necessary task – the fallout from the growth in use of fossil fuels throughout the 20th century. Globally, northwest Europe and the US Gulf of Mexico are the most mature hydrocarbon basins, where most decommissioning has taken place to date, with more to come. Some 73% of fields in north-west Europe and 87% in the US Gulf of Mexico have produced more than 75% of their reserves, according to market analyst Rystad Energy, which predicts $28bn spend on decommissioning between 2020–2024 alone. Of that, some 42% ($14bn) will be spent in the UK, 20% in the Gulf of Mexico and 11% in south-east Asia. Fine-tuning when that spending will come is a challenge. Spending in the UK was 11% (£170mn) less than expected in 2019, according to the Oil and Gas Authority (OGA), partly due to deferrals but
also increased efficiencies. This year, industry body Oil & Gas UK (OGUK) is expecting a 27% drop (£386mn), followed by an 8% fall (£109mn) in 2021 before a rise of 12% (£139mn) in 2022, based on a survey of UK operators. The biggest hit segment is expected to be well plugging and abandonment (P&A) – the largest overall segment (45%) in terms of cost within decommissioning – forecast to fall by 35% this year in the UK, 23% in 2021 and 13% in 2022. P&A work on the Schooner and Ketch fields operated by DNO was due to start under contractor Well-Safe early this year but was postponed due to COVID-19. P&A work by rig firm Valaris at Eni’s Dotty, Dawn and Hewett fields has also been postponed. Platform removals are also expected to fall by 25% this year on the UKCS but are expected to remain flat next year and then increase by 125% in 2022. Subsea
decommissioning will also take a big hit in 2020, down 65%, but increase by 31% in 2021, then by 125% in 2022, according to OGUK’s research. ‘The overwhelming theme is that we are seeing a reduction in the short term and that’s expected, with the implications of operating in a COVID environment, with offshore social distancing measures, all these are things operators have to consider and will impact decommissioning,’ says Joe Leask, Decommissioning Manager, OGUK. A challenging basin The North Sea is a challenging basin. Ownership is fragmented and costs are high; 17% of 214 mature assets (that have produced >75% of reserves) have opex above $30/b, according to Rystad’s Sara Sottilotta. The oil price barely breached $30/b through midMarch to mid-May this year, resulting in some facilities being shut-in permanently – for example, Premier Oil’s Balmoral floating production facility, which had knock-on effects for other fields. Elsewhere, age and structural issues have resulted in an early demise for fields – the Alma/ Galia project, for example, which Petroleum Review | October 2020 27
Decommissioning
shut early due to pump problems, and the Thistle/Heather/Deveron fields which were shut-in due to structural concerns. Some of the reduction in spending could also be due to increasing efficiencies. In 2017– 2019, according to the OGA’s UKCS Decommissioning Cost Estimate 2020 report (based on pre-COVID data), the total estimated cost for decommissioning the entire UK North Sea fell 19%, from £59.7bn to £48bn, based on a like-for-like basis (ie decommissioning the same assets that were there in 2017 in 2019), thanks to efficiencies made. But it is still quite a way off the 35% cost reduction by 2022 target set in 2017. What’s more, 2019 – pre-COVID – saw just a 2% (£1bn) cost estimate reduction (compared with 7% in 2017 and 10% in 2019), a figure Pauline Innes, OGA’s Head of Decommissioning, says ‘raises some questions for all of us’. Furthermore, based on an updated inventory at 2019 prices, the fullbasin estimate remains £51bn. Looking at the positives, there was cost reduction in platform and subsea infrastructure removal, at £700mn and £500mn respectively. This year, for the first time in the history of the basin, two northern North Sea platforms will be lifted out – Brent Alpha, which was removed to Able UK’s yard in Hartlepool, and Ninian North, which has been removed by Allseas’ Pioneering Spirit to Veolia-Peterson’s Dales Voe on Shetland. ‘North West Hutton took 100 days to remove, now we’re doing two in one year,’ comments Leask. ‘Technology (heavy lift vessels) is helping us.’ But the OGA’s cost estimates were pushed up by post-COP (cessation of production) running costs and P&A activity, increasing by £400mn and £100mn respectively. While there has been cost reduction through learning and lower rates (semisubmersible rates were <$130,00/d in 2017–2018, rising towards $200,000/d in 2019, according to IHS Markit), there are still significant inconsistences in spending between operators. The industry had managed to reduce post-COP running costs from £166mn to <£50mn, highlights OGA Decommissioning Manager Ian Fozdar. ‘It’s something we know how to do’, he says. However, he also reports some operators are going well over that level. To tackle these inconsistencies, the OGA has created dashboards so operators can compare their performance with peers. But bigger changes are needed. 28 Petroleum Review | October 2020
‘There is a real threat that if operational activity does not increase in the UKCS during the remainder of 2020 and particularly in 2021 that the number of redundancies we have already witnessed within the industry will continue to grow.’ Phil Milton, CEO, Well-Safe Solutions
‘If they are still not up to it, they should hand the work over to companies who can,’ says Fozdar. Innes also says there must be commercial transformation in the way decommissioning is delivered. ‘New models and offerings have been brought into the market, but there has been little traction,’ she told an OGUK event launching the cost estimate report. One idea is scope aggregation. Aggregating work and allowing contractors flexibility to tackle it would go some way to bridge the gap between the supply chain needing work and operator needs for cost certainty, EY’s Jon Clark, EMEIA Leader Oil & Gas Transaction Advisory Services, told the Decom North Sea and OGUK Offshore Decommissioning Conference last November. But the fragmented nature of the North Sea makes that difficult. To aggregate work, data has to be available to structure the value proposition, according to Innes. Done right, you could have a rig targeting P&A in a certain ‘postcode’, suggests Neil MacCulloch, Spirit Energy’s Executive Vice President Technical & Operated Assets. Yet, it has proven challenging to do in reality, with issues around terms and conditions and agreeing how to work and manage campaigns, adds Leask. The key is commercial models, according to Alex MacDonald, Petrofac’s Managing Director for Well Engineering. ‘Without having a commercial model where rewards are aligned to project outcomes, it’s genuinely difficult to get fully onboard collaboration.’ Instead, some seek savings from margin erosion, which the supply chain has been under ‘enormous pressure’ to achieve. Phil Milton, CEO at Well-Safe Solutions, says some progress has been made to align operator and contractor goals – but much more could be done, including having a continuous campaign approach. And it needs to be done soon or capability within industry will be lost, through redundancies but also loss of equipment and assets to other regions or retirement. Their replacements could end up being new higher cost units, resulting in cost inflation. MacDonald believes the biggest threat to achieving the 35% reduction in decommissioning costs is supply chain capacity destruction due to work being deferred. ‘The danger is that, if not a lot of money is being spent this year, you might see skills and infrastructure no longer available
in 2–3 years’ time and that might mean a more competitive market and higher costs. Losing skills is also a risk.’ The OGA is working with various operators, the supply chain and banks to explore commercial frameworks that could allow for regular amounts of work to come to the market. Innes also says operators should think hard about deferring projects, amidst concerns that a reduction in decommissioning work over the next couple of years could have a ‘significant and long-term detrimental impact on the supply chain’ that will have a knockon impact on the UK’s ability to reduce decommissioning costs. Energy transition The energy transition is another part of the decommissioning equation. Could infrastructure be reused towards net zero goals, such as for carbon capture and storage (CCS) or hydrogen production? What is important is that these options are looked at some five to six years ahead of COP, says Innes. There are 400+ platforms in the North Sea, but only a relatively small number could be suitable for other uses. With £50mn postCOP running costs, options can be limited. The biggest opportunity could be re-use of trunk lines for hydrogen (see Petroleum Review’s forthcoming November 2020 issue) or CCS. But even then, new business models will be needed to make that work. What has been lacking is a bigger picture, suggests Fozdar. ‘Is CO2 needing to be transported, is hydrogen needing to be generated?’ he asks. Still, efforts to gear up and develop new solutions continues. Earlier this year, the Scottish government announced £1.84mn in funding to 10 projects via its Decommissioning Challenge Fund. Projects range from new P&A technologies to yard upgrades and cost estimate tools. Meanwhile, the Energy Institute is leading a project to investigate the risks of structural failure of assets during decommissioning, through funding from Engineering X, a collaboration between the Royal Academy of Engineering and Lloyd’s Register Foundation. Other projects such as Insite North Sea are looking at the broader impact on the environment of man-made structures and what would happen if they are removed. Decommissioning is a complex and changing picture. It is thus unsurprising that it is notoriously difficult to predict. ●
Decommissioning
WIND
A new challenge for offshore wind To date, just a handful of small offshore wind farm projects have been decommissioned, but increasing numbers are expected towards the late 2020s. Elaine Maslin reports.
I
n some ways, the wind industry is still in a maturation phase. Innovation continues in terms of turbine technology and there is still fundamental research ongoing around blade materials. Yet decommissioning has started and in 2020–2025 the first large Danish (such as Horns Rev 1 and Nysted) and UK Round One (including North Hoyle and London Array Phase One) offshore wind projects will be hitting the 20-year operational milestone. Estimates predict that one or two wind farms (<10 MW) are expected to be removed each year in the 2020s, with numbers increasing towards the late 2020s. By 2034, close to 3 GW of wind power will reach the end of its design life, according to Axel Laval, Asset Manager, The Crown Estate. That amounts to 1,000 turbines to be removed. However, just as offshore oil and gas decommissioning costs and timing have been riddled with uncertainty, offshore wind decommissioning costs currently vary hugely and timing will likely follow the same trend. The challenge for offshore wind is that this creates uncertainty around the cost of energy for ongoing and future wind farms, said Laval, speaking at the Decom North Sea and OGUK Offshore Decommissioning Conference last November. ‘It’s difficult to lower the cost of energy if you don’t know the cost of removing it,’ he stated. To date, just a handful of small projects have been decommissioned, including the world’s first offshore wind farm, Vindeby, in Denmark, and the first two UK wind turbines, at Blyth, in the UK. The first offshore wind decommissioning project was Yttre Stengrund (five 2 MW turbines built in 2001) in Sweden, which was removed in 2016, followed by Lely, (four 500 kW turbines built in 1994) in the Netherlands, and some other small early wind farms. In the UK, the period 2032–2038 (based
Lely in the Netherlands was one of the first offshore wind farms to be decommissioned Photo: Hebo
on 20–25-year life spans) could be when activity picks up as some of the Round One projects come to the end of their life, such as North Hoyle, Thanet, Greater Gabbard and London Array Phase One. Counting the cost Cost estimates for removing wind farms are about £80,000–300,000/ MW, according to Laval. The total liability for the installed base as at 2017 has been estimated at £1.82bn. Given the wide range of cost estimates per MW, that means to decommission the installed base as at 2017, the numbers could be in the £1.28–3.64bn range, he said. A report by consultancy Arup in 2018, commissioned by the Department of Business, Energy and Industrial Strategy (BEIS), estimated costs at between £27–79mn per wind farm, based on an assessment of a selection of 37 wind farms. Aside from costs, a challenge is what to do with the decommissioned turbines – particularly the composite blades. If the goal to reach 30 GW of offshore wind power in the UK by 2030 is met, there would be some 600,000 tonnes of composites to be removed at the end of life, 5mn tonnes
of steel and 300,000 tonnes of copper. While the steel and copper would recover scrap value at about £1.05mn each, the composites would cost £60mn to put in land fill. Marylise Schmid, Analyst – Environment and Planning, at WindEurope, comments: ‘Blades are more challenging because they’re made of composite materials; glass or common fibres or polymers.’ Much of it is thermoset composite, which, when cured, sees cross linking of the polymers mixed in with resins and glues. That means specific recycling technologies are needed to be able to break up these chemical bonds. Today, there are two main types of recycling technology used for this. One aims to recover original fibres in the blades using solvents or heat. ‘What all these have in common is that they’re not mature yet,’ notes Alexander Vandenberghe, WindEurope’s Advisor – Research & Innovation. The other type is ‘downcycling’ type technologies that are a bit more mechanical, such as coprocessing in cement kilns or mechanical grinding, which create a composite dust or pellets for reuse as a feedstocks or for other uses. One example of this is a company making garden furniture from recycled wind farm blades, says Vandenberghe. However, while there is more maturity in this technology, it is not yet at the volumes that could be needed. Furthermore, the current price of virgin materials for composite components is low – and much lower than the cost of recycling the fibres. Recycled fibres are also lower quality – they will always be shorter so they cannot be recycled back into blades. Vandenberghe says there is political will to make turbine technology more sustainable. Vestas Wind Systems, for example, has pledged to eliminate all waste in the production of its machines by 2040, as part of a drive to hit carbon neutrality by the start of the next decade. Some chemicals companies are trying to develop resins that are more easily recyclable. Meanwhile, work continues to investigate wind farm blade performance through the lifetime of a project and develop materials and technologies to help extend life. As a result, just as has been seen in the oil and gas sector, offshore wind decommissioning dates could be pushed further into the future. ●
Petroleum Review | September 2020 29
Europe
GAS
Deflated gas market Dr Anouk HonorĂŠ, Senior Research Fellow, The Oxford Institute for Energy Studies (OIES), looks at the impact of COVID-19 on Europeâ&#x20AC;&#x2122;s gas sector.
O
COVID-19 hit an already weak European gas market and the future remains uncertain, depending on the speed and scale of economic recovery Photo: Shutterstock
n 13 March 2020, the World Health Organization (WHO) declared Europe to be the epicentre of the new coronavirus epidemic. Across the region, countries were closing their borders and introducing increasingly strict restrictions on movement to stop the virus spreading. Italy was the first in the world to issue a nationwide lockdown on 11 March, but within a week or two, many other European countries had taken similar decisions. Containment policies have been almost exclusively national and not uniform across Europe, with various degrees of restriction, geographical coverage and starting dates. These measures largely halted economic activity, with social distancing encouraged, public events banned, schools closed and most non-essential retail and manufacturing activities shut down or ordered to operate at minimum levels for several weeks. The most drastic measures were taken in Italy, France and Spain. But despite the differences in response to the virus, the measures have come at huge economic and social cost to all countries.
Weak demand Gas demand in Europe was already weak even before the COVID-19 pandemic reached its full extent.
30 Petroleum Review | October 2020
Winter 2019â&#x20AC;&#x201C;2020 was mild, wet and windy, a combination of factors not favourable to high gas demand in the region. Warm temperatures seen in January, especially in north-west Europe, limited the need for gas used for heating in buildings as well as heating-related electricity consumption. Strong winds in February further limited the potential for gas used in power generation. As a result, gas demand was down both in January and in February year-on-year. The effect on gas demand of reduced activity or even temporary closure of power-intensive manufacturing and retail shops, restaurants/cafes and offices started to be seen from the second half of March in the industrial and power generation sectors in most countries, but at varying degrees depending on the severity of early lockdown measures. Total gas demand in March was still above 2019 levels due to below average temperatures in western countries in the second half of the month. With more people staying at home, cooler weather is thought to have had a stronger impact on gas use than usual. In both April and May, total gas demand in Europe was down by 16% year-on-year despite the very careful relaxation of restrictions which started in mid-April in
various countries as the spread of new COVID-19 infections started to slow down across Europe. A gradual reopening of the economies started in May, but precautionary measures such as social distancing remained (and are likely to continue for several months). Manufacturing output rose by about 12% on a monthly basis, but remained considerably lower than in 2019. The impact on gas-based power generation varied widely across Europe, but as a result of relatively high carbon prices, most of the least efficient coal plants were priced out of the mix and in countries where some coal-to-gas switching was still possible, such as in Germany or even in Poland for instance, gas-based generation showed good resilience because of the low gas prices. June was the first full month outside of confinement in many countries. The heaviest restrictions were lifted and more global supply chains were restored. Industrial output grew by 9% from May, although with big variations by countries and by sectors as government measures to curb the pandemic affected some more than others and was still about 12% down year-on-year. Lower renewables led to strong growth in gas-fired generation (about a third higher than in May) and preliminary data show that total gas demand was only about 2% below 2019 levels. In July, demand in gas-intensive industry continued to improve, hot temperatures increased demand for air conditioning, especially in southern Europe, and some additional coalto-gas switching (when possible) boosted power sector gas burn, in particular in Germany. All in all, in the first seven months of 2020, gas demand in Europe is likely to have declined by about 7%, or 20bn cm year-on-year due to the successive impacts of mild temperatures, high renewables in power generation (with hydro and wind as the main contributors) and the consequences of COVID-19. The road ahead What can be expected for the rest of the year? While policies are likely to take the lead as the main driver of future gas demand in Europe in the 2020s and beyond, in the short term, much will depend on the speed of economic recovery, the level of power demand and the available generation mix and finally, temperatures over the winter.
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Europe
In early April, the International Monetary Fund (IMF) forecast a decline of 7.1% of GDP in 2020 before a rebound in 2021. In May, the European Commission expected an even worse scenario for 2020 but followed by a stronger recovery in 2021, although the EU economy was not expected to have fully made up for this year’s losses by the end of 2021. Meanwhile, in its May bulletin, the European Central Bank suggested that the Euro area’s GDP could fall by between 5–12% in 2020 depending on the duration of the containment measures and the success of policies to mitigate the economic consequences for businesses and workers. A rapid rebound, the so-called ‘V’ shape, seemed unrealistic according to its President, Christine Lagarde, and the scenario of only a 5% decline was probably already out of the question. In early June, the OECD projected a decline of 9% of the Euro area’s GDP in 2020 in its single-hit scenario (ie if the virus remains contained after the end of the lockdowns in May/June) and a sharper decline of 11.5% if a second pandemic wave takes place later in 2020 (the double-hit scenario). The risks surrounding these forecasts seem very large and concentrated on the downside. The EU and national governments have been spending more money more quickly than during the financial crisis a decade ago, but more will be needed, especially in the hardest hit countries. The measures are likely to protect some companies from the immediate effect of the crisis for a few months. However, once this support is gone and loans need to be repaid, many companies may face shutdown or relocation. The extent of the economic damage is still uncertain, as is the speed and scale of recovery. In addition, several countries have been registering increasing numbers of coronavirus infection in July/August/September and
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Other market drivers Even if the economic situation does not recover before 2021/2022, other drivers may influence (sustain) gas demand. In the early 2020s, utilities and industry will be able to continue to take advantage of low gas prices. There are expectations that gas prices will recover gradually over the next few years as the global supply and demand balance tightens, but they will struggle to exceed $6/mn Btu (and may well go into decline again from 2025 as a new wave of LNG supply emerges). In the power sector, while renewables availability is likely to remain high, cheap gas (and a relatively high level of carbon prices) means that gas-fired plants are competitive with coal-fired units. By the end of July, clean spark spreads (gas generation) were at least €15/MWh above clean dark spreads (coal generation) in many countries (based on Argus data for 55% efficiency gas plants and 38% coal). Coal-to-gas switching will continue where possible (many countries already have zero or very little coal in their mix). Various countries around Europe have decided on coal phase-out sometime in the 2020s, and about 20 GW are due to close down by 2023. These restrictions, coupled with bad economics and EU emissions regulations on large combustion plants, could mean an acceleration of coal retirement in Europe by the end of 2020/2021 and potentially more room for gas in the mix. Cold temperatures could also boost gas demand for heating at the end of the year. A difference
Uncertain times There is no doubt that measures taken to fight COVID-19 have had, and will continue to have, an enormous impact on European economies. Uncertainties remain as to their ability to bounce back in the coming months. A slow recovery in 2H2020, continued low gas prices, low coal in the generation mix, average temperatures in the winter and localised lockdowns could see a possible decline of gas demand in Europe of about 7% for the whole year. In this scenario, gas consumption would go down to about 463bn cm (34bn cm less than in 2019), which would still be above the low levels seen in 2014 and 2015 (433bn and 450bn cm respectively). All in all, while governments focus on immediate (and green) recovery, other factors may support gas demand in the early 2020s – even if economic recession sets in. Importantly, even an economic bounce-back may not necessarily equate to longer term gas demand recovery – even if low gas prices continue. Fossil gas demand in Europe should not expect to recover for much longer in the context of the Green Deal and climate neutrality by 2050. What happens in and post 2020 will only define how quickly fossil gas will decline (or disappear) from the energy mix… to be replaced potentially by low carbon or renewable gases? l
• Addressing winter fuel poverty in the time of COVID-19 • Tackling unreliable electricity in Sub-Saharan Africa • Sustainable development and achieving global energy goals
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between a cold and a warm winter in Europe can easily increase gas demand by 20–30bn cm. However, if people continue to social distance and work from home, even milder temperatures may well raise gas demand above what could be normally expected.
In this month’s Energy World:
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these fresh outbreaks could result in new or deepening of remaining restrictions. This could slow the economic recovery of these countries, cut into industrial activity and lower power demand, all of which would dampen gas consumption.
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Energy World is the monthly sister publication to Petroleum Review, covering renewables, power generation and energy efficiency. As an EI member, you can subscribe to Energy World for £60, or access it online, for free, at https://knowledge.energyinst.org/magazines/energy-world For more information visit www.energyinst.org
Europe
SPAIN
Energy transition, second time round Will Spain’s energy transition be a job creator or destroyer? asks Maria Kielmas.
I
n late November last year, when Spain’s Ministry of Ecological Transition approved an environmental impact assessment by Sociedad de Hidrocarburos de Euskadi (Shesa) to drill for gas in Ávala Province south of Bilbao, it set in progress a series of reactions that illustrated the ambiguities and misunderstandings of the country’s second attempt at an energy transition. Founded in 1983 and 100% owned by Ente Vasco de la Energía (EVE), the Basque Country’s regional government energy agency, Shesa’s mission has been to explore for and provide oil and gas to its region. The planned Armentia-2 well is to be drilled conventionally, to a depth of between 4,993–5,540 metres at a cost of €27mn. But this drilling programme has been interpreted locally as fracking and has triggered numerous protests by local environmental groups. These groups claim also that it counters Spain’s national energy strategy to be carbon neutral by 2050. Juantxo López de Uralde, a member of the Congress of Deputies, the lower house of Spain’s legislature for the leftist Unidos Podemos, the junior partner in Spain’s fragile governing coalition, has demanded that the
32 Petroleum Review | October 2020
‘nonsense’ of Armentia exploration should be stopped ‘once and for all’. It is not possible to talk about an energy transition and proceed with gas exploration, he says. Draft climate law In May 2020, the government presented a draft law that would cut Spain’s net carbon emissions to net zero by 2050. This includes a ban on all coal, oil and gas projects. State and public institutions will have to divest from all activities related to the refining, processing and production of fossil fuels. Nine of 14 coal plants will be closed over the next few years and, after 2030, the last nuclear plant goes offline. But since the closure of mining basins in León Province at end2018, Spain has been importing coal-fired electricity from Morocco via the subsea power link. Spain currently imports over 95% of the fossil fuels it consumes, notably natural gas through two pipelines from North Africa to its southern coast, and through an interconnection with France in the north. Natural gas is broadly envisaged as the transition fuel in the country’s decarbonisation programme. But this depends on the share it will maintain in both the power generation and the transportation sectors. Nearly half of Spain’s power generation is gas-
fired. As gas replaces coal in power generation, gas prices effectively govern wholesale electricity prices. Gas supplies In May this year the US became the leading gas supplier, increasing its LNG exports to Spain by 467% year-on-year while pipeline imports from Algeria fell by 30%. Between January and March 2020 Spain imported 20.25 TWh of gas from the US and 19.75 TWh from Algeria. Algerian gas to Europe sold at $6/mn Btu but oversupply from the US and Qatar pushed the market down to $2/mn Btu. As a result, Barcelona-based Naturgy – formerly Gas Natural Fenosa – the main importer of gas from Algeria, saw its profits fall by 44% over 1H2020 compared with the same period in 2019. Naturgy is now in talks with Algerian state Sonatrach over changes to its gas supply contract. Both companies say they hope to avoid international arbitration. The draft climate law follows an interim strategy, the National Integrated Energy and Climate Plan (PNIEC), first proposed in January 2020. This sets out the energy transition over the period 2021–2030 when renewable energy will represent 74% of total power generation, paving the way for a 100% renewables share by 2050. According to Manuel Monge,
EVE/Enegas Bahia de Bizkaia regasification plant, Bilbao Photo: Sedigas
Europe
Associate Professor of Financial and Energy Economics at Universidad Francisco de Vitoria in Madrid, this will need a total investment of €240bn over the period, of which electricity distributors must invest €23bn. This is a key enabler of other high added value investments related to the energy transition. The European Union’s Green Deal and recovery fund will also be additional fundamental tools to a postCOVID-19 recovery, Monge adds. Economic slump Spain’s economy slumped 18.5% in 2Q2020 and by 22% compared with 2Q2019. An August report from the Bank of Spain forecast that government debt could reach 125% of GDP next year. This will cause a liquidity trap in the future as the government will issue bonds that effectively crowd out private sector debt issues. So, utilities may find the financing of investment problematical. Unemployment is expected to reach 21.7% by end2020, the second highest in the eurozone after Greece. Spain’s last attempt at an energy transition ended with the 2008 financial crisis, but up to that point, was no job creator. According to a 2009 report by researchers at Universidad Rey Juan Carlos in Madrid, in 2000 Spain spent €571,138 to create each green job, including €1mn per wind industry job. Only one out of 10 of these jobs was permanent. One quarter were in administration and marketing and project engineering, while two-thirds were in construction, fabrication and installation. This spending hindered Spain’s way out of the 2008 crisis, the report noted. The current COVID-19 crisis differs from the 2008 financial crisis in that it has affected all countries. So, the energy transition could be delayed for a number of reasons, says Monge. These include a drastic change to energy use and supply shock to the world economy caused by population confinements and health measures. Firms have seen their incomes fall over this period due to reduced consumption and this could affect future investments. In Spain, the coronavirus pandemic caused a 12.7% fall in electricity demand in the industrial and services sector between March and June, while gas demand fell 15.5% over the same period. Green deal The EU Green Deal foresees spending of €260bn/y to meet a carbon emissions reduction target of 40% vis-à-vis 1990 by 2030. But this implies that the EU Commission is effectively imposing
Combined cycle power plant in Malaga, operated by Naturgy Photo: Naturgy
faces an impossible task without major new grid expansion. Requests for renewables access to the grid totalled 430,000 MW over recent years while the grid itself has only a capacity of 105,000 MW. This situation would be worse if Catalonia had a less restrictive legislation on the location of renewable energy projects. The problem is Catalonia’s high population density and the perceived overall environmental impact of renewables on the agricultural sector, especially around the Ebro and Empordá river basins. Practically no new renewable projects have been installed over the past decade and the region holds just 5% of Spain’s installed renewable capacity. Decentralised projects and smart grid development are difficult in an energy policy on member states, Spain. Five large corporations – says Samuele Furfari, Professor Endesa, Iberdrola, Repsol, Naturgy of the Geopolitics of Energy at and Eletricidade de Portugal – the Université Libre de Bruxelles. control 70% of power generation ‘They will stifle the economies of and 90% of sales. A country with member states,’ he says. This policy year-round sun, Spain has just is contrary to both Article 194 of 10,000 sun-roofs with solar panels the 2007 Lisbon Treaty, which compared with 1.4mn in Germany. states that energy policies are the Furfari takes a caustic view of the responsibilities of member states, EU’s lack of transmission capacity. ‘A and to the 1994 Energy Charter few years ago people were confident Treaty (ECT), whose aim is the that they could invest millions in protection of fossil fuel investments, smart grids. But now no one really continues Furfari. It promotes wants to invest. They can’t find the energy efficiency but not renewable funds,’ he notes. energy. The ECT has a total of 54 signatories of whom only 27 are EU Seeking compensation members, and a further 33 observer Spain will receive €140bn from countries. ‘Nobody outside of the EU the recovery fund and Green Deal, wants to change the charter,’ Furfari equivalent to 11% GDP in 2019. says. An EU withdrawal from the This will be divided into €72.7bn ECT would not mean the other direct transfers over 2021–2024. countries would withdraw, but This amounts to 10 times what could create significant problems Spain received in cohesion funds for oil and gas exporting signatories over 2014–2020. However, provinces and observers, especially former dependent on fossil fuels are lining Soviet republics in Central Asia, as up for compensation. well as an overall legal imbroglio. In the north of the country some 25% of the province of Asturias' Transmission problems GDP depends on industry, mainly The EU budget and €750bn recovery coal-fired energy and steel making fund have slashed earlier planned that depends on coal. The energy financing of climate goals. These transition could remove most of will receive only €17.5bn from the this. recovery fund and budget, down In the south in Almería, from an earlier €37.5bn. InvestEU, local councillors stress that the another pot of money to help MedGaz pipeline from Algeria green goals, also suffered a cut. is part of the region’s basic This will now be €4bn down from infrastructure. Diversification of an earlier €31bn and is unlikely Spanish gas supplies hurts the to help finance urgently needed region’s economy. Endesa has additional power transmission made a €213mn provision for 577 capacity. Access to overloaded voluntary redundancies caused by power transmission grids for the decommissioning of coal-fired burgeoning new renewables power plants. capacity is a problem that Spanish The question overhanging utilities, like their counterparts in Spain’s energy transition is: Will it Germany and Sweden, are reluctant create more employment than it to talk about. Grid operator Red destroys? ● Eléctrica de España has performed well throughout the crisis, but Petroleum Review | October 2020 33
EI Technical
AVIATION FUEL FILTRATION
Meeting a global challenge For nearly three years, the international aviation fuel handling industry has been working to address an issue that could lead to a fuel contamination incident on an aircraft, caused by the very equipment intended to ensure fuel cleanliness during aircraft fuelling. Martin Hunnybun, Head of Good Practice Fuels and Fuel Handling at the Energy Institute, explains.
O
n 14 November 2017, an International Air Transport Association (IATA) Special Interest Group announced that ‘filter monitors shall be phased out of all aviation fuel handling systems’. Filter monitors are a type of filter deployed worldwide on refuelling vehicles (hydrant dispensers, carts and refuellers) that also incorporate water-absorbing material to prevent free water passing to aircraft. Evidence of the migration into fuel of that water-absorbing material under normal operating conditions, and the implications for engine operability, led to the announcement. The statement had significant implications for the industry, which has safety of flight at its very core. Information for filter monitor users was quickly disseminated, including procedures intended to minimise the risk of media migration and emphasis on the alternative filter/water separator system recognised by industry operating standards as suitable for immediate deployment. The EI also stated that the filter monitor qualification test specification, EI 1583, would not be updated or maintained beyond its 7th edition and would be withdrawn by no later than 31 December 2020.1-4 There was recognition that the fastest transition away from filter monitor use would require a new type of filter element (not available at that time) to retrofit into existing filter vessels in place of filter monitor elements. The EI helped to establish a collaborative approach between stakeholder organisations for laboratory assessment and controlled field evaluation of potential candidate technologies. So began an unprecedented global collaboration. Renewed focus This activity threw a spotlight on the importance of fuel hydrant system operators diligently applying fuel cleanliness control
34 Petroleum Review | October 2020
procedures. These are described in the newly updated EI 1560 Recommended practice for the operation, inspection, maintenance and commissioning of aviation fuel hydrant systems and hydrant system extensions, 2nd edition (July 2020). Filters on hydrant dispensers/carts are intended as a protection barrier in case other equipment/procedures fail (the last line of defence); they should not be required to compensate for deficiencies in tank farm/hydrant system operations. New retrofit technology Since the beginning of 2018, the EI has issued nine publications to support the transition away from filter monitors and provided expert witnesses for 15 laboratory evaluations performed by manufacturers. It is only under controlled laboratory conditions that system performance in response to free water and particulate matter challenges can be assessed safely. That work has so far resulted in two new approaches going forward to controlled 12-month into-plane field trials (organised by Airlines for America (A4A), IATA and the Joint Inspection Group (JIG)). Those organisations have recently published a Joint Filtration Field Trial evaluation summary for one of those replacement options – a dirt defence filtration system (qualified in accordance with EI 1599) combined with an electronic water sensor (conforming with EI 1598, that had previously been subjected
An electronic water sensor located downstream of a dirt defence filter on a refuelling vehicle
bit.ly/ EIbulletin2017 2. bit.ly/ A4Abulletin2017 3. bit.ly/ JIGbulletin105 4. bit.ly/ EIseminar2018 5. bit.ly/ Techsummary 6. bit.ly/ A4Abulletin2020 7. bit.ly/ JIGbulletin130 8. go.shell. com/2QjDuTc 9. bit.ly/ EIseminar2019 10. bit.ly/ EIseminar2021 1.
to extensive field evaluation).5 Both A4A and JIG have also recently modified their operating standards to adopt that combination of a new type of filter element with an electronic water sensor.6-7 This is a major breakthrough for the introduction of new technology for global into-plane operations. Existing filter monitor users worldwide now have two replacement options – a filter/ water separator (requiring vessel replacement) or retrofitting dirt defence filter elements into the existing filter vessel and installing a downstream electronic water sensor. Global fuel suppliers have responded, with Shell Aviation, for example, announcing publicly that all of its refuellers at Shell-managed locations worldwide will be fitted with dirt defence filter elements and a downstream electronic water sensor by the end of 2020.8 Ongoing development Another new retrofit technology is the water barrier filter. A model of water barrier was qualified to EI 1588 for the first time in April 2019 and significant laboratory assessment has led recently to the initiation of into-plane field trials. This filter is described in EI 1550 Handbook on equipment used for the maintenance and delivery of clean aviation fuel, 3rd edition (August 2019). The outcome of field trials is eagerly anticipated. Several other technology developments have been made public by filter manufacturers, as described during an EI seminar in September 2019.9 These developments are in their infancy and if they are successful, they are realistically some three years away from acceptance in operating standards. Time to act is now A new fuel cleanliness control system has been adopted by global operating standards, for the first time in several decades. Existing users of filter monitors can now consider two systems in their sitespecific transition plans and should do so without delay. Further information on industry developments in the next six months will be presented at a third EI seminar on this topic, to be held online on 24 March 2021.10 ●
Learning
HUMAN FACTORS
Achieving sustainable change Mark Sujan, Managing Director, Human Factors Everywhere, describes a process to capture learning from adaptations and changes made during COVID-19.
T
he Chartered Institute of Ergonomics and Human Factors (CIEHF) has developed guidance on Achieving sustainable change: capturing learning from COVID-19 to help organisations learn from the positive changes made as the world continues to adapt to the pandemic.1 The guidance is aimed primarily at the health and social care sector, where people have been at the frontline of dealing with COVID-19 since the beginning of the outbreak. However, the principles described apply equally to organisational learning across sectors, including the energy industry.
In the energy sector, organisations were hit hard by a sudden and sharp drop in demand coupled with lockdowns and restrictions on international movements. People and organisations had to adapt, for example through the widespread introduction of flexible and remote working. Operational activities and critical maintenance activities needed to be reorganised, and regulatory inspections were temporarily suspended or had to be conducted remotely without site walkthroughs. Many of these changed circumstances are here to stay for
Figure 1: Organisational learning can be achieved by examining and changing a mindset and following this with the actions that are required to embed and deploy the achieved learning Source: CIEHF
a significant period of time. As people start returning to work, new ways of working need to be developed that are consistent with requirements for social distancing and safe working during COVID-19. Regulatory and professional bodies such as the Health & Safety Executive (HSE), the Institution of Occupational Safety and Health (IOSH) and CIEHF have all issued guidance on safe return to work. Organisations have introduced increased cleaning regimes, one-way walkways and team â&#x20AC;&#x2DC;bubblesâ&#x20AC;&#x2122; to maintain social distancing and reduce the risk of spreading infection. These can have potentially critical knock-on effects on communication, staffing levels and infrastructure availability, and risks have to be assessed and managed accordingly. Collaboration and creative leadership However, a positive emerging from the pandemic is that organisations are even more prepared to share information and good practice across organisational and national boundaries, and there is a willingness to work together in order to keep people safe. In addition, during the crisis many organisations have seen creative leadership from frontline staff, where improvements and changes were developed and implemented bottom-up and with more ready deference to expertise rather than in the traditional hierarchical topdown fashion. If these changes are not documented and analysed properly, there is a danger that valuable lessons are not learned. Many frontline staff are eager to reflect on how they managed to work safely and effectively during the pandemic, and want to see positive changes sustained. Organisations need to learn from COVID-19, but deciphering the learning from such a complex and immediate situation is not straightforward. Learning from what an organisation did well is often overlooked by safety management systems that are conditioned to identify and control risks, and that focus on what went wrong.
Petroleum Review | October 2020 35
Learning
With this new guidance, CIEHF draws on insights from resilience engineering and ‘safetyII’ management, where safety is regarded not as the absence of something (ie incidents and accidents), but rather as the presence of something – the ability to anticipate and to adjust performance to meet changing demands and deal with disturbances and surprises. This increasingly popular perspective appears ideally suited to capture, document and learn from the many adaptations that people have made during COVID-19 (the ‘work-asdone’). The CIEHF guidance aims to support organisations by describing organisational learning in terms of the mindset and the actions needed to achieve sustainable change (see Figure 1). The mindset – or learning structure – is about how an organisation approaches organisational learning. The guidance contains prompts to encourage organisations to think about their learning goals, who is involved in organisational learning, how deep their learning is, the types of situations they try to learn from and the processes they have in place to foster learning. The action – or learning process – describes how organisational
learning actually takes place in an organisation, or how it is carried out. The guidance puts emphasis on learning from everyday work (rather than just from incidents) to understand how workers adapt to situations and changes. It emphasises that workers should have an active role to play in organisational learning to ensure that learning is meaningfully related to practice. And, where possible, staff should be encouraged to take ownership for taking changes forward, and should be given authority and resource to do so. Finally, any changes that are implemented will likely require further adjustments over time, and therefore the learning process should be continuous and feedback from staff should be sought and given. The guidance appreciates that learning lessons and putting them into meaningful change is a tremendous challenge for organisations in any sector. In part, this has been due to the well-intentioned, but somewhat narrow focus on learning from incidents. This perspective has been extremely limiting, and often organisational learning has been reduced in practice to an administrative exercise of counting ‘lost time’ injuries and
other adverse events. With this guidance, the intention is to move away from negative notions of incidents, errors and blame, and to encourage organisations to reflect on what goes well even when situations are challenging. How safe spaces (in terms of psychological safety) can be created where people can contribute to organisational learning, and where they can take ownership of change and improvement. Embedding a more positive approach to organisational learning can equip organisations to achieve sustainable change during COVID-19 and beyond. Learning and sharing lessons now can help prepare the energy industry for potential further outbreaks. Reflecting on how staff at all levels of an organisation adapted successfully to the challenges. Adopting the mindset and processes capable of learning from what goes well, will serve the industry in its transformation towards low carbon technologies and greener energy production. ● bit.ly/HFSustainableChange
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