Decarbonisation Technology - November 2021

November 2021 D carbonisati n Technolo gy Pow ring the Transition to Sustainable Fue s & Energy

DECARBONISATION OF STEAM CRACKERS SITE EMISSIONS: NEW METRIC FOR COMPETITIVENESS

COP26 SPECIAL

HYDROGEN: POTENTIAL SUPERFUEL?

Where energies make tomorrow

Accelerating the energy transition for a better tomorrow

Technip Energies is a leading engineering and technology company for the energy transition. We offer leadership positions in LNG, ethylene and hydrogen, as well as growing market positions in sustainable chemistry, CO2 management and carbon-free energy solutions. Through an extensive technology, products and services offering, we bring our clients’ innovative projects to life while breaking boundaries to accelerate the energy transition to a low-carbon society.

L N G

LNG and Low-Carbon LNG

Sustainable Chemistry

Onshore and offshore liquefaction

Biofuels, biochemicals, circular economy

H 2

Green hydrogen, offshore wind, nuclear Carbon-free energy solutions

Energy efficiency, blue hydrogen, CCUS Decarbonization

technipenergies.com

1CCUS : Carbon Capture, Utilization and Storage

Contents

November 2021

Play a leading role in the energy transition Robin Nelson

Transformational potential for climate change mitigation Stephen B. Harrison sbh4 Site emissions become a new metric for competitiveness Alan Gelder Wood Mackenzie

Decarbonisation of steam crackers Jim Middleton Technip Energies

First principles of energy transition - Part 2 Jean-Gaël Le Floc’h, Mel Larson, Darren York and Robert Ohmes Becht Hydrogen: potential superfuel? Chuck Baukal, Bill Johnson, Michel Haag, Gilles Theis and Matt Whelan John Zink Hamworthy Combustion, a Koch Engineered Solutions Company

Green hydrogen: a possible path towards a low carbon future Dr Himmat Singh Scientist ‘G’ & Prof (Retd)

New low carbon methanol production approach Dan Barnett BD Energy Systems, LLC

A low carbon alternative to HFO Jack Williams Quadrise Fuels

Well to wake and beyond Susan BrownlowWords for Industry

How advanced process control can support decarbonisation Martin Gadsby Optimal Industrial Technologies Find opportunities to decarbonise with pinch technology David Hart Energy Intelligent Solutions Challenges and opportunities of achieving sustainable operations Antonio Pietri Aspen Technology

Leverage digitalisation for sustainable operations Dr Pratap Nair Ingenero

Moving to a more sustainable future with Coriolis technology Meha Jha and Julie Valentine Emerson Monitoring technology for ethylene crackers and SMRs James Cross AMETEK Land Role of gas analysis in clean air strategies to reduce emissions Matt Halsey Servomex

The need for custody transfer in the hydrogen industry Danny Knoop ABB

Capturing green opportunities Marcel Suhner Sulzer Chemtech

Decarbonisation through innovation NEUMAN & ESSER GROUP compressor solutions

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Visit our booth at ERTC November 15-18, 2021

W elcome to the second issue of the transition to sustainable fuels and energy. First of all, we would like to thank all our readers for their valued support and overwhelmingly positive response to our launch issue, which shows there is a keen interest in searching for answers to some of the biggest challenges our industry has yet to face. The release of our second issue coincides with the start of 26th UN Climate Change Conference of the Parties (COP26), which will bring parties together to determine the actions required to meet the goals of the Paris Agreement and the UN Framework Convention on Climate Change. One objective of the summit is to strengthen the National Determined Contributions (NDC), the commitments by governments, to mitigate climate change. A second objective is to further define some of the measures needed to accelerate climate action. Decarbonisation Technology , a digital magazine that focuses on the policies, strategies and technologies powering This issue focuses on the energy transition and shares progress in the deployment of technologies that are driving the transition in oil and gas. Several articles discuss the policy recommendations needed to accelerate investment in renewable feedstocks, hydrogen and alternative fuels, as well as carbon capture and usage. Energy efficiency measures present some of the short-term opportunities to reduce emissions, as do new analytical techniques and measurement tools. We are also pleased to announce our series of Decarbonisation Technology Summits, which will explore the cutting edge of global decarbonisation technologies, solutions and supporting infrastructures. Turn to page 70 for more information on these events. As always we hope you will find this issue both interesting and informative. Register HERE to receive your regular copy, and to contribute to future issues,

Managing Editor Rachel Storry editor@decarbonisationtechnology.com tel +44 (0)7786 136440 Business Development Director Paul Mason info@decarbonisationtechnology.com tel +44 844 5888 771

Managing Director Richard Watts richard.watts@emap.com

Graphics Peter Harper

Circulation Fran Havard

EMAP, 10th Floor Southern House Wellesley Grove, Croydon CR0 1XG

please send any editorial suggestions to editor@decarbonisationtechnology.com

©2021. The entire content of this publication is protected by copyright. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means – electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner. The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies.

Cover Story Oilrefineryandpetrochemicalplant, with naturalgasstoragetank

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LH 2

COP26 SPECIAL

Play a leading role in the energy transition

Transformation of the energy systemmust support the development of renewable electricity and fuels, while progressively reducing the demand for fossil fuel

Robin Nelson

I n the lead-up to the 2021 COP 26 meeting in Glasgow, the Intergovernmental Panel on Climate Change (IPCC) Working Group 1 released their latest report on the physical science basis of climate change, as a contribution to the IPCC sixth Assessment Report. The Summary for Policy Makers concludes that it is “unequivocal that human influence has warmed the atmosphere, ocean and land. Widespread and rapid changes in the atmosphere, ocean cryosphere and biosphere have occurred”. 1 The United Nations Environmental Programme (UNEP) Emissions Gap Report provides a yearly review of the difference between where greenhouse emissions are predicted to be in 2030 and where they should be to avoid the worst impacts of climate change. The 2020 Emissions Gap Report found that, despite a brief dip in carbon dioxide (CO 2 ) emissions caused by the COVID-19 pandemic, the world is still heading for a temperature rise in excess of 3ºC this century, far beyond the Paris Agreements goals of limiting global warming to well below 2ºC and pursuing 1.5ºC. 2 IPCC and UNEP conclude that it is highly probable that we will pass the 1.5ºC limit before 2030. Unless all sectors of society including governments, cities, local authorities, and businesses act decisively there is little chance of changing the trajectory to remain below 2ºC by 2050.

Time to transform The World Business Council for Sustainable Business Development (WBCSD), in its updated Vision 2050 , 3 stresses that now is the “Time to Transform” to deliver both the Climate Action and the UN Sustainable Development Goals. The WBCSD vision describes nine pathways for businesses to play a leading role in this transformation, one of which is the transformation of the energy system. Whilst we must recognise the interconnections between energy and the other Sustainable Development Goals, the focus of Decarbonisation Technology is on what the oil and gas sector can and is doing to bring about the energy transition. The International Energy Agency (IEA), in their World Energy Outlook 2020 , highlights that while the energy transition has made progress over the last decade, a full implementation of their IEA Sustainable Recovery Plan is necessary to change the longer term trajectory and meet the targets of the Paris Agreement. 4 The IPCC states that to stay within the world’s remaining carbon budget we must stop exploiting fossil fuels (coal, oil and gas). The need to ensure we deliver the energy for heating/cooling homes and workplace, for cooking, for the movement of goods and people shows that this is currently impractical and so even with the best will from the forthcoming COP it is likely to remain a longer term target.

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Hydrogen in 2020 Virtually all grey, emitting 830 Mtpa COeq

Hydrogen in 2050 Consistent with a net-zero society

GHG emissions

Production potentially 800 Mtpa

Production

Production 70 Mtpa

Negative carbon H <0

Net-zero carbon H on life-cycle basis

Ultra low- carbon H ≤ 1 kg CO/ kg H

Low- carbon H ≤ 3 kg CO/ kg H

Reduced carbon H ≤ 6 kg CO/ kg H

Existing grey production c. 11 kg CO/ kg H

Carbon intensity of hydrogen

New production/consumption

Figure 1 Stepping stones based on the carbon intesity of hydrogen Source: WBCSD 2021, Policy Recommendations to Accelerate hydrogen deployment for a 1.5ºC Scenario

components, recycled waste, and captured carbon. Refiners are also investing to reduce the energy consumed (and therefore carbon emissions generated) during the production of the fuels, lubricants, and chemical feedstocks. At the same time, gas producers are decarbonising gas streams by converting the methane to hydrogen and capturing the CO 2 . Many of the technologies needed are available now, but of course new innovations designed to further improve efficiency and to bring down costs in the future will be welcome. Hydrogen production Hydrogen is used in most of the processes to upgrade refinery oil streams to useful products. Hydroprocessing includes hydrocracking, desulphurisation, dearomatisation, and denitrogenation processes and hence hydrogen production units are present in most refineries. As we look to decarbonisation technologies, hydrogen assumes even more importance. Some question why hydrogen is needed as renewable electricity powering electric engines is more efficient. Hydrogen can be complementary to pure electric power as it provides an alternative to batteries for renewable energy storage (for instance, in offshore deep water wind installations). Hydrogen can be used as a portable fuel in its own right, to power hydrogen engines or for use in fuel cells. Furthermore, as already mentioned above, hydrogen can be used as a fuel to turn

The energy transition must be a managed transition that supports the development of renewable electricity and fuels, and progressively reduces the demand for fossil fuels. Renewable electricity In developing countries, energy demand is growing. More investment in renewable electricity generation is needed both for burgeoning cities and for more rural areas which lack an electricity supply. In mature economies the focus is on renewable electricity production along with measures to increase the penetration of electric vehicles. Even the most ambitious targets for electric vehicle roll-out are only likely to achieve a measurable reduction in global carbon emissions in the latter half of this century. The reality is that the majority of the world’s cars, trucks, aeroplanes, and ships will continue to require liquid or gaseous fuels. In many northern hemisphere countries, gas is the main means of heating homes in the colder winter months. The IEA’s Sustainable Development Scenario includes a much faster deployment of clean energy technologies but also envisages the operation of existing carbon-intensive assets in a very different way. 5 Technologies which can reduce emissions now and over the next 2-3 decades will buy the time needed to develop and deploy longer term solutions on a global scale. The oil and gas industry understands this and is developing lower carbon fuels. Refinery feedstocks increasingly include different biofuel

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evidence of the efficiency gains and carbon savings achieved. Decarbonisation Technology can help by sharing these stories with a wider audience, going beyond those inside the industry to reach the politicians, their advisers and ultimately the public. This will be valuable in changing the debate away from one of blaming the oil and gas industry to one of encouraging a spirit of cooperative partnership between all stakeholders, vital in driving a rapid transformation to a net-zero global economy. Establishing priorities Societal priorities and politics are important factors that influence the technologies that will be deployed in the next decade. However, it is important for technology providers and users to create options for consideration, and to challenge the priorities. Stabilising the climate is one of three goals (along with protecting biodiversity and respect for human rights) common to the whole global community, hence the COP process. Urgency is critical and as such any technology that can contribute and be deployed at scale quickly must be supported. Thus, in the near term, carbon capture from industrial processes should be supported, even as capacity for direct CO 2 capture from the atmosphere is developed. Similarly, hydrogen production from existing nuclear power plants should be supported as a zero carbon, lower cost option. 9,10 Some of these solutions may not be preferred in the longer term, but such preferences should only be made once the alternative is technically and commercially ready at scale. Bans on fossil fuels or sanctions against energy companies could result in higher prices and supply crises, which in turn could create a negative public perception about climate action. Carbon pricing mechanisms can and should be used as a means of progressively driving the energy transition whilst ensuring energy supply security.

captured CO 2 into renewable, hydrocarbon fuels for harder to decarbonise transport systems such as marine and aviation. It is also valuable as a route for the decarbonisation of whole sectors of the chemicals and metals industries. The issue with hydrogen so far has been the scale of production and the economics. Innovations in hydrogen production are therefore of great interest in the production of low carbon liquid and gaseous fuels. A recent publication from WBCSD on Policy Recommendations to Accelerate Hydrogen Deployment for a 1.5ºC Scenario is a clear example of the importance of progressive decarbonisation. 6 This paper illustrates how it is possible to grow hydrogen capacity from 70 Mtpa in 2020 to 800 Mtpa by 2050 whilst reducing the carbon intensity for hydrogen production from approximately 6kg CO 2 eq/kg H 2 today to 1kg CO 2 eq/kg H 2 by 2050, given the right policy support to encourage investment. Carbon capture and storage Carbon capture and storage is too often dismissed. It is a technology proven at scale, initially in several oil and gas production sites and more recently in downstream refining and petrochemical operations. In 2021, Ineos Grangemouth 7 announced a multi-million dollar investment in carbon capture and storage from its petrochemical operations. Further innovations are extending carbon capture such that the CO 2 is not just stored but reused. For example, recently Repsol and Petronor 8 announced two projects that combine captured CO 2 with green hydrogen (hydrogen produced from the electrolysis of water using renewable electricity) to produce net-zero emissions fuels. These examples show that carbon emissions to the atmosphere can be reduced in the near term. Share knowledge and experiences Whilst refiners are employing a myriad of innovations in refineries that result in emissions reductions now and in the near term, the wider world is largely ignorant of these. It is in the interests of all involved in the industry to share the work it is doing throughout the lifetime of a project from the planning and investment phases, through the commissioning phase, but, most importantly, the operational phase, with

VIEW REFERENCES

Robin Nelson

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Optimizing combustion for a greener tomorrow.

AMETEK process analyzers and sensor technologies have been the industry standard for more than 50 years. Today, our industry faces more environmentally responsible emissions mandates and greater demand for the use of clean energy. That’s why decarbonizing through optimized combustion and enhanced predictive analytics is essential for reducing plant emissions and ensuring equipment uptime. Our Thermox® WDG-V combustion analyzer is field-serviceable and monitors and controls combustion with unparalleled precision. As facilities strive to operate more efficiently and accept more variable fuels at their burners, AMETEK provides solutions for tighter emission control.

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COP26 SPECIAL

Transformational potential for climate change mitigation A broad review and some specific implications for the oil and gas sector

Stephen B. Harrison sbh4

Non-linear, non-reversible, unpredictable trajectory calls for widespread, urgent action The pace of climate change is exponential and many of its effects will be irreversible. The thawing tundra in Siberia is generating a layer of dry combustible material on the forest floor – tinder for wild-fires that destroy beneficial trees and generate carbon dioxide (CO 2 ) emissions with no useful energy capture. Due to climate change, flooding, drought, and starvation will be inevitable, as will increased levels of poverty in many locations. Both Madagascar and Zambia are reporting their worst droughts in over 40 years, with consequential food shortages, famine, and thousands of premature deaths. The finger of blame is clearly pointing at climate change and urgent action is required to reduce CO 2 , methane, and F-Gas emissions from many industrial sectors, including oil and gas processing. There are enough solutions out there to create hope and enable the positive changes that are required. COP26 must be a platform to raise awareness of the issues, stimulate education about the solutions, and propose policy frameworks that stimulate implementation and international collaboration. Price of prevention is less than the cost of catastrophe The business case for prevention is clear at a conceptual level, and a myriad of technologies exists. Many can readily be implemented if there is enough inspirational corporate action, the right regulatory environment, and visionary

political leadership. COP26 is the platform where the consequences of climate change must be presented impactfully and effectively. And the outcomes from the meeting must be transformative, collaborative, international solutions for immediate implementation. There is a price to be borne, but failure to act will cost the earth. Policy leadership ahead of COP26 is coming from several directions. As an example, India could force oil refineries and urea fertiliser plants to use green hydrogen as a portion of their hydrogen production under draft plans sent for cabinet approval by the Indian Government’s Power and Renewable Energy minister, RK Singh. This is proposed as the first stage of a national plan to secure a leading role for green hydrogen in the energy transition. Methane emissions reduction has also been in focus in the run up to COP26. On behalf of the European Union and the United States, European Commission President, Ursula von der Leyen, and President Biden used the Major Economies Forum on Energy and Climate (MEF) to announce the ‘Global Methane Pledge’ on the 18th of September. It will be launched at COP 26 in November, in Glasgow. Several other nations have already signalled their support, and countries joining the Global Methane Pledge will commit to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030. To monitor and implement progress, countries that have committed to the pledge must move towards best available inventory methodologies to quantify methane emissions, with a particular

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dependence and stimulates trade. Amongst the range of clean energy vectors, such as low carbon hydrogen, ammonia, and methanol, all fall short of LNG when it comes to volumetric energy density, which is the important factor for long- distance shipping. Whilst the CO 2 emissions at the power plant from gas fired electricity generation are significantly less than coal, only a tiny amount of methane leakage would give the gas fired option an equally damaging greenhouse gas footprint. It is essential to consider the full lifecycle analysis of fuels production, distribution, and utilisation. Going underground CCS is also an established technology. In Europe, more than 20 years ago, Equinor commenced capture and sequestration of CO 2 on the Sleipner West field in the Norwegian sector of the North Sea. The components of a CCS scheme, from the absorption tower to the multi-stage CO 2 compressor with integrated drying system, are highly developed. Beyond Norway, CCS has also been used in Australia, Canada and the United States for many years. The use of safe, permanent underground CO 2 storage in saline aquifers, depleted oil and gas reserves for CCS schemes is an area where midstream and upstream operators can rise to the decarbonisation challenge. The expertise that has been used to explore and drill for oil and gas can be applied to developing CCS reservoirs. Furthermore, the associated pipeline transmission infrastructure is likely to be adaptable to become the backbone of a CO 2 disposal network. Most existing CCS schemes are point to point, meaning that one carbon capture location such as an ammonia plant SMR is connected to one underground geological CO 2 storage location. This simple model will transition to more complex ‘hub and cluster’ schemes where CO 2 will be captured from several plants and fed into a feeder network connected to a long-distance transmission pipeline. This will mirror the existing natural gas pipeline grids. Sub-surface technologies can also be used for mid-term and long-term storage of energy gases. To add flexibility to integrated energy systems in the future where reliance on variable renewable energy will increase, long-term, high-capacity energy storage will be essential to balance

focus on high emission sources. Delivering on the Pledge would reduce warming by at least 0.2°C by 2050. Major sources of methane emissions include oil and gas, coal, agriculture and landfills. Of these sectors, the greatest potential for short- term methane abatement by 2030 is within the energy sector. Oil and gas sector can rise to the challenge Energy usage in industrial, domestic and transportation is responsible for an overwhelming proportion of greenhouse gas emissions. The oil and gas sector is fundamentally an energy business, and it will therefore be integral to the transformation to climate neutral energy vectors and efforts to minimise the impact of fossil fuel usage. Conversion of natural gas to blue hydrogen and low carbon ammonia or methanol is one value chain that the midstream and downstream sectors are in pole position to lead. But methane emissions must ruthlessly be eliminated. Additionally, CO 2 released with methane from the reservoir and CO 2 generated from the energy requirements of gas processing and liquefaction must also be mitigated. Blue hydrogen relies on capturing the CO 2 that is released from the reforming process chemistry and capturing the post-combustion CO 2 emissions from the fired burner that is used to generate the heat energy, which is required to drive the reforming reactions forwards towards hydrogen production. Whether the CO 2 is then utilised or sent for permanent underground storage or mineralisation is of secondary importance – the first stage of the process relies on carbon capture. There may be latent concerns about classical CCS with underground CO 2 storage, but the idea of CCS as 'Carbon Capture and Something' begins to turn the focus towards capturing the carbon, thus leaving the next steps open. At the very least that approach may get some traction behind carbon capture, whilst the debate about the long- term storage mechanism can take place in parallel to constructive action. Displacement of coal fired power generation with pipeline natural gas or LNG is another area where the midstream sector will most likely be busy for the coming decades. LNG can connect energy producers and consumers. Through its transportability it creates international inter-

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Ten transformational policy proposals and discussion points for COP26  Clean up existing processes in parallel to developing the new clean energy infrastructure. As priorities, support investment in reduction of leaks and emissions of natural gas and other methane sources such as landfill sites.  Implement carbon capture on existing CO 2 point sources with a projected operational life of more than 15 years.  Place more emphasis and urgency on CO 2 capture, collection, and logistics infrastructure and business model development.  Tax ‘the problem’ with an international CO 2 emissions tax at a fixed rate, with a clear implementation and ramp-up timeline would be the fairest mechanism, which would also allow for clear planning and investment.  Use funds derived from national and international taxation to support transformational research, such as the use of direct air capture for the simultaneous capture of CO 2 and methane from the air.  Implement a review of practices in agriculture and the food supply chain and stimulate the necessary research into new techniques.  Focus on tighter control of F-Gases production because release to atmosphere is difficult to monitor due to the diverse range of domestic applications.  At a policy level, shift the debate away from picking between apparently competing good ideas, e.g. battery electric vehicle (BEV) vs fuel cell electric vehicle (FCEV) or green hydrogen vs blue hydrogen.  Motivate with a combination of hope and urgency. Current climate conditions indicate that the 1.5°C and perhaps 2°C targets will be overshot and the timeline for climate neutrality is variable around the world. COP26 must maintain the focus on achieving alignment to tougher targets and rapid action.  Visionary, blame-free collective international action is required and COP26 programmes must recognise this.

resources to produce hydrogen through in-situ gasification. This technology has the potential to be commercialised internationally due to the large volumes of oil resources globally. Instead of extracting crude oil from the underground fossil energy resources, in-situ gasification in the underground fossil fuel reservoir can be applied to create low carbon hydrogen. To produce pure hydrogen, gas separation is achieved by installing a downhole membrane. Hydrogen is extracted from the production well, and since the carbon monoxide and CO 2 gases and other hydrocarbons remain underground, the process simultaneously results in underground CO 2 storage. Carbon capture is at the root of all CCS or CCUS technologies During glass, lime, cement, and refractory products making, CO 2 emissions are unavoidable. This is

seasonal changes in energy supply and demand. Underground hydrogen storage, or UHS, is ideal for this application. Currently, two UHS pilots are planned in Germany and the Netherlands in 2021-2022. The North Sea and its nearby onshore region could also be an attractive choice for energy system integration, where CO 2 could be injected into oil and gas reservoirs and aquifers to generate blue hydrogen from local natural gas resources. Offshore wind power generation is being installed at Giga Watt scale, enabling green hydrogen production. The green and blue hydrogen can be stored in multiple UHS salt caverns, thereby fully harnessing natural resources above and below the ground in the region. The North Sea Energy programme and the Zero Carbon Humber project are planning to use this region capability for a sustainable energy system. It is possible to use underground hydrocarbon

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CO lean ue gas

CO rich ue gas

CO lean ue gas

CO lean amine

20% NaOH (aq)

CO lean methanol

CO lean solvent

CO rich ue gas

CO lean ue gas

CO rich solvent

CO rich methanol

NaCO (aq)

CO rich amine

Amine-wash rotating disk contactor

Amine-wash with tower contactor

Methanol wash

Mineralisation

A selection of CO 2 capture processes based on absorption

because the sands and minerals used contain CO 2 , which is released during the melting and calcination processes. These mineral processing industries must live with the fact that this geogenic CO 2 is generated, even if heating from renewable electrical power or hydrogen is used to replace fossil fuel fired burners. However, there are many things that can be done to mitigate CO 2 emissions to the atmosphere. Decarbonisation may be ‘difficult’, but it will be possible. Due to the geogenic CO 2 emissions, part of the decarbonisation solution in glass making and other mineral processing industries must therefore include ‘carbon capture’. Disposal of the captured CO 2 in underground reservoirs may become an important service and new business model for the oil and gas sector. CCS schemes that they operate can become the CO 2 sink for these industrial CO 2 emitters. Refinery steam methane reformers (SMRs) consume natural gas to make hydrogen. The vast majority make grey hydrogen and emit CO 2 . In the long term, this can be mitigated with ‘green’ hydrogen production using electrolysers fed with renewable electricity or reformers fed with biogas. In the short term, retrofitting carbon capture to SMRs to make so-called ‘blue hydrogen’ will make a step change reduction to CO 2 emissions and take a big step towards carbon neutrality. SMRs are used to produce more than half of the world’s hydrogen today. ATRs are also used extensively for syngas production. They tend to operate at a slightly higher pressure and the product is richer in carbon monoxide than the gases produced on an SMR. Fine-tuning of blue hydrogen production technology will, in part, come from a detailed understanding of the energy

and chemical feedstocks required in any scheme. Both SMRs and ATRs can be combined with downstream shift reactors to optimise production of hydrogen or syngas. The H 2 H Saltend project is focused on producing hydrogen for industry, power, and ammonia. The major advantage of using an ATR would be the scale that can be achieved, with a high carbon capture rate and high energy efficiency. Operating pressure, and therefore product gas delivery pressure, is another aspect that differentiates SMRs and ATRs. The ATR can operate at a higher pressure, which is a benefit if hydrogen must be injected into a high-pressure gas pipeline for transmission to cities in Yorkshire and beyond. Turquoise hydrogen, biochar & solid carbon Turquoise hydrogen is produced by methane pyrolysis (also known as methane splitting or cracking) and is another pathway to produce low carbon hydrogen. Methane pyrolysis is endothermic, meaning that it requires heat energy to convert methane to hydrogen and solid carbon. There are different options for the heat supply. Indirect heating using burners fuelled by hydrogen or natural gas as a fuel is one option. Indirect electrical heating or direct heating with an electrical plasma are also possible. A question that arises from methane pyrolysis with hydrogen as the target is: what happens with the various forms of solid carbon that are produced? If turquoise hydrogen production becomes a mainstream pathway to hydrogen, the amount of solid carbon produced will greatly exceed demand from current applications. If carbon black becomes abundant at low cost, it

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Nitrogen

Flue gas to FGD/SCR/CCS as required

Superheated steam

Heater

Air separation unit

Air

High pressure steam

Oxygen

Natural gas + hydrogen

Fired heater

ATR

Dry syngas

Catalyst bed

Final cooling & separation

Raw syngas

Steam Fuel Air

Condensate

Waste heat boiler

Boiler feed water

ATR process flow sheet for syngas production

might find additional application as a soil improver in agriculture. The use of biochar and wood acid (produced in a sustainable way from gasification or pyrolysis of wood) as alternatives or supplements to conventional fertilizers in rice paddies is reported to reduce N 2 O emissions by more than 50%. As an additional benefit, methane emissions are reduced by more than 30%. Additional research in these areas and subsequent education and roll- out of such programmes to change agricultural practices is an area the international community can focus on at COP26 and other forums for climate change prevention. Direct air capture of CO 2 and methane CO 2 accumulation in the atmosphere has been through industrial and human activity. CO 2 removal is mainly through biological

photosynthesis in plants, where the CO 2 is converted to starchy hydrocarbons. Various mechanical direct air capture (DAC) processes have been developed to simulate the action of plants and remove CO 2 from the air. A DAC facility rated at 1 million tonnes of CO 2 capture per year does the equivalent work of 40 million trees. With such huge potential, it is no surprise that a massive amount of development activity has taken place to research, scale up, and commercialise these technologies in the past decade. One of the attractions of DAC is that CO 2 can be recovered close to where it is required for EOR. The use of DAC to remove CO 2 from the air can also be used to offset CO 2 emissions from certain aspects of oil and gas processing that are very difficult to decarbonise. For example, amine wash CO 2 recovery systems operate most cost-effectively at up to 96% of CO 2 removal from the flue gas. The

CO depleted air

Air

Gas flow channel Ferrocene electrode

CO depleted air

Air Air Air

CO depleted air

Air

Spray tower

Gas flow channel Quinone electrode

CO depleted air

Air

CO rich solution

Climeworks

Verdox

Carbyon

Carbon engineering

A selection of technologies for direct capture of CO 2 from air (DAC)

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generate steam for process heating in the food, brewing, sprits distillation, paper making and chemicals sectors. An HTIHP requires a heat sink at a temperature of between 60°C and 120°C to generate steam. Waste heat is widely available from many processes at these temperatures. From a sustainability perspective, HTIHPs are attractive for steam generation because they do not create CO 2 greenhouse gas emissions for boiler operation. This is because the combustion of fossil fuels is not required. However, the heat pump must be supplied with renewable electrical power for the full environmental benefits to be realised. The electrification of industrial processes will only be climate neutral if the power is generated using renewable technologies. Wind, solar, and hydro-electric power dominate here. Geothermal and biomass-based power generation are also relevant. So-called ‘green’ hydrogen can be produced through the electrolysis of water using renewable power. Reforming of biogas or gasification of biomass can also yield ‘green’ or renewable hydrogen. There is the possibility that renewable power generation in the future will far exceed the total level of electricity production today. Imagine that all existing power from all sources is produced by renewables, plus a similar amount of power is used to generate hydrogen, and an additional third of the total is used to drive CO 2 and methane reduction equipment. For example, DAC technology to reverse the damage of the past and return the air to sustainable levels of these greenhouse gases.

5(ish)% residual CO 2 emissions from ATR and CCS for blue hydrogen can be offset in some way (e.g. BECC or DAC). Furthermore, of great interest to the downstream sector, production of e-fuels could be a major application of CO 2 from DAC in the future. In the simplest case, captured CO 2 and hydrogen from an electrolyser are synthesised to methanol. Methanol acts as a hydrogen carrier and remains liquid under ambient pressure and temperature. Thus, the storage and transport of methanol is much easier and cheaper than liquid or compressed hydrogen distribution. Whilst several commercial DAC technologies for atmospheric CO 2 removal exist, there is not yet one that has been implemented for methane capture from the air. It would be a good idea to capture these gases in parallel, since a major energy consumer in the system is the power requirement to drive the fan that moves air through the equipment. Using this power once to remove both gases would perhaps be the most efficient way to reverse the historical damage that has been done from CO 2 and methane emissions. Electrification of industrial processes will play a leading role Heat pumps are common for space heating. They use ambient air or soil as a heat sink and produce heat at about 50°C, which is ideal for heating buildings. High temperature industrial heat pumps (HTIHPs) are based on a similar operating principle and have been recognised for their potential to

Vapour

Compressor

Fan

Evaporator

Heat from ambient air

Heat for warmth and hot water

Condensor

Refrigerant gas recirculates within the system

1kW of electrical power applied to the fan and compressor can yield between 3 and 5 times the amount of heat energy

Liquid and vapour

Liquid

Expansion valve

Heat pumps can generate warmth for space heating from ambient air, or higher temperatures for steam generation from waste process heat

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Hydrogen FCEV/FCEB

Hydrogen ad-mixing into natural gas pipeline

Synthetic fuels via Fischer Tropsch

Fuel cell

Wind

Desulphurisation of fossil fuels

Hydro power

Gas turbine

Upgrading biofuels

Hydrogen storage/ distribution

Electricity grid

Battery

Biomass

Methanol

Gasication

Invertor

Rectier

Ammonia

Other end use

Metals rening

Solar PV

Hydrogen electrolyser

Electrolysis can convert renewable electricity to hydrogen, which can be used as a low carbon energy vector, as a reducing agent for steel making or to synthesise e-fuels, methanol, and ammonia

Methane monitoring and emissions mitigation matters

landfill methane, which can be used as an energy vector or be converted to hydrogen using a reformer. F-Gases – low tonnage, high climate impact The Paris Agreement on climate change sets a framework for the control of greenhouse gas emissions. It has been a catalyst for many efforts related to decarbonisation. Interestingly, it does not explicitly mention CO 2 once. It also does not mention methane, N 2 O, nor fluorinated hydrocarbons (known as F-Gases), which are all potent greenhouse gases. However, in recognition of their potentially harmful impact, legislation has been implemented around the world to focus on the processing and use of F-Gases, such as Regulation (EU) No 517/2014. Refrigerant gases are used in the oil gas sector for process chilling and to support liquefaction of hydrocarbons. A transition to low GWP F-Gases or so-called ‘natural’ refrigerant gases such as CO 2 or ammonia in mechanical refrigeration cycles will be essential to ensure sustainable refining and gas processing operations.

According to the European Pollutant Release and Transfer Register (E-PRTR), refineries in Europe that reported data to the public domain emitted between circa 100 and 2000 tonnes of the greenhouse gas methane per facility in 2017. The E-PRTR also reveals that methane emissions from gas pipelines, terminals, processing stations, and offshore platforms are in the range of 100 to 1200 tonnes per year per facility. Natural gas leaks during extraction, storage, and transport are estimated to total in the order of 9 million tonnes per year in the USA alone. Natural gas is mostly methane, a greenhouse gas that traps 56 times more heat than carbon dioxide over a 20-year period. In addition to the greenhouse warming potential of these methane emissions and the lost opportunity to provide valuable energy to consumers, methane is a flammable gas and intensive leaks present a safety risk. So, for a host of reasons, methane emissions monitoring is a ‘must’. Elimination of methane emissions from landfill sites is also essential. Technologies exist to capture

Stephen B. Harrison sbh@sbh4.de

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Site emissions become a new metric for competitiveness

Sitesmust be competitively strong and lowemissions to be sustainable as these provide cashflow to support both investment and returns to investors

Alan Gelder Wood Mackenzie

Global oil demand growth is to stall then demand is to fall The energy transition is under way, with the global community increasingly focused on reducing greenhouse gas emissions. Recent policies, such as the EU’s Fit for 55 proposal, are increasingly focused on decarbonising key sectors of the economy, reducing the demand for refined products. Compared to Wood Mackenzie’s base case outlook, such proposals are a downside risk in the mid-2030s and beyond. In the near term, global oil demand is recovering from the pandemic and we are expecting global oil demand to exceed 2019 levels in Q3 2022. Despite 2017 being the peak in global sales of internal combustion engine passenger cars, growing global populations, rising urbanisation, and increasing economic activity continue to drive oil demand higher, with our energy transition scenario projecting oil demand to peak at near 108 million b/d in the mid-2030s. The outlook for the refining sector is one of muted recovery. Despite recent capacity rationalisation, new sources of supply outpace demand growth. Refinery utilisations and margins will improve, but not repeat recent highs. Once global oil demand has peaked, the refining sector faces sustained capacity rationalisation. The refining outlook is not totally bleak, as the demand for petrochemicals is expected to grow through to 2050, supporting greater integration as a way of capturing volume and value growth. The refining sector is challenged by the energy transition as demand for its traditional products is set to fall. Growth opportunities lie in petrochemicals and low carbon liquid fuels (either

biofuels or synthetic e-fuels), both of which are core competencies of refiners, who safely operate large-scale continuous chemical transformation processes. While evolving their product mix, refiners also need to decarbonise operations. Emissions reduction is key to achieve our net-zero ambitions Refining is an energy-intensive sector and its emissions account for around 3% of global energy sector CO 2 emissions. Around 80% of these refinery emissions are from fuel combustion to support chemical transformation and treating reactions. Emissions are very site specific, but in general the more sophisticated the refinery (as measured by Nelson Complexity), the higher the carbon emissions, as the greater the chemical transformation of low value products into transport fuels and petrochemical feedstocks. Wood Mackenzie analysis shows refinery emissions are, however, poorly correlated with site profitability, as complexity is only one of the key drivers of site net cash margin. Location, scale, and crude diet are other key drivers of site profitability. At present, only Singapore and Europe impose a carbon charge on the emissions from their refiners. European refiners are exposed to a carbon charge of over €50 per tonne as of September 2021. This has a material adverse effect on their profitability as there are no similar charges imposed on imports of refined products from other regions, so they are currently unable to pass on those costs. European refiners do enjoy the benefit of free allowances to reflect the emissions of the most efficient process

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technologies. Despite this, Wood Mackenzie expects most of the 2021 recovery in gross refining margins has not made its way to the bottom line. The EU provides free allowances to mitigate the risk of carbon leakage. These are established by best-in-class technologies for the various refinery process units, reflecting the emissions of the top decile of facilities. The net result is that European refiners are exposed to significant additional carbon costs, which we anticipate to largely eradicate the positive margins of third and fourth quartile European sites for the next few years. An analogous situation exists for Asia, by which a carbon price of, say US$100/tonne in 2027, results in the carbon liability taking over 60% of cumulative refinery earnings, as shown in Figure 1 . The EU has considered, but not adopted, a carbon border adjustment mechanism for refining. The concept appears supportive of the European refining sector, as charging a tariff on imported middle distillates based only on the emissions of the export refinery and the transport delivery to Europe would lift the effective import parity price. Wood Mackenzie’s integrated analysis along the entire oil value chain suggests a more holistic perspective might offer no such protection, as shown in Figure 2 . When emissions are evaluated on a refinery gate forwards basis, European emissions for middle distillate production are below those of barrels delivered from Saudi Arabia, so a carbon border adjustment would raise the costs of Middle East volumes imported to Europe. However, if

120% 100%

80% 60% 40% 20% 0%

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2027 $30/t carbon

2027 $100/t carbon

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Carbon liabilty

% of renery earnings

Figure 1 Asian refinery carbon liability

the Scope 1 and 2 emissions associated with the crude production and delivery are included, the low upstream emissions for Russian and Saudi crude results in the emissions being broadly comparable. In such a framework, the carbon border adjustment would offer no protection to European refiners. Given this uncertainty, refiners need to establish a robust, commercially viable conversion platform that can adapt to the energy transition and not rely upon potential regulatory support. Significant investment is required to achieve site sustainability Wood Mackenzie believes refining’s role as a conversion business provides a long-term future, as decarbonising the world requires large volumes of low carbon liquid energy carriers as electrification is not a silver bullet across all

100

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Diesel

EU domestic production

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Saudi Arabia

Figure 2 Emissions for middle distillate imports to EU from major exporters

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REM-Chemicals - $2.15/bbl REM - $0.90/bbl

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Integrated renery petrochemical sites Standalone fuels reneries Rening only

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Figure 3 European Refining Competitive profile (2019, US$/bbl)

Portfolio rationalisation will be critical to focus investment on sustainable sites The falling demand for liquid fuels means not all refining sites will survive. Companies with multiple sites, such as the oil majors, have a portfolio to manage, with carbon emissions being a key metric to identify those that are sustainable for the coming decades, as shown in Figure 4 . The four quadrants reflect the relative position of sites reflecting their net cash margin position and their carbon emissions. The characterisation reflects Wood Mackenzie’s thesis that future sites need to be both competitively strong and low emissions to be sustainable as these provide cashflow to support both investment and returns to investors. Key actions are identified by quadrant. There are several sites in the ‘invest’ category – these are competitively weak but low emissions intensity. The challenge for owners is to establish whether a major expansion/upgrade can be commercially viable. This challenge is too much for those in the ‘divest/close’ category, as those sites are currently low margin and high emissions intensity and so they are likely to be converted to storage sites or liquid bio-facilities (following the examples from Eni and TotalEnergies). For those sites that are competitively strong, the requirement is to deliver low carbon operations through: • Fuel efficiency improvements and process electrification

sectors. Refining also has a key role in supporting the development of a circular economy through the chemical recycling of petrochemicals and conversion of municipal solid waste. The challenge facing the sector is that these technologies are still under development and so are not yet commercial, even at Europe’s current high carbon costs. Refiners need to be prepared to partner with others to pilot new technologies and approaches to deliver low carbon fuels. Government policies are critical to ensuring early-stage projects are nurtured and form the basis for future industry deployment at far larger scales. For this to be successful, these investments need to be made at a commercially viable conversion sites that are generating cash for both future investment plus providing a return to investors. Our REM-Chemicals research confirms that large integrated refinery/petrochemical sites dominate the first and second quartile competitive positions. These are the sites best placed to adapt to the challenge of the energy transition. Petrochemical integration has many benefits, including that the additional value from a major petrochemical investment significantly outweighs the additional costs of carbon emissions, given the synergies that are available between refineries and liquids-based steam cracking. Not all sites, however, can support such investments and so refiners need to consider their portfolio of site options.

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