Decarbonisation Technology August 2022 issue

August 2022 Decarbonisati n Technolo gy Powering the Transition to Sustainable Fuels & Energy

HYDROGEN: POTENTIAL SUPERFUEL?

HYDROGEN ECONOMY & CCS - UK CLUSTERS

THERMAL ENERGY STORAGE

BIO-FUELS & E-FUELS

HYDROGEN CARRIERS

ACCELERATING DECARBONISATION TOGETHER

The world’s energy system is changing. To solve the challenges those changes present, Shell Catalysts & Technologies is developing its Decarbonisation Solutions portfolio — to provide services and integrated value chains of technologies, designed to help industries navigate their path through the energy transition. Our experienced teams of consultants and engineers apply our diverse, unique owner-operator expertise to co-create pathways and technology solutions to address your specific Decarbonisation ambitions — creating a cleaner way forward together. Learn more at shell.com/decarbonisation

Decarbonisation Solutions

Contents

August 2022

Best practices in decarbonisation for LNG export facilities Peter Zhang Gulf LNG Solutions Saeid Mokhatab LNG Consultant

HyNet: a case study on industrial symbiosis Chris Manson-Whitton Progressive Energy

Teesside: the heartland of the UK’s energy transition Matt Williamson bp

Maximise renewable resources with thermal energy storage Raymond C Decorvet MAN Energy Solutions

Decarbonising through advances in heat exchange technology Gerald Marinitsch, David Moon and Lowy Gunnewiek Solex Thermal Science

Techno-economic metrics of carbon utilisation – Part 1 Joris Mertens, Mark Krawec and Ritik Attwal KBC (a Yokogawa company)

Biomass, BECCS and electrolysis for climate-neutral liquid fuels Stephen B. Harrison sbh4 Consulting

Energy transition technology scenarios Nick Flinn and Chris Egby Shell Catalysts & Technologies

Co-processing of bio-based feedstocks in the FCC unit Bob Riley, Stefan Brandt and Kenneth Bryden W. R. Grace & Co.

Power-to-X integration, the methanol case Raimon Marin AFRY

LOHC: H 2 delivery pathway for emerging hydrogen market Sebastien Lecarpentier, Arnaud Cotte and Stephanie Decoodt Axens

Choosing the ideal CO 2 drying solution for CCS applications Kirstie Thompson, Margaret (Peg) Greene and Manish Mehta BASF

Electric process heating – a call for standard specifications Craig Tiras Vulcanic EML

Holistic renewables investment is key to achieving net zero Jonathan Hicks Triple Point

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F ollowing on from the article ‘Delivering the Global Methane Pledge’ * in our May edition, we welcome announcements in July that three more companies, ConocoPhillips, Pioneer Natural Resources and Devon Energy, have joined OGMP 2.0. Another three companies, QatarEnergy, Wintershall DEA and Neptune Energy, have signed OGCI’s ‘Aiming for Zero Methane Emissions Initiative’. Our August edition illustrates the all-embracing nature of the energy transition with articles on two industrial clusters, HyNet North West and East Coast/Teesside, confirmed for ‘Track 1’ development with support from the UK Government. A third cluster, the “Scottish cluster”, was announced as a reserve. We plan to follow progress with all three clusters. Thermal energy storage can provide stable, long-term energy storage, overcoming issues with intermittency from renewable energy sources. In Denmark, an electro-thermal energy storage (ETES) system will be commissioned in 2023, which will buffer energy supply from offshore wind and tidal sources with energy demand in the form of sustainable electricity, heating, and cooling for the city of Esbjerg. Whilst the Esbjerg system uses water as the medium for energy storage, solid particles such as silica sand are a viable solution for thermal energy storage from concentrated solar power, as described in the article by Solex. Moving from Europe to Japan, KBC has conducted a techno- economic assessment on carbon capture and utilisation together with green hydrogen for producing renewable chemicals in the Goi industrial area in Tokyo Bay. The assessment uses pricing scenarios for green hydrogen over 30 years. They conclude that mandates or other form of support are required for the introduction of low carbon intensity products such as sustainable aviation fuels (SAF). The topic of sustainable fuels continues with articles on different phases in the transition. In the short term, technically mature, lower- cost routes using sustainable bio-based feedstocks will be deployed, but ultimately these are likely to be limited by feedstock availability. Thus e-fuels, currently at lower maturity and more costly, will be required in the longer term. In July, the European Parliament approved the Refuel EU regulation. This regulation will come into effect in January 2023 with mandates on the minimum levels of biofuels and e-fuels in aviation kerosene, starting at 2% (with 0.04% e-fuels) in 2025 and increasing to 85% (with 50% e-fuels) by 2050. Challenges in processing bio-feedstocks include their physical and chemical compatibility with conventional refinery streams, as discussed by Grace, as well as cost and logistical issues concerning the transport of bulky biomass over long distances. AFRY makes a clear case for co-locating renewable methanol production in pulp mills or bio-waste processing plants where there is a source of biogenic CO₂ and renewable electricity for green hydrogen production.

Managing Editor Rachel Storry rachel.storry@emap.com tel +44 (0)7786 136440

Consulting Editor Robin Nelson robin.nelson@ decarbonisationtechnology.com

Graphics Peter Harper

Digital Editorial Assistant Ciaran Nerval US Operations Mark Peters mark.peters@emap.com tel +1 832 656 5341

Business Development Director Paul Mason info@decarbonisationtechnology.com tel +44 844 5888 771

Managing Director Richard Watts richard.watts@emap.com

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

Cover Story Galp Sines Refinery, Portugal

Credit: Galp

* Please note that the article ‘Delivering the Global Methane Pledge’, published in Decarbonisation Technology May 2022, now includes some valuable feedback from Simon Blakely, Senior Advisor, S&P Global Commodities Insight. Please click HERE to read the feedback together with the full article. UPDATE

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Best practices in decarbonisation for LNG export facilities Reducing emissions from LNG plants can be technically feasible and economically viable as well as environmentally desirable

Peter Zhang Gulf LNG Solutions Saeid Mokhatab LNG Consultant

R ecently, all business organisations have been under greater pressure from both the public and investors to manage their operations associated with reducing carbon footprints. As the US liquefied natural gas (LNG) market continues to grow due to globally increased demand for cleaner energy, reducing greenhouse gas (GHG) emissions from each stage of the LNG value chain has become particularly important to LNG project developers and facility owners. Carbon dioxide (CO₂) emissions associated with the liquefaction process account for approximately 6 to 10% of overall GHG emissions of the entire LNG value chain. Decarbonising current LNG export facilities is a difficult challenge for facility owners. Not only do they need to justify the increased cost associated with deploying various decarbonisation options, but they also must find those options that have demonstrated unmitigated success and can meet owners’ unique decarbonisation goals.

This article reviews some of the best practices in addressing decarbonisation for LNG export facilities from an engineering design point of view. Not all LNG projects are designed equally and with the same level of emissions. As a result, the authors believe there are opportunities for LNG facility owners to address the unique decarbonisation issues associated with their existing facilities, and for LNG project developers to do it right in the first place during the development of new projects. Process overview of LNG export facilities An LNG export facility (see Figure 1 ) is typically comprised of natural gas treating facilities, one or more liquefaction trains, LNG storage tanks, one or more LNG ship-loading facilities, as well as supporting infrastructure and utilities. In the natural gas liquefaction plant, LNG is produced from a cryogenic liquefaction process where natural gas (mainly methane) is cooled down to approximately -160 o C (-256 o F) at 103 kPa (15 psi)

Natural gas pipeline

LNG storage tanks

Ship loading facilities

Natural gas pretreatment facilities

Natural gas liquefaction trains

LNG ship

Figure 1 LNG export facility

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Sulphur recovery/ thermal oxidiser

Nitrogen rejection

Nitrogen vent to ATM

Fuel gas

Water/ mercaptans removal

Mercury removal

Nitrogen rich gas

Acid gas removal

Raw natural gas

End ash Nitrogen removal

N GL recovery

LNG to storage

Liquefaction

Inlet separation

NGLs to storage

Water

Condensate

Figure 2 Typical LNG production process flow

to liquefy it for easy storage and transportation. The LNG production process flow is as follows: natural gas from raw gas transmission pipelines, typically at relatively high pressure, is fed to the LNG plant (see Figure 2 ), where it first goes through a series of processing steps to remove the undesirable components. These include heavy hydrocarbon liquids (condensate), free water, acid gases (carbon dioxide and hydrogen sulphide), water vapour, mercaptans, mercury, and other hydrocarbons heavier than methane called natural gas liquids (NGLs) contained in the natural gas feed stream, to prevent freezing issues in the cryogenic process, and to meet final LNG product specifications. Nitrogen, a potential natural gas contaminant, will be removed in the later cryogenic process through fractionation or fuel gas purge. After the NGLs are removed, the residual natural gas stream gets liquefied (using an external refrigeration system) and then sent to the end-flash nitrogen removal unit to meet the required specification to improve its calorific value and to avoid storage problems. The flash gas stream from nitrogen removal unit can be used as fuel gas. However, to meet fuel gas requirements, excess nitrogen needs to be rejected from this flash gas stream. Emission sources in LNG export facilities To understand the decarbonisation options in an LNG export facility, one must first locate the main GHG emission sources. There are primarily two major GHG emission sources in an LNG plant facility. One is CO₂ and methane contained in the feed gas, and the other is the flue gas produced from fuel gas combustion devices, such as gas turbines, thermal oxidiser, and other process fired heaters.

CO₂ in the feed gas is typically removed by amine absorption during feed gas treatment in the CO₂ absorber in the acid gas removal unit (AGRU). The off-gas from the amine regeneration column, which typically contains CO₂ and a small amount of hydrogen sulphide (H₂S) and other light hydrocarbons, is sent to a thermal oxidiser to destroy the hydrocarbons and other hazardous components by combustion or oxidation. The thermal oxidiser is often operated with some augmented fuel gas due to the low heat value of CO₂ off-gas from the AGRU. The flue gas from the oxidiser mainly contains nitrogen, unreacted oxygen, CO₂, water vapour, nitrogen oxides (NOx), sulphur oxides (SOx), and tiny amounts of uncombusted hydrocarbons depending on the combustion efficiency of the burner. These components can be vented to the atmosphere (to the extent allowed by local regulations) at a safe location. Alternatively, a carbon capture unit for CO₂ recovery can be added if needed. The amount of flue gas produced from a gas turbine is proportional to its fuel gas consumption, which in turn is a function of the duty required (or power output), fuel gas composition, and thermal efficiency. In addition, there are other emission sources in an LNG export facility. They can be intermittent or continuous and together can sometimes make significant contributions to the overall annual emissions of an LNG facility. Those emission sources include fugitive leaks from process equipment/turbomachines, piping and valves, vents from pressure control, compressor seals, emergency relief (flaring), and venting during commissioning, start-up, maintenance, and shutdowns. They may also include fuel gas purge for nitrogen removal (usually flared), nitrogen-rich

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venting from the nitrogen rejection unit, boil-off gas venting when boil-off gas compressor is down (usually flared), and ballasting vents during LNG storing and ship loading/unloading (also normally flared). Methane is a far more potent GHG than CO₂, so flaring those emissions (rather than venting them) can reduce their impact by a factor of 35 or more. Means to decarbonise LNG export facilities While decarbonising an LNG export facility is a challenge, various efforts have been taken in the LNG sector to reduce emissions, which basically can be divided into the three following categories: Elimination This category represents the choice of energy forms that power an LNG facility which can eliminate GHG emissions. Due to a proportional relationship between fossil energy or fossil fuel usage and GHG emissions, using a non-fossil fuel energy source will be the ultimate solution to achieve zero emissions. This includes using electrical motors based on electricity generated from renewable energy sources for refrigerant compressors. While partial substitution of fossil fuel by non-fossil fuel is possible for an LNG facility, with current technologies and energy mix, completely substituting fossil fuel is unlikely. It is particularly challenging for those existing LNG facilities that have already installed gas turbines for their refrigerant compressors. Mitigation On the basis of utilising fossil fuel energy, decarbonisation means reducing emissions from fuel gas combustion or methane leaks from piping and instrument leaks. This category includes improving energy efficiency through process design and equipment modifications. This includes utilising more energy-efficient equipment and advanced technologies associated with minimising emissions. It should be noted that, even if all of these mitigation methods are applied, not all GHG emissions associated with operating the facility may be eliminated. Sequestration The amount of CO₂ in the feed gas and the turbine exhaust gas will be released into the atmosphere if it is not captured and

stored. Carbon capture and sequestration (CCS) is considered a must-deploy technology to achieve net-zero emissions by 2050. CCS for LNG plants includes efforts that utilise commercially available CCS technologies to capture and sequester CO₂ emissions, mainly from the AGRU and the gas turbine exhaust. Examples of decarbonisation practices:  Improvement of energy efficiency The energy efficiency for an LNG plant is generally defined as energy input or requirement to produce a unit mass of LNG, such as kWh/kg or kWh per metric ton (MT). Each metric ton of LNG produced is estimated to require approximately 170 to 350 kWh of energy. In the absence of utilising renewable power from the grid, about 8 to 12% of feed gas is needed to produce power to run an LNG plant (including the fuel gas needed for gas turbines that drive refrigerant compressors). This is equivalent to GHG emissions of approximately 0.16 tCO₂e/tLNG to 0.48 tCO₂e/tLNG. For given feed gas conditions (such as pressure, temperature, and compositions), site conditions, and liquefaction technology selected, those values are strongly dependent on the type of drivers used for refrigeration compressors and the level of energy and heat integration. Driver type Efficiency of drivers varies with type. Heavy-duty frame turbines typically have an energy efficiency of 33 to 35%. For aero- derivative turbines, the energy efficiency ranges from 41 to 44%. The energy efficiency of a combined cycle gas turbine (CCGT) can run up to an energy efficiency of 60%. Recently, electrical motors with zero emissions (if the electricity is from a renewable source) have increased interest. Electric drive has been proposed for new LNG facilities that are geographically located where it is feasible to use renewable power from the grid. Heat recovery and integration For LNG plants that use gas turbines, recovering heat from turbine exhaust gas has become a standard design. The recovered waste heat can be used as a heat source for process use, such as providing heat for molecular sieve dehydration regeneration gas and heating medium. This can

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eliminate the use of dedicated fired heaters, which means no fuel gas consumption and no emissions for these necessary utilities. Energy recovery In several areas of an LNG plant, high-pressure fluids are sometimes let down to lower pressure for process reasons. For instance, in the feed gas circuit, the high pressure of feed gas is often let down to a lower pressure as required for NGL recovery. And in the rich amine circuit, the high-pressure, rich amine stream exiting from the bottom of a high- pressure amine absorber is typically let down to a lower pressure for amine flashing. In those instances, pressure letdowns are commonly realised by throttling valves. An alternative is to use turbine/expanders and turbochargers, respectively, to recover some of the lost energy. Note that the cost of equipment and maintenance of said equipment is not trivial and must be considered in the overall analysis.  Mitigation of emissions In addition to improvement in energy efficiency, there are other areas where decarbonisation opportunities exist in a liquefaction export facility. Many have been successfully practised in operating LNG facilities and are accepted as standard features, designs, or procedures. The following is a short list: Fugitive emissions prevention Prevention of hydrocarbon leaks from static equipment and turbomachines, piping connections and valves, plus associated safety and environmental regulation compliance are ongoing tasks of LNG facilities during design and operations. A good fugitive emission management programme should address quantifying and eliminating fugitive emissions in the first place, i.e., during the design phase. This includes compressor type selection (including seal type) and valve selection (i.e., low [external] leakage valves versus high leakage valves). Abnormal venting and emergency relief Emissions through venting/flaring during emergency shutdowns can sometimes be enormous. Implementing predictive maintenance programmes and improving equipment reliability can help prevent

unplanned shutdowns and thus reduce lifetime emissions from the facility. Overpressure protection Overpressure protection through relief and depressurisation systems in LNG process facilities is the standard means of protecting people, an owner’s assets, and the environment. However, in reviewing emission- mitigating methods for overpressure protection, atmospheric release (usually via flaring) and the associated negative environmental impact, as well as the potential lost revenue due to relief valve opening, must be addressed. It is common practice to consider solutions such as inherent safer design through high-integrated pressure protection systems (HIPPS) that can address both potentially hazardous emissions and the costly release while still providing overpressure protection. Commissioning and start-up Venting during process commissioning and start-up is unavoidable. However, emissions can be mitigated through proper planning and reviewing of commissioning and start-up procedures. For instance, utilising nitrogen for initial dry-out of mercury removal beds (placed downstream of the dehydration vessels) may have advantages over using fuel gas in minimising CO₂ emissions. Similarly, during AGRU commissioning, or turndown operation at start-up, the over- circulating lean amine may be unnecessary as it will increase the amount of dissolved hydrocarbons in the rich amine and potentially increase emissions, depending on the disposition of the flash gas.  Carbon capture and storage Chevron Australia’s Gorgon LNG facility installed the world’s largest CCS system to capture carbon emissions. After treatment, CO₂ captured from the AGRU in the feed gas pretreatment section of the LNG plant is injected into a giant sandstone formation about 2000 meters deep from the surface, where it remains permanently trapped.

Peter Zhang pzhang9898@gmail.com Saeid Mokhatab s.mokhatab@yahoo.com

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HyNet: a case study on industrial symbiosis

How a collaboration of over 30 organisations across different industries can work together to transition to a low-carbon economy

Chris Manson-Whitton Progressive Energy

H yNet is a project creating the transporting, and storing low-carbon hydrogen. HyNet is a decarbonisation cluster – a project designed to remove and reduce carbon dioxide (CO₂) emissions from a regional industrial hub that produces economic output and, subsequently, emits CO₂. HyNet and similar clusters across the UK connect companies that generate CO 2 and companies that can use low- carbon hydrogen to displace fossil fuel sources such as natural gas. HyNet is a case study on new industrial networks that together can transition to a low-carbon economy. infrastructure for carbon capture and storage (CCS) and producing, Background Progressive Energy was formed in 1998 to deliver hydrogen and CCS clusters and is the architect of HyNet. In this article, HyNet is used as a case study on how a collaboration of over 30 organisations across different industries can work together to deliver an outcome. A perspective on UK energy consumption Have you ever thought about how much energy

it takes to produce ordinary household tasks? As a consumer, the task of boiling a kettle, a menial element of a Briton’s day, uses on average 2-3 kWh of energy, roughly equivalent to someone climbing the stairs to the top of the Empire State Building! A household gas boiler uses 10 times that energy to provide heating and hot water. The production of energy can be taken for granted. From a national perspective, the UK is one of the world leaders in offshore wind. In 2021, it generated over 30 TWh of electricity from offshore wind, against the UK electricity demand of around 300 TWh. Beyond electricity, natural gas supplies around 600 TWh of our energy, while 800 TWh comes from petroleum products. Thus, while the UK is a world leader in offshore wind, 30 TWh is only 10% of our electricity consumption and just 2% of our total energy flows of 1740 TWh (see Figure 1 ). Rightly, the UK plans a massive expansion of offshore wind, but a five-fold expansion would still only make 10% of our total energy flow. So, the question is, how do we fill the gap? Progressive Energy believes we need renewable energy. For renewables to take a

Five-fold expansion by 2030

A major energy gap to ll – this needs a proper transition

Electricity Electricity Electricity Electricity

1740TWh

Misc Misc Misc

Natural gas Natural gas

Petroleum

10%

20%

30%

40%

50% 60%

70%

80%

90% 100%

Figure 1 Anchoring energy – the UK picture in 2021

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HyNet’s foundations HyNet was conceived around five years ago. The story starts with the demand from industry to contribute to the journey to net zero. Figure 3 shows the demand for the infrastructure that HyNet is building. Progressive Energy is working with major industrial organisations across the North West to support their switch across to low-carbon hydrogen or capture their carbon emissions. The driver for this change comes from both business-to-business and end-user consumers recognising that this is not just about decarbonisation but value creation, allowing them to differentiate themselves. The users of the Hynet infrastructure are given in Figure 3. Around three-quarters of partners and associated companies are looking to decarbonise by fuel switching to low-carbon hydrogen, with some also using the HyNet infrastructure to safely transport and store the CO₂ they produce. Key partners The location of HyNet gives access to the Liverpool Bay depleted gas fields owned by Eni. This represents a low-cost, low-risk site for CCS (see Figure 4 ). The gas field is serviced through an existing pipeline, originally used to transport the natural gas from the offshore field, which will be repurposed to deliver the CO₂ to the offshore CCS site, shown in orange in Figure 4 . The pipeline will be extended to reach the Ellesmere Port industrial zone, with Essar’s refinery located at the Stanlow Manufacturing Complex. Encirc, the largest bottling plant in the UK, will use locally produced hydrogen to power Encirc’s furnaces, reducing carbon emissions by more

1200

UK territorial emissions

1000

800

600

UK consumption emissions

400

200

Figure 2 UK greenhouse emissions (MtCO₂ eq/yr) 1990-2017

much greater share of the UK’s energy sector, a level of fossil resources will form an inevitable part of our energy system in the short term to transition successfully. And so, projects like HyNet must not only deliver renewable energy into the future but also capture the carbon emissions produced in the short term, targeting hard-to-abate sectors of the economy, such as heavy industry. The UK Climate Change Committee monitors the trend in UK greenhouse gas emissions and shows that over the last 25 years, emissions have fallen from around 800 million tonnes of CO₂ eq/ yr (0.8 GT) in 1990 to around 450 million tonnes by 2017. However, when the carbon embedded in imported products is factored in, our consumption emissions over the same period have held pretty constant at roughly 800 Mt/yr (see Figure 2 ). So how can the UK solve this? HyNet will use carbon capture, an almost 50-year-old solution for storing CO₂, then transport the CO₂ to the depleted oil and gas fields for permanent storage.

than 90%. This will enable the manufacture of billions of low- carbon glass bottles, create over 200 new jobs, and grow a skills base fit for the future to establish the region as the global centre of excellence for glass innovation. Hanson’s Padeswood cement plant produces CO₂ as an inherent part of the cement-making process. The HyNet infrastructure will safely transport and securely store 800,000 t/yr CO₂ from this facility.

Figure 3 HyNet demand led decarbonisation

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Initial p hases of Cadent ' s H pipeline Future phases of C adent’s H pipeline CO transportation and storage system Future CO pipeline connections

Liverpool

Manchester

Industrial CO capture

CO storage

Flint

Low carbon H production

Northwich

Underground H storage

Chester

H blending for homes and business

Industrial H user

H fuelling for transport

Flexible H power generation

H from oshore wind

Wrexham

CO shipping

H from solar and wind

Figure 4 Overview of HyNet

Next steps The HyNet project is now moving from the development to the delivery phase. The Vertex hydrogen production facility has already gone through front end engineering design (FEED), and planning permission has been submitted. The Cadent hydrogen distribution pipeline is already in FEED, and consultation is taking place. Inovyn has almost finished the FEED for the hydrogen storage, and soon 1.3 TWh of hydrogen storage will have gone through FEED and consenting. Eni is also at an advanced stage in its engineering and consenting process. HyNet will be able to store 10 MT CO₂ annually by 2030, while almost 50% of the region’s natural gas can be displaced by hydrogen. The project will create an estimated 6,000 new green jobs and help diversify the economy. This is an opportunity for economic redevelopment in the North West and Wales and could support 75,000 jobs. HyNet represents the UK’s first net- zero industrial cluster. The project will not only build on the region’s rich industrial heritage with an estimated economic impact of £17 billion for the North West and North Wales but also reduce the region’s carbon emissions by a quarter within five years. Chris Manson-Whitton chris.mw@progressive-energy.com

Fuel switching to hydrogen has been successfully trialled at Pilkington Glass, which created a world first by firing pure hydrogen in its flat-glass manufacturing process. Similarly, Unilever has successfully trialled hydrogen for generating the steam used in its Port Sunlight plant. Vertex Hydrogen is building a large-scale hydrogen production plant, using Johnson Matthey’s low-carbon hydrogen technology with a conversion efficiency from methane to hydrogen of 85% and a CO₂ capturing efficiency of 97%. The captured CO₂ will be sent via the pipeline for offshore storage. Cadent is building a 120km hydrogen distribution pipeline, which will be connected to the storage of hydrogen in underground salt caverns managed by Inovyn, to balance hydrogen supply and demand and give dispatchable power generation that can compensate for the intermittency of renewables, such as wind and solar power. In the longer term, there is potential for hydrogen to be added to the wider natural gas network as a means of decarbonising household gas supplies. HyNet establishes an infrastructure for all sources of hydrogen, encouraging investments in low-carbon hydrogen from electrolysis (green hydrogen) in this region (see Figure 4 ).

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Teesside: the heartland of the UK’s energy transition Teesside is perfectly placed to become a world-class, low-carbon energy hub and is an excellent test bed for bp’s hydrogen ambitions

Matt Williamson bp

B p is in the midst of a sweeping reimagining energy for people and our planet. And in doing so, we aim to reduce carbon emissions from our operations and production, and build new low-carbon businesses. We are committing significant resources to that transition – from an oil and gas company to an integrated energy company. We want to rapidly become a market leader in low-carbon energy by developing 20 GW of renewable power by 2025 and 50 GW by the end of the decade. Clean energy sources like wind, solar, and biofuels will play an important role. But hydrogen will also play a crucial role in bp’s transition. The transformation to help the world reach net zero. We are committed to our aim of industrial and commercial use of low-carbon hydrogen energy is still nascent, but its potential to help drive decarbonisation is massive. We think it will be a vital part of the energy transition, and we are not alone – according to the IEA, hydrogen could provide 10% of total global energy consumption by 2050. The bp Energy Outlook suggests that the share of low-carbon hydrogen could reach between 6% and 8% of total global energy consumption by 2050 in its “Accelerated” and “Net Zero” scenarios (bp, 2022), with total hydrogen demand – including that used to produce synthetic fuels and generate power – nearly double this. It is clear that hydrogen will play a vital role in helping to reduce carbon from the global economy. Yet it will be most important for carbon-intensive sectors where electrification will be difficult and, therefore, an unrealistic option. In heavy industry, for example, hydrogen can be used as a power source to decarbonise

high-temperature processes used in steel and cement production, refining, and petrochemicals. And in the transport sector, where ships and HGVs carry heavy loads for great distances, hydrogen and its derivatives have great potential as low-carbon fuels. The world is also coming together on hydrogen. The technology is advancing, our understanding is developing every day, and government support is building. This is why bp is aiming to capture 10% of the hydrogen market by 2030 in our core markets. One of those core markets is bp’s home, the UK, where we are committed to championing the development of a hydrogen ecosystem. We believe Teesside, in the North East of England, is perfectly positioned for the development of decarbonisation infrastructure. There are a number of reasons for this. First, the Teesside industrial cluster (see Figure 1 ) is in a tightly packed area with a radius of seven square kilometres, making it cost effective and efficient to decarbonise. The region is already a UK energy hub, with access to gas from the UK North Sea, helping ensure national energy security. Importantly, Teesside also has a rich industrial history and is home to five of the country’s 25 top emitters. It is the perfect test bed for industrial decarbonisation at scale. Blue hydrogen A key element of our vision is H2Teesside – a world-scale blue hydrogen project aiming to produce 1 GW of hydrogen, ramping up in two 500 MW phases in 2027 and 2030. It will produce hydrogen from natural gas, with up to 2 million tonnes of CO₂ emissions, which will be stored safely underground.

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Northern Endurance Partnership

East Coast Cluster

CCUS

1 GW Blue hydrogen

Green hydrogen

Figure 1 bp’s planned hydrogen projects on Teesside

Blue hydrogen will play a vital role in helping to decarbonise sectors where direct electrification is likely to be technologically very challenging or prohibitively expensive, such as steel production and long-distance shipping. It will also be vital in the scale-up and transition to hydrogen more broadly. Through H2Teesside, we have the opportunity to supply a diverse range of customers, including those already established in the region and new businesses attracted to this low-carbon hydrogen produced at scale. The CO₂ captured at H2Teesside will be transported and stored by the Northern Endurance Partnership, a joint venture whose partners include bp (who is also the operator), Equinor, Shell, TotalEnergies, and National Grid Ventures. Gas-fired power station with carbon capture Also using this infrastructure will be another bp-led project, Net Zero Teesside Power, which is aiming to be the world’s first commercial-scale gas-fired power station with carbon capture. This will be a large-scale 860 MW gas-fired power station. That is enough low-carbon electricity to provide power to 1.3 million homes, or 5% of all UK homes. It is also power that can be dialled up or down and switched on or off as needed. And it is power with a very big difference – it will be low carbon.

The plant is a joint venture between bp and Equinor, with bp as operator. A project of this nature has been discussed in the energy industry for decades, so it is incredibly exciting to see it finally in sight. A Development Consent Order has been submitted, and Front-End Engineering Design is underway. Together, H2Teesside and Net Zero Teesside Power will capture up to four million tonnes of CO₂ per year, roughly comparable to the emissions from heating two million homes. This CO₂ will be captured and piped 145 miles to be stored safely in the rocks beneath the North Sea via the Northern Endurance Partnership. Hydrogen through electrolysis of water We are also developing HyGreen Teesside, a green hydrogen project that uses a different technology – producing hydrogen through the electrolysis of water. In this process, electrolysis splits and separates the hydrogen from the oxygen molecules. And if the electricity used is from renewable sources, the hydrogen produced is known as green hydrogen – a zero-carbon fuel. HyGreen Teesside aims to be one of the UK’s largest green hydrogen production plants, ramping up over the next decade from 60 to 500 MW. This is a really important and strategic project for bp because we need to make advances in green hydrogen. We need to make it efficient and commercially viable.

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We also expect HyGreen to fuel the development of Teesside into the UK’s first major hydrogen transport hub, paving the way for large-scale decarbonisation of heavy transport, airports, ports, and rail in the UK. To put it into context, the project could provide enough low-carbon hydrogen to power over 10,000 heavy goods vehicles. The project has now entered the pre-FEED (front end engineering design) stage, which will run until early 2023, so we are on track for our delivery schedule and excited about the progress we have made so far. Together, we estimate that our two hydrogen projects in the region – H2Teesside and HyGreen Teesside – will deliver around 1.5 GW of energy by 2030, which is 15% of the UK government’s national target of 10 GW. But these projects are also significant from an international perspective. Hydrogen and CCS in Teesside can be a real showcase and a chance for the region to shine on the world stage. One early example is the interest and support we have received from international partners. We recently announced that ADNOC – the Abu Dhabi energy company – will take a 25% stake in the design stage of H2Teesside. ADNOC is a highly innovative energy company, a long-time partner of bp – and this is its first investment in the UK. And Masdar, the Abu Dhabi renewable energy company, has also signed a memorandum of understanding to acquire a stake in HyGreen Teesside. This is a great boost for the projects – a strong signal of confidence among investors – and good news for the region at the heart of the UK’s ambitions for building a hydrogen sector. But importantly, with these projects, the focus is not solely on global prestige and partners. It is about the people. To really succeed, these projects have to benefit local households and families. They need to create quality jobs that allow people to build their careers and lives in this region. Too often, industrial change brings about dislocation. It leaves communities without workplaces and leaves people without hope. This must not happen again. We need to have a just and fair transition to the low-carbon future. And this region will not only be a source of low-carbon energy – but good-quality, high-skilled jobs.

H2Teesside is estimated to create 1,200 construction jobs by 2027 and more than 600 operational jobs. We also expect Net Zero Teesside Power to provide 3,000 jobs in construction, peaking in 2024, and then 1,000 jobs annually to 2050. We will help train local people in the specialist skills required. That is why, for example, we are supporting and investing in the development of a Clean Energy Education Hub at Redcar & Cleveland College. This will train school leavers, apprentices, and adults in the skills needed for jobs in the kinds of facilities we are building, as well as in wind and solar farms. Our ambition for the region and hydrogen globally is bold, but we are not starting from scratch. We have vast experience gained from engineering, building, and operating some of the world’s most ambitious commercial energy projects. In fact, in the five years from 2016 to 2020, we constructed and launched over 25 major projects in partnership with more than ten national governments worldwide. And our expertise across the value chain and global network means we can offer a breadth of decarbonisation solutions, as highlighted by the diversified energy path we are taking to reach net zero by 2050. We are able to draw on decades of experience in producing and managing grey hydrogen at scale across our refineries. And we have a growing green and blue hydrogen portfolio around the world with a robust pipeline of future projects. Conclusion For hydrogen projects to be a success, we believe you need three key pillars – ample access to natural resources, a set of customers ready to begin decarbonising, and a supportive community and local government in the region in which you are operating. Teesside has all of these in abundance. It is perfectly placed to become a world-leading low-carbon energy hub. We believe it can be and we couldn’t be prouder to be playing our part in that journey.

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Matt Williamson matthew.williamson@se1.bp.com

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A new approach to energy management and storage, electro-thermal energy storage is bringing balance to some of the hardest to tackle clean energy challenges Maximise renewable resources with thermal energy storage

Raymond C Decorvet MAN Energy Solutions

O n the road to net zero, there are some pretty steep hills to climb. Hard-to- reach energy-intensive sectors, along with heating and cooling of existing building stocks, have hitherto resisted the siren call of sustainability. However, a new approach to energy storage and management now opens up even the toughest nut to clean energy. The breakthrough is centred on tried and tested technology, but its novel deployment offers a real opportunity for corporate, communities, and even whole cities to reach their net-zero ambitions. Sector coupling – in which heat demand is connected with sources of so-called ‘waste heat’ and demand for cooling – is a remarkably efficient approach to meeting system-wide energy consumption. In developing electro- thermal energy storage (ETES), MAN Energy Solutions has created a bulk energy storage system that links electricity, heating, and cooling in a high-efficiency reversible process. In a first for a major city, Esbjerg in Denmark is putting the ETES system at the heart of its plans to become entirely carbon-free by 2030. Reversible conversion of electricity into thermal energy The ETES storage system is built around a multi- stage radial turbo-compressor. Developed for highly efficient gas compression and proven in the harshest subsea environments, the HOFIM compressor allows the reversible conversion of electricity into thermal energy stored in simple and scalable insulated water tanks. Incredibly robust, oil-free, and hermetically sealed, the high-speed motor-compressor runs

on magnetic bearings and uses environmentally safe and non-toxic CO₂ as the working fluid. This refrigerant (R744) is successively compressed or expanded in a closed cycle with the outputs of hot and chilled water or electricity as desired. Initially, the CO₂ is compressed to around 140 bar and 150°C. It then passes through a heat exchanger and the hot store. The hot side may include up to four storage tanks at different temperatures or a direct supply to consumers. Once pressurised, the CO₂ is then expanded where it condenses and cools. A second heat exchange process uses the now liquid CO₂ to produce ice or cold water for the cold storage tank. To reverse the process and produce electricity, gaseous CO₂ is passed through the cold side heat exchangers, where it condenses while raising the temperature of the cold tank water. Once liquefied, the CO₂ is passed through the compressor, where the pressure is increased. It then goes through the hot side heat exchangers, increasing the temperature and pressure still further. Heated and pressurised, the CO₂ passes through an expansion turbine. A coupled conventional generator produces electricity. The current round-trip efficiency of ETES is 45%, but continued development is expected to see around 60% achievable in the near future. However, unlike chemical batteries, which degrade during each charge and discharge cycle and have a lifespan of only 10-12 years, the impressive efficiency figures from the ETES system remain constant throughout its more than 35-year design life. ETES and the carbon-neutral city Simple, reliable, and efficient, the tried and

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tested turbo-compressor with integrated expander at the heart of ETES is comparable to a conventional domestic fridge but represents a real advance in city-scale energy system management. Furthermore, while the ETES process not only allows heating and cooling to be distributed according to demand – as well as the option of converting this resource back into electricity – the process can be powered by renewable electricity such as wind or solar. This raises the possibility of using renewables and other carbon-free energy sources to provide the heat needed for previously tough- to-reach sectors. Recognising the advantages of this integrated energy management approach, DIN Forsyning – the Danish multi-utility company that operates the district heating network in the port city of Esbjerg, nearby Varde and part of the island of Fanø – is installing two large-scale ETES heat pump units. Using renewable electricity for heat was one of the big selling points for the ETES approach. “What we see from the major global trend is that renewable electrical power will be the basis of the whole energy system in some way. We see ETES as part of a transition,” said Claus Nielsen, Business Development Director at DIN Forsyning. “If we are to bring more renewable energy into the district energy system in Esbjerg then we have to find a smart way to integrate the network with the electricity system. The best method we have seen is the electrically driven heat pump,” he added. MAN Energy Solutions is developing a two- unit heat pump for the city with a total capacity of more than 50 MWth and is supplying the entire system, including the heat exchangers and all the associated electrical infrastructure. The turnkey project will supply around 235,000 MWh of heat annually and will largely replace an existing coal-fired thermal plant scheduled for decommissioning in 2023. Once completed in April 2023, the ETES project will form the backbone of a network of smaller and more sustainable heat sources for the city as part of its plans to become carbon neutral by 2030. It will be the largest CO₂-based heat-pump plant deployed to date. Energy to power the system will be supplied from nearby wind farms. However, as any heat

source can be recovered as usable energy through the ETES system, the Bay of Ho (Ho Bugt) in the Wadden Sea, a UNESCO World Heritage Site, will be employed as an energy resource. Nielsen explained: “Because we are close to the coast, we have a big heat sink. It’s at a low temperature, but it’s stable, and with eight million cubic metres of new water each tide, there is a huge and stable heat source accessible from the ocean.” The ETES system will extract heat energy from the bay by fractionally cooling the water. This heat will then be supplied to 100,000 of the city’s residents connected to the network as well as the company’s commercial and industrial customers. DIN Forsyning currently delivers around 1 million MWh to its district heating network. System-wide benefits of flexibility While the ETES system enables the use of renewable energy in normally unreachable heating and cooling applications, it also offers a number of associated benefits. The flexibility ETES provides allows energy to be stored or delivered depending on supply and demand. For example, when demand for electricity is high, ETES can convert energy in the heat store into usable power. When there is excess renewable generation, this can be stored as heat and cold. Furthermore, along with the energy storage capacity provided by the ETES, the district heating system itself can also act as a significant energy store. Additional capacity, and thus flexibility, can be achieved by temporarily adjusting the energy flows into the network to free up extra energy for other purposes, for instance as electricity. Nielsen explained: “The thing about a heating system is that a heat network is much better prepared for variability than the electricity system. The electricity system has to balance consumption and production at all times. With the heat system in Esbjerg, we can have up to 10 hours without any inputs and still meet demand using r esidual heat in the network, accumulated heat and moving around consumption at the consumer end. Even on the coldest day, we can supply heat to all customers for seven hours without any production.”

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