Professor Dawid Hanak

Delivering net zero transition

Category: Carbon capture and use

  • CO2 transport and storage: the real CCUS bottleneck

    CCUS context

    The UK has committed a sizeable budget to carbon capture. In October 2024, the Government set out up to £21.7 billion over 25 years for the first two clusters, the East Coast Cluster and HyNet, and in December 2024, the Northern Endurance Partnership reached financial close on the country’s first CO2 transport and storage network. Construction on Teesside is now underway.

    Most of the public argument about CCUS is still about the capture plant: which solvent, what capture rate, and how high the cost per tonne. If you are deciding whether a UK capture project will actually be built, and when, that is the wrong thing to watch.

    The binding constraint is neither the capture technology nor the cost of capture. It is the shared CO2 transport and sequestration network, and the contractual chain wrapped around it. Capture is the mature part. The pipeline, the store, and counterparty risk among emitters determine delivery. Three dependencies, set out below in order of how binding they are, explain why.

    The CO2 transport and storage network has to exist before a CO2 capture plant is worth anything

    A capture plant with nowhere to send its CO2 is a stranded asset. That sentence sounds obvious, and it is exactly the point that is often skipped in discussions of current technology.

    Post-combustion amine capture is not the difficult part here. It is a mature technology, deployed at commercial scale, sitting at the top of the technology readiness scale. You can buy it. What you cannot buy off the shelf is a route to a permanent store. On the East Coast Cluster, that route is a 145 km offshore pipeline to the Endurance saline aquifer, roughly 1,000 metres below the seabed, plus the onshore gathering and compression to feed it.

    Map of the East Coast Cluster showing pipelines for CO2 transport and storage project from Teesside and Humber to offshore storage and associated projects

    Shared transport and storage have an awkward economic shape. It is capital-heavy and has to be built ahead of the demand that justifies it. Moreover, it must be sized larger than any single emitter requires, so that future emitters can connect. No individual capture project can carry that cost, and no individual project will build a pipeline and a subsea store on the chance that others follow. This is a textbook coordination problem, and an unsupported market does not solve it on its own.

    There is also a timing mismatch on top of the cost. The network spends its capital years before the emitters that connect later contribute any revenue, so the early years are deliberately underutilised by design. Someone has to fund that gap and carry the risk that the later emitters never arrive. A merchant developer cannot price that exposure into a single project, which is precisely why it falls to a regulated structure rather than to the market.

    That is why the Northern Endurance Partnership needed a government-backed, regulated revenue model to reach financial close at all. The honest implication for any single capture project is uncomfortable: your timeline is hostage to infrastructure you do not own and cannot control. The capture plant is a procurement decision. The network it depends on is not.

    The real bankability question is counterparty risk, not capture risk

    The second dependency is contractual, and it is where most business cases are quietly optimistic.

    In a cluster, every emitter’s economics depend on every other emitter and on the transport and storage operator, all of which must perform as planned. The CO2 has to flow, the store has to accept it, and the shared cost has to be spread across a connected set of projects. That interface is the real risk, and it has very little to do with whether the capture technology works.

    The UK business model architecture is built specifically to allocate that risk. The Industrial Carbon Capture contract is a contract for difference, with a 15-year term and a strike price set to cover both capital and operating costs, negotiated bilaterally for the first projects before any move to competitive allocation. The transport and storage network sits on its own regulated model. The November 2025 update to the business models exists because these interfaces are genuinely hard to paper over.

    Here is the part that does not show up in a single project’s spreadsheet. If one anchor emitter slips, the shared infrastructure’s unit economics move for everyone connected to it, because the fixed cost of the network is now spread across less volume. That is why the network’s revenue cannot sensibly be tied to the tonnes that happen to flow in a given year. It has to be underpinned by availability, so the operator is paid for standing ready rather than only for what passes through the pipe, with volume risk deliberately pushed elsewhere in the chain. The question that follows is who holds it, and on what terms.

    That cross-chain exposure is the real question of bankability. It is also why the first clusters could not be financed as ordinary merchant projects and instead needed bespoke, state-backed contracts.

    Once it is funded, delivery is gated by sequence and supply chain

    Suppose the network is committed and the contracts are signed. The third dependency is the least glamorous and, right now, the most active: getting it built.

    The East Coast Cluster is a useful gauge because it is public. By March 2026, its main contractors had awarded more than 230 sub-contracts worth £1.5 billion to UK suppliers, including around £500 million of new awards through competitive tender since the third quarter of 2025. The first major equipment for Net Zero Teesside Power arrived at Redcar Bulk Terminal in April 2026, with start-up expected in 2028.

    At this stage, the binding constraint is not whether amine capture works. It is engineering and construction capacity, skilled labour, equipment lead times, and the sequencing of a very large set of interdependent works. First-of-a-kind infrastructure carries real schedule risk, and schedule risk on a shared network is shared by everyone waiting to connect. None of that is a technology problem.

    A worked example

    Considering these dependencies for the East Coast Cluster confirms this pattern is clean. The network came first and needed de-risking: the Northern Endurance Partnership reached financial close in December 2024, not because the pipeline was technically novel but because someone had to underwrite the coordination problem. The contracts came next: the Industrial Carbon Capture model and the regulated transport and storage model allocate the interface risk between emitters and the network. Delivery came third: £1.5 billion of supply-chain contracts and a 2028 start-up date now turn on sequencing and EPC capacity. At no point in that chain is the capture technology the thing in doubt. This is the live UK case, and it is publicly documented.

    What this means for you

    For investors screening UK CCUS projects, the diligence order is the wrong way round in most decks I see. Capture readiness is the box that is easy to check and rarely fails. Spend your scrutiny on the transport and storage counterparty, the cross-chain default and curtailment terms, and the construction schedule. A confident capture-cost figure attached to a project with an uncertain route to store is an optimistic model, not a bankable one.

    For industry leaders in hard-to-abate sectors, your decarbonisation date is set by your cluster’s transport and storage availability, not by your capture vendor’s datasheet. If your site is not on a Track-1 or Track-2 cluster, that connection and its timing should be at the top of your plan, ahead of solvent selection.

    For policymakers, the £21.7 billion and the layered business models are doing the right job: de-risking a coordination problem the market cannot solve alone. The lesson the first clusters already teach is one of sequence. Build, or at least firmly commit, the transport and storage backbone ahead of the capture plants that depend on it. The infrastructure is the enabling constraint, so it has to lead.

    The conclusion

    A CO2 capture plant is a procurement decision. A CO2 transport and storage network is a coordination problem, and coordination problems determine whether clusters are actually built. The UK’s first two clusters did not reach financial close because the capture technology finally worked. They reached it because the state absorbed enough of the network and counterparty risk to make the chain bankable. That is the part worth watching as the next wave of projects comes forward.

    Bar chart showing CO2 capture cost ranges by industry and technology, varying from approximately €12 to €205 per tonne. Extracted from Prof Hanak's academic papers

    PS — the capture-cost ranges get all the attention. The IEA puts capture at roughly USD 15–25 per tonne of CO2 for concentrated streams such as gas processing, rising to USD 40–120 per tonne for dilute streams like cement and power. Yet a 2025 analysis by Agora Industry and the Öko-Institut put end-to-end costs in the EU at €105–280 per tonne. My team’s work has shown that the capture cost can fall between these ranges, depending on the host plant and CO2 capture cost. Notably, most of the gap between those numbers is in CO2 transport and storage infrastructure, as well as the system around CO2 capture, which is where the delivery risk lives. Capture is rarely where these projects are won or lost.

  • Is 2026 the Year Carbon Capture Scales Up? CCUS, DAC and Industrial Decarbonisation Explained

    Is 2026 the Year Carbon Capture Scales Up? CCUS, DAC and Industrial Decarbonisation Explained

    In 2026, Carbon Capture, Utilisation and Storage (CCUS) is transitioning from niche pilot demonstrations to system-scale deployment. Forty-two projects were operational globally by 2025 — a 25% year-on-year increase — flagship Direct Air Capture (DAC) facilities like Stratos are approaching the million-tonne annual scale, and European hubs are linking industrial emitters to offshore geological storage for the first time. However, high costs and policy dependency mean CCUS remains a complement to — not a replacement for — electrification and renewables, and is best targeted at hard-to-abate sectors where process emissions cannot be eliminated by switching energy carriers alone.

    About the author

    Professor Dawid Hanak is Professor in Decarbonisation of Industrial Clusters at the Net Zero Industry Innovation Centre, Teesside University. He is a Chartered Engineer (CEng MIMechE), Chartered Fellow of the Chartered Management Institute (CMgr FCMI), and Fellow of the Higher Education Academy (FHEA), with expertise spanning carbon capture, utilisation and storage (CCUS), direct air capture (DAC), techno-economic assessment (TEA), and life-cycle assessment (LCA) for energy-intensive industries and industrial clusters. He advises the UK Department for Energy Security and Net Zero (DESNZ) on CO₂ capture and carbon removal technologies, leads the EU COST Action TrANsMIT as UK representative and working group leader on CCUS techno-economic assessment, and has secured and delivered over £5 million in research and commercial funding across EPSRC, Innovate UK, and industry partners. Connect with him on LinkedIn or read more of his writing on Illuminem.

    Research support: If you or your organisation need support with techno‑economic assessment (TEA), life‑cycle assessment (LCA), or the development of robust net-zero strategies for industrial assets or clusters, I also work with partners on bespoke analysis and training. Book an initial consultation via my website: book.drhanak.com

    What Are CCUS, CCS and DAC? Core Terms Explained

    Before diving into the 2026 landscape, it is worth defining the key terms clearly, because they are often used interchangeably but refer to distinct things:

    • CCS (Carbon Capture and Storage) — the process of capturing CO₂ from industrial sources or the atmosphere and permanently storing it underground in geological formations such as saline aquifers or depleted oil and gas fields.
    • CCUS (Carbon Capture, Utilisation and Storage) — a broader term that includes CCS but also covers pathways where captured CO₂ is used rather than stored, for example in synthetic fuels, chemicals, or building materials. CCUS is now the more commonly used umbrella term in policy and industry.
    • DAC (Direct Air Capture) — a specific subset of carbon capture where CO₂ is extracted directly from ambient air rather than from a concentrated emission source such as a power plant or cement kiln. DAC can deliver genuine carbon removal but currently comes at significantly higher cost than point-source capture.
    • Hub-and-cluster model — an infrastructure approach in which multiple industrial emitters in a geographic cluster share a common CO₂ pipeline network and connect to a single offshore or onshore storage site. This distributes capital costs and de-risks individual projects. The UK’s East Coast Cluster (Teesside and Humber) and Northern Lights (Norway) are leading examples.
    • TEA (Techno-Economic Assessment) — a systems-level analytical method used to evaluate the technical performance and economic viability of a process or project, including capital costs, operating costs, and levelised cost per tonne of CO₂ avoided.
    • LCA (Life-Cycle Assessment) — an environmental accounting method that quantifies the full lifecycle emissions and resource impacts of a process or product, from raw material extraction through to end of life.
    • FID (Final Investment Decision) — the point at which a project’s owners formally commit the capital required to proceed to construction. Reaching FID is a key milestone that signals a project has secured financing and regulatory approvals.

    CCUS in 2026: Key Facts at a Glance

    • 42 CCUS projects were operational globally by end of 2025, representing a ~25% increase in capacity year-on-year.
    • 650+ projects are currently in development across power, cement, steel, hydrogen and DAC sectors worldwide.
    • Carbon Engineering’s Stratos plant (Texas, USA) is expected to capture up to 1 million tonnes of CO₂ per year when fully ramped up — the world’s largest DAC facility.
    • Capture costs for first-generation amine scrubbing in large industrial plants typically range from £50–100+ per tonne of CO₂, depending on plant size, fuel type and energy prices.
    • $30 billion+ in total global public financial support for CCUS and DAC has been committed via tax credits (including the US 45Q credit) and national incentive schemes.
    • 10 major European CCS initiatives reached Final Investment Decision (FID) in 2025, including full-chain projects linking industrial emitters to offshore geological storage.
    • Brevik cement plant (Norway) became the first cement plant in Europe to capture CO₂ at scale and send it offshore for permanent storage — demonstrating a complete CCS chain from process stack to subsea reservoir.
    • The European Energy Research Alliance (EERA CCS) describes 2026 as a “turning point” where CCS moves “from the margins to the mainstream”.

    Context

    In this edition, I wanted to look at a question that keeps coming up in discussions with industry partners, policymakers and fellow researchers: is 2026 finally the year when carbon capture moves from a collection of pilots to a serious, system‑scale decarbonisation tool? Across Europe and beyond, we are seeing a wave of projects reaching final investment decision, new hub‑style infrastructures being announced, and direct air capture projects pushing capacities that would have sounded unrealistic just a few years ago.

    From my perspective, we are clearly beyond the “niche demonstration” phase, but we are not yet in a world where CCUS is a mature, low‑risk option that every industrial emitter can simply plug into their net‑zero plan. The economy still depends heavily on policy support, infrastructure is uneven, and public acceptance remains fragile in some regions. There is no silver bullet here. CCUS can be a critical part of the portfolio, especially for hard‑to‑abate sectors and carbon removals, but only if we remain honest about costs, limitations and trade‑offs.

    Today, I would like to walk you through where CCUS actually stands in 2026, what is genuinely new compared to even two or three years ago, and what this means if you are an engineer, manager or policymaker trying to make real decisions rather than just repeat slogans. You get my point: this is not about perfection; it is about progress that is technically and economically defensible.

    Why Does Carbon Capture Matter in 2026?

    Let me start with the big picture. Across Europe, 2026 is being framed by many as the year in which carbon capture and storage (CCS) finally starts to scale in a visible way. The European Energy Research Alliance (EERA CCS) describes 2026 as a “turning point” where CCS is moving “from the margins to the mainstream”, building on a 2025 pipeline in which ten major initiatives reached final investment decision (FID), including full‑chain projects linking industrial emitters to offshore storage. This matters because it signals that we are no longer talking about isolated power‑plant retrofits, but about multi‑site, cross‑border infrastructure.

    At the same time, global CCUS market assessments show both progress and a large remaining gap. A recent H1 2026 market outlook notes that there were 42 CCUS projects operational in 2025, increasing capacity by about 25%, yet more than 650 projects are in various stages of development and the total deployed capacity is still far below what is needed for credible 1.5–2 °C pathways. This implies that while the project pipeline is impressive on paper, timely execution, permitting and financing will determine whether CCUS becomes material for climate targets or stays marginal.

    On the carbon removal side, 2026 is also a pivotal year. Carbon Engineering’s Stratos facility in Texas is expected to capture between 0.5 and 1 million tonnes of CO₂ per year when fully ramped up, making it the world’s largest direct air capture (DAC) plant, while other players like Climeworks continue to expand in Europe and the Middle East. From my perspective, these capacities are still small relative to global emissions, but they represent an important scaling step for DAC technologies that only a decade ago were mostly confined to academic papers and small pilots.

    Policy remains the main driver behind all this. In key markets such as the United States, the 45Q tax credit provides significant per‑tonne support for captured and stored CO₂, and recent analyses estimate that global public support for CCUS (including DAC) via tax credits and other incentives exceeds 30 billion dollars in total. In parallel, European initiatives, including national support schemes and cross‑border infrastructure frameworks, are pushing CCS hubs in the North Sea region and beyond. This poses both an opportunity and a challenge: projects look attractive as long as the policy environment is stable, but any regulatory U‑turn could quickly undermine investor confidence.

    How Does CCUS Work at Industrial Scale?

    When we talk about “CCUS scaling up”, it is easy to think only about capture units integrated into industrial facilities, but the real story in 2026 is about integrated systems. At a typical industrial site, post‑combustion capture using amine‑based solvents still dominates, with capture efficiencies of 85–95% technically achievable when process integration is carefully executed. Capture costs for first‑generation amine scrubbing in power and large industrial plants often fall in the range of 50–100 (or more) £/tonne of CO₂, depending on plant size, fuel, and energy prices, consistent with the ranges reported in recent industry outlooks and conference agendas. Yet for many brownfield sites, this remains the most mature option.

    However, capture is only the first piece. The emerging hub‑and‑cluster model, which is particularly relevant for regions such as Teesside, focuses on shared CO₂ transport and storage infrastructure that can serve multiple emitters. Industry analyses highlight that shared pipeline networks linking industrial clusters to saline aquifers or depleted hydrocarbon fields are becoming essential to make CCUS cost‑effective, because they distribute capital costs and utilisation risk across several projects. From my perspective, this is exactly where places like the UK’s East Coast Cluster and Northern Endurance Partnership are positioning themselves as backbone infrastructures rather than bespoke, single‑project solutions.

    Storage is also maturing. The Brevik cement plant in Norway, for example, became the first in Europe to capture CO₂ at scale and send it offshore for permanent storage, demonstrating a full CCS chain from process stack to subsea reservoir. Across Europe, a growing number of projects are following this model, with ten large initiatives reaching FID in 2025 alone. This shows that geological storage is no longer just a theoretical option but something that regulators, operators and communities are learning to manage in practice.

    On the utilisation side, progress is more uneven. Many pathways such as synthetic fuels, chemicals or mineralisation remain either niche or in early commercial stages, with techno‑economic analyses often showing limited mitigation potential at high cost unless they are carefully targeted at specific value chains. From my experience in process modelling and techno-economic assessments (TEA), this is where rigorous system‑level assessment is crucial. It is very easy to be seduced by a neat reaction pathway while overlooking energy penalties, upstream emissions, or market constraints that undermine the climate benefit.

    What Is New About CCUS in 2026?

    So, what makes 2026 different from 2018 or even 2022? First, the scale and diversity of projects. The CCUS Market Outlook H1 2026 stresses that 42 projects were already operational by 2025, with a 25% capacity increase year‑on‑year, while more than 650 are in development across power, cement, steel, hydrogen, and DAC. This suggests that investors are no longer treating CCUS as a one‑off experiment, but as a portfolio play with different technologies, regions and business models.

    Second, we see specific flagship projects reshaping expectations. Stratos in Texas, planned to capture up to 1 million tonnes of CO₂ annually from ambient air, exemplifies the move from tens of thousands of tonnes per year to the low‑million‑tonne scale in DAC. In parallel, European CCS hubs linked to projects such as Northern Lights and the North Sea storage complexes illustrate multi‑client, cross‑border value chains, with EERA CCS emphasising that 2026 is the year when these systems begin operating at meaningful scale. This is a step change compared to earlier single‑site demonstrations.

    Third, the policy narrative is maturing. While tax credits like 45Q remain central and are considered relatively resilient across different US administrations, discussions in 2026 explicitly highlight concerns about long‑term policy stability, regional differences in carbon pricing, and the need for predictable regulatory frameworks to justify multi‑billion‑currency investments in capture plants and pipelines. That is why I keep stressing to both companies and policymakers: CCUS deployment is not just an engineering challenge, it is a policy and market‑design challenge.

    Finally, criticism of CCUS is becoming more sophisticated. Commentaries now focus less on generic “greenwashing” claims and more on concrete issues: the risk that CCUS prolongs fossil fuel production, the uneven distribution of projects across regions, and the need for robust monitoring, reporting and verification of stored CO₂. From my perspective, this is healthy. Honest debate forces projects to demonstrate real climate additionality and not simply rely on policy incentives.

    Is CCUS Cost-Effective Compared to Renewables or Hydrogen?

    A question I hear a lot is: why invest in CCUS when we could “just” electrify, deploy renewables, or switch to hydrogen? The straightforward answer is that in many cases we should do those things first, but there remain sectors where process emissions cannot be eliminated simply by changing the energy carrier. Cement is the classic example. Around two‑thirds of its CO₂ emissions come from the calcination of limestone, which will occur regardless of whether the kiln is fired with gas, hydrogen or electricity. For such processes, capture at source becomes a necessary complement.

    If we look at costs, the picture is nuanced. Recent CCUS conference materials emphasise that high capital costs and substantial operating expenses mean that many large‑scale projects still rely on policy support and carbon pricing to be viable. By contrast, renewables such as utility‑scale solar and onshore wind have seen dramatic cost reductions over the last decade and can often compete without subsidies in favourable locations. This implies that for power generation and some forms of heat, renewables plus electrification will often be the more economical decarbonisation path, while CCUS is better reserved for genuinely hard‑to‑abate emissions and carbon removals.

    Comparing CCUS with hydrogen is also context‑dependent. Low‑carbon hydrogen produced from natural gas with CCS (so‑called “blue” hydrogen) can mitigate emissions significantly when capture rates are high and upstream methane leaks are well controlled, but the overall system still depends on fossil inputs and capture infrastructure. Green hydrogen from electrolysis powered by renewables avoids fossil fuels but currently comes at higher cost and requires large amounts of low‑carbon electricity. From my perspective, you get my point – there is no silver bullet. Each pathway can be optimal in specific settings, and rigorous techno‑economic assessment (TEA) and life‑cycle assessment (LCA) are essential to avoid unintended consequences.

    This is exactly where I see the role of research and tools like TEA and LCA. They allow us to quantify not only the levelised cost per tonne of CO₂ avoided, but also the broader impacts on energy systems, resource use, and local environments. Linking process models of capture units, pipelines and storage reservoirs with economic and environmental data is not glamorous, but it is precisely what we need to prioritise robust projects over fashionable ones.

    How Should Businesses and Policymakers Respond to CCUS in 2026?

    If you are an industrial operator, 2026 should not simply be the year you “wait and see” what happens with CCUS. Instead, it is the moment to map your emissions sources, understand which ones are realistically addressable via efficiency, fuel switching or electrification, and identify the residual fraction that might require capture or removals. The emerging hub model means that being in, or near, an industrial cluster like Teesside, the Humber, Rotterdam or the Gulf Coast could significantly change your option set and cost structure.

    For engineers and project developers, the key is to move beyond conceptual enthusiasm and into integrated design. That means considering capture systems, utilities, heat integration, CO₂ conditioning, and compression as part of a whole‑site optimisation, not as standalone add‑ons. It also means engaging early with potential transport and storage providers to understand pressure, purity and deliverability requirements. From my perspective, multidisciplinary collaboration between process engineers, geoscientists, economists and policy experts is no longer optional if we want viable projects.

    Policymakers and regulators, on the other hand, face a slightly different challenge. They must design frameworks that are generous enough to de‑risk first‑of‑a‑kind projects, yet predictable and stringent enough to avoid locking in underperforming assets. This involves aligning tax credits, carbon pricing, permitting and long‑term liability rules, while also considering international measures such as the EU’s Carbon Border Adjustment Mechanism, which may indirectly pressure trading partners to adopt CCUS or equivalent measures. It is not easy, but inconsistent or stop‑start policies are, in my view, the fastest way to undermine all the engineering work currently underway.

    Finally, for researchers and educators, 2026 is a reminder that our role is not limited to publishing papers. We need to translate complex models into insights that decision‑makers can use, help train the next generation of engineers and technicians for CCUS deployment, and remain honest about what we know and what we do not know. I believe that regions like Teesside, with their industrial legacy and emerging net‑zero ambitions, are uniquely positioned to be living laboratories for this transition, but only if we invest in skills and communication as much as in hardware.

    Will Carbon Capture Scale Up in 2026? Final Assessment

    So, is 2026 the year carbon capture finally scales up? From my perspective, it is the year when we move decisively from “if” to “how” and “where”. The number of projects, the scale of flagship facilities like Stratos, and the emergence of European storage hubs all indicate that CCUS is becoming a serious pillar of decarbonisation strategies, particularly for heavy industry and carbon removals. At the same time, the technology is not a get‑out‑of‑jail‑free card: costs are still high, policy risk is real, and CCUS must be deployed alongside, not instead of, aggressive electrification, renewables and demand‑side measures.

    I would encourage you to think about CCUS not as a monolithic solution, but as a family of tools that can be combined in different ways depending on your site, sector and time horizon. Some of you will find that CCUS is a central pillar of your strategy; others may conclude that it plays only a marginal role compared to efficiency and electrification. Both outcomes are fine, as long as they are grounded in robust analysis rather than wishful thinking or political slogans. Am I practising what I preach? In my own research and teaching, I am trying to make sure that we always link elegant models back to the messy reality of industrial sites and policy frameworks.

    What has been your experience so far with CCUS discussions in your organisation or region? Do you see it as a realistic option for your assets, or is it still perceived as too costly or too complex compared to other pathways? I would genuinely love to hear your perspective, especially any concrete numbers or lessons learned from feasibility studies or pilots you have been involved in. Your insights could help guide and inspire others — and I would love to feature them in future editions of this newsletter.

    Research support: If you or your organisation need support with techno‑economic assessment (TEA), life‑cycle assessment (LCA), or the development of robust net-zero strategies for industrial assets or clusters, I also work with partners on bespoke analysis and training. Book an initial consultation via my website: book.drhanak.com

  • On viability of power-to-gas for CO2 use

    TL;DR

    • The power-to-gas concept converts surplus renewable energy into methane (CH₄) via the Sabatier reaction:
      4H₂ + CO₂ → CH₄ + 2H₂O.
    • Methane can be injected into existing gas networks for energy storage and distribution.
    • The process shows:
      • Technical feasibility: Energy loss of ~4% for CH₄ production (excluding H₂ and CO₂ generation).
      • Economic challenges: High costs of CO₂ supply and renewable energy limit financial viability.
    • Environmental benefits depend on sourcing CO₂ from biogenic or atmospheric sources rather than fossil fuels.
    • Further research is required to:
      • Optimize efficiency and reduce costs.
      • Explore policy incentives and market opportunities

    What is power-to-gas?

    A power-to-gas concept assumes that we can use the energy from renewables during the period of reduced demand to produce hydrogen via electrolysis. To avoid the need for hydrogen compression and storage, produced hydrogen is then combined with CO2 to produce CH4. This is the so-called Sabatier reaction or CO2 hydrogenation reaction. The produced CH4 can be then injected into the existing gas networks, as shown in Figure 1 below.

    No alt text provided for this image

    Fig. 1: Representation of the power-to-gas network [1]

    This process follows the reaction below:

    4H2 + CO2 → CH4 + 2H2O

    Is the power-to-gas process technically viable?

    As you may know, process design, techno-economics and life-cycle assessments form a substantial part of my consulting and teaching activities. To refresh the curriculum of my modules, I’ve started developing new industrially-inspired case studies – methanation appeals to be an interesting concept from the process design point of view, and that is why I selected it as the very first case study to develop this year (much more to come!).

    power-to-gas process flow diagram dwsim

    Fig. 2: Process flow diagram for methanation process

    You can see the initial process design I developed in DWSIM, assuming both CO2 and H2 need to be compressed to the reaction pressure. Is this process feasible then?

    Well, my initial analysis showed that this process would consume 0.59 kWh (2.12 MJ) of renewable energy to produce 1 kg of CH4 – and this doesn’t account for the energy required for H2 or CO2 production. Considering the heating value of methane of 55 MJ/kg, we are looking at the energy loss of about 4% for this process itself.

    Economics and environmental performance of power-to-gas

    Finally, it’s important to talk about the economics and environmental performance of such a concept. I’m yet to complete the full assessments and optimization of the layout, but my previous work can shed some light on these aspects.

    power-to-gas process flow diagram dwsim techno-economic viability

    Fig. 3. Economic viability of power-to-gas concept [2]

    In my previous collaborative work with the research group led by Prof Luis Romeo [2], we evaluated the techno-economic viability of the power-to-gas process integrated with the oxy-combustion process for CO2 supply.

    The economic analysis (Figure 3), showed that because of the costs associated with CO2 supply, the power-to-gas project may not be viable under the conditions we considered. This would, of course, change considering the recent changes in carbon markets.

    And this brings me to the final point – the environmental implications. Naturally, we would like to use CO2 captured from the power plants so that we could add more value to it. But if that CO2 comes from the combustion of fossil fuels, then we merely shift the emission point. Sure, we could create economic value through this process, but it would not help us solve the global warming challenge.

    So where such CO2 could come from? We would need to consider biogenic and atmospheric sources, but this would definitely have implications on process economics.

    More work is needed – happy to collaborate!

    Conclusions

    In summary, while the power-to-gas process demonstrates technical promise with manageable energy losses, its economic and environmental viability remains contingent upon advancements in CO₂ sourcing and reductions in associated costs. Further research and optimization are necessary to enhance the overall efficiency and economic attractiveness of the system. Collaborative efforts and continued exploration of innovative solutions will be essential to overcome the current barriers and fully harness the potential of power-to-gas technologies in the transition to a sustainable energy future.

    PS: If you need consultancy or training in process design and process economics, green energy transition, industrial decarbonisation, and carbon removal technologies, I am open to discussing how we can collaborate together!

    References

    1. Bailera M, Lisbona P, Llera E et al. Renewable energy sources and power-to-gas aided cogeneration for non-residential buildings. Energy 2019;181:226–38.

    2. Bailera M, Hanak DP, Lisbona P et al. Techno-economic feasibility of power to gas–oxy-fuel boiler hybrid system under uncertainty. International Journal of Hydrogen Energy 2019:9505–

    Frequently Asked Questions:
    Power-to-Gas and Methanation Process

    1. What is the power-to-gas concept?

    The power-to-gas concept uses surplus renewable energy to produce hydrogen (H₂) through electrolysis. The hydrogen is then combined with carbon dioxide (CO₂) in a reaction known as the Sabatier reaction to produce methane (CH₄). This methane can be injected into existing gas networks, providing a way to store and transport renewable energy.

    2. What is the Sabatier reaction?

    The Sabatier reaction is a chemical process where CO₂ reacts with H₂ to produce CH₄ and water (H₂O):
    4H₂ + CO₂ → CH₄ + 2H₂O
    This reaction is exothermic, meaning it releases heat, and it requires specific catalysts and operating conditions to achieve efficient conversion.

    3. How efficient is the power-to-gas process?

    The initial analysis indicates that the process consumes 0.59 kWh (2.12 MJ) of renewable energy to produce 1 kg of CH₄, resulting in an energy loss of approximately 4%. However, this does not include the energy required to produce H₂ and CO₂, which affects overall efficiency.

    4. Is the power-to-gas process economically viable?

    Economic viability depends on several factors, including the cost of renewable electricity, hydrogen production, and CO₂ supply. Current analyses show that high costs associated with CO₂ supply, particularly from fossil fuel combustion, can render the process unfeasible. However, changes in carbon markets and alternative CO₂ sources may improve its economic outlook.

    5. What are the environmental benefits of power-to-gas?

    The environmental benefits depend on the source of CO₂. Using CO₂ from biogenic or atmospheric sources supports a circular carbon economy and helps mitigate climate change. However, using CO₂ from fossil fuel combustion shifts emissions without reducing net greenhouse gas levels.

    6. Where can the CO₂ for this process come from?

    CO₂ can be sourced from power plant flue gases, industrial emissions, or biogenic and atmospheric sources. While fossil-based CO₂ is more readily available, it does not offer net emissions reduction. Biogenic and atmospheric CO₂ sources are more sustainable but often come with higher costs and technological challenges.

    7. How does power-to-gas compare to other energy storage solutions?

    Power-to-gas offers the unique advantage of utilising existing gas networks for energy storage and distribution. Unlike batteries, which are limited in storage capacity and duration, power-to-gas can store large amounts of energy for extended periods. However, its efficiency and cost-effectiveness are lower compared to some battery technologies.

    8. What are the next steps to make power-to-gas more viable?

    Further research is needed to:

    • Improve the efficiency of the Sabatier reaction.
    • Optimize the integration of hydrogen production and CO₂ capture.
    • Reduce the cost of renewable energy and CO₂ supply.
    • Explore policy and market incentives to support deployment.

    9. Can I collaborate on research in this area?

    Yes, collaborations are welcome! If you’re interested in working on process design, optimization, or techno-economic and environmental assessments, feel free to reach out.

    10. Why did you choose methanation as a case study?

    Methanation is an industrially relevant and technically challenging process that showcases key aspects of process design, optimization, and sustainability assessment. It serves as an excellent example for educational purposes and aligns with my expertise in process design and consulting.

  • Unlocking the potential of waste-to-energy and CCUS synergy: Redefining negative emissions in the UK

    TL;DR

    • WtE plants contribute significantly to UK emissions, yet play a vital role in waste management and energy generation.
    • Traditional CCUS methods like amine scrubbing are not ideal for WtE due to high energy demands, negatively impacting WtE’s energy output and economic viability.
    • Our research at the Net Zero Industry Innovation Centre explores CaL as a cost-effective and energy-efficient alternative for CO2 capture in WtE plants.
    • CaL offers significant advantages: Competitive cost of CO2 avoided: Lower than traditional methods, potentially incentivising WtE operators to adopt CCUS. Minimal efficiency penalties: CaL maintains or even increases WtE’s energy generation capacity unlike amine scrubbing. Net negative emissions potential: Captured CO2 exceeds plant emissions, contributing to negative emissions goals.

    Crossroads for WtE and CCUS: Redefining Sustainability in the UK

    The UK’s Ten Point Plan for a Green Industrial Revolution boldly aspirates for a cleaner future. Carbon Capture, Utilisation, and Storage (CCUS) is critical in delivering this aspiration. The East Coast Cluster stands in the vanguard of this ambitious strategy, aiming to remove nearly 50% of the UK’s industrial cluster emissions and support an average of 25,000 green jobs annually between now and 2050. While most of the current CCUS projects focus on low-carbon power generation or hydrogen supply, another promising pairing can contribute to delivering the net zero aspirations. Although not prioritised in the UK Government Track-1 CCUS cluster sequencing exercise, integration of waste-to-energy (WtE) and CCUS can deliver negative CO2 emissions and reduce the amount of landfilled waste.

    Notably, while WtE offers a valuable waste management solution and generates energy, its contribution to the CO2 emissions in the UK is substantial. In the Teesside Cluster alone, which is a part of the East Coast Cluster, WtE accounts for a staggering 18% of total greenhouse gas emissions. The projections are also concerning, as the UK’s WtE has been forecasted to emit up to 20 MtCO2e annually by the mid-2020s. Such a figure is higher than 11 MtCO2e annually reported in 2021 for industrial processes in the UK. The preliminary work on WtE and CCS integration by the Energy Systems Catapult showed that the specific CO2 emissions from WtE are 600 gCO2/kWh (excluding biogenic carbon), and flue gas contains up to 12%vol CO2. As a result, their ESME model demonstrated that unabated WtEs must be phased out by 2040 due to reduced carbon budgets, indicating the need to develop low-carbon alternatives.

    This is where CCUS can play a role. By strategically integrating CCUS into existing WtE plants, the UK can achieve a two-pronged victory: significantly curbing its carbon footprint and transforming WtE into a net negative emitter of greenhouse gases. Yet, unlocking the full potential of WtE-CCUS synergy requires careful consideration. Existing CCUS solutions, while potentially effective in larger-scale applications, pose challenges for WtE due to their high energy demands and potential impact on energy output and profitability. The search for alternative CCUS technologies with lower energy penalties and costs becomes paramount.

    Therefore, the future of WtE in the UK’s decarbonisation strategy hinges on two pillars: embracing innovation in CCUS technologies tailored to WtE applications and forging strategic partnerships to navigate the technological and economic complexities.

    The Challenge: Decarbonising WtE without hindering energy or economic performance

    While amine scrubbing has emerged as the CCUS technology of choice for many industrial applications, such as the Net Zero Teesside Power, its application to WtE presents unique and prohibitive challenges. This mature approach to CO2 capture stumbles on the high demand for steam required for its regeneration. In the UK, WtE plants often play a critical role in supplying heating, electricity, and/or industrial steam. Implementing amine scrubbing can have a detrimental impact on these vital functions, jeopardising both WtE’s energy output and economic viability.

    The severity of these challenges is well documented. An AECOM study revealed that amine-based capture units could consume a staggering 66% of the total thermal input to the steam turbine at a combustion-based WtE plant. This translates to a significant reduction in electricity generation, a key revenue stream for WtE facilities. Further research by Magnanelli et al. confirmed this concern, demonstrating that amine scrubbing integration can lead to a 30% reduction in power output and a 12% reduction in heat output from a typical WtE plant. Supplying such an amount of steam will not only be limited by technical considerations but will also substantially impair the economic viability of the WtE plant.

    Adding to the complexity is the lack of readily available information regarding post-combustion CO2 capture for gasification-based WtE plants. These facilities, utilising a different waste processing technology, present additional unknowns regarding CCUS compatibility. This knowledge gap further accentuates the need for alternative CCUS solutions that can overcome the limitations of amine scrubbing and effectively decarbonise WtE without compromising its energy production and economic viability.

    A Promising Solution: Exploring the potential of carbonate looping

    Amidst the challenges of WtE decarbonisation with mature amine scrubbing, our research at the Net Zero Industry Innovation Centre has focused on emerging carbonate looping (CaL) technology. Unlike steam-hungry amine scrubbing, CaL offers a potentially cost-effective and energy-efficient solution for capturing CO2 from WtEs. Our past studies have demonstrated the remarkable cost advantages of CaL. Hanak et al. revealed that post-combustion CaL retrofits to coal-fired power plants could achieve a competitive cost of CO2 avoided (~£40/tCO2), significantly lower than the range reported for amine scrubbing by Wood (ranging from £73 to £173/tCO2). This translates to a potential financial incentive for WtE operators considering CO2 capture.

    However, the benefits of CaL extend beyond cost savings. Compared to amine scrubbing, CaL exhibits a demonstrably lower impact on energy efficiency (<7% points) and can actually increase the power output by 20-50%. This means that WtE facilities adopting CaL can maintain their current energy generation capabilities while simultaneously capturing CO2.

    However, our research pushes the boundaries even further. We have proposed calcium looping combustion (CaLC) as a potential breakthrough technology for WtE decarbonisation. By replacing conventional incinerators with indirect heat transfer in the calciner, CaLC can minimise efficiency penalties to an impressive <3% points. For power generation from coal, our research showed a remarkably low cost of CO2 avoided of <£35/tCO2. Notably, municipal solid waste is a lower-quality fuel than conventional fossil fuels. Therefore, the expected efficiency penalties and cost of CO2 avoided are expected to be higher. Yet we forecast it will still be substantially lower than the mature amine scrubbing retrofits. At NZIIC, we are currently working with the UKCCSRC and the major waste-to-energy organisations in the Teesside Cluster to assess the feasibility of such technology.

    Conclusion

    As the UK embarks on its Green Industrial Revolution, the East Coast Cluster stands as a beacon of ambition, aiming to capture nearly half of the UK’s industrial emissions. While the focus is low-carbon power and hydrogen, an often-overlooked pairing holds immense potential: integrating Waste-to-Energy (WtE) with Carbon Capture, Utilisation, and Storage (CCUS). Such a synergy offers a two-pronged victory, curbing the nation’s carbon footprint and transforming WtE into a net negative emitter.

    However, unlocking this potential requires navigating a complex landscape. While effective in larger applications, traditional amine scrubbing proves problematic for WtE due to its high energy demands and detrimental impact on energy output and profitability. The search for alternative CCUS solutions with lower energy penalties and costs becomes paramount.

    Our research at the Net Zero Industry Innovation Centre focuses on carbonate looping (CaL) as a promising alternative. Unlike amine scrubbing, CaL presents a cost-effective and energy-efficient solution. Studies indicate a competitive cost of CO2 avoided and minimal efficiency penalties. This allows WtE operators to embrace carbon capture without compromising their core functions.

    Acknowledgement

    This publication is based on research conducted within the “Techno-economic and carbon footprint assessment of advanced waste-to-energy with carbon capture and storage for East Coast Cluster” project funded by the UK Carbon Capture and Storage Research Community