November 2026 May 2023 Decarbonisati n Technolo gy Powering the Transition to Sustainable Fuels & Energy DECARBONISATI N TECHNOLOGY
UTILISATION OF CAPTURED CARBON RENEWABLE HYDROGEN & HYDROGEN SAFETY SUSTAINABLE E-SYNGAS METHANE FROM PALM OIL MILLING
SUSTAINABLE AVIATION AND MARINE FUELS BLUE AMMONIA ELECTRIFICATION: GRID CONNECTIONS & FLEXIBILITY DECARBONISATION OF REFINING VALUE CHAINS
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Contents
November 2026
5 EU storage targets established: Now the grid has to catch up Graeme Hutchison Eclipse Power
9 Grid flexibility: The UK’s most overlooked clean power tool Enel X
13 Satellite-informed methane decarbonisation Ihwan Rafina MosaiX
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Can lignin become a refinery feedstock? Simge Oğuz Ankara University, Department of Chemical Engineering Vahide Nuran Mutlu SOCAR Türkiye R&D and Innovation Co.
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Designing the next blue ammonia plant VK Arora Kinetics Process Improvements, Inc.
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Sustainable e-syngas: A decarbonisation win-win Stephen B. Harrison sbh4
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Making biomass work for Sustainable Aviation Fuels Harold Boerrigter Shell Catalysts & Technologies Patrick Bergman Yilkins
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From CO₂ to SAF Nabeel Ataimisch ZCT Solutions
56 Enhancing waste-heat-to-power with moisture measurement Antti Heikkilä Vaisala JTEC Energy
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Integrating renewables into a modern refinery Kai Dannenbauer, Adrian H. Hergesell, and Ioan-Teodor Trotus hte GmbH Johanna Rindebäck and Moa Sundén VAROPreem
© 2026. The entire content of this publication is protected by copyright. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means – electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner. The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies.
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What’s ne t?
Renewable electricity is widely recognised as the backbone of the energy transition. The early years of the transition have seen the share of renewable resources (solar, wind, hydro, and nuclear) grow in proportion to fossil sources (coal, oil, and gas). In its Energy Transition Outlook 2026, DNV forecasts the share of electricity in the global final energy demand will double from 16% in 2026 to 33% by 2045. In this edition of Decarbonisation Technology, we share two articles on systems integration for electrification that highlight the need to design grid connections and grid flexibility alongside expanding energy storage capacity. Prolonged geopolitical conflicts mean energy security and affordability will be key drivers of the energy transition in the immediate future. In its Oil Market Report – October 2026, the IEA reported that diesel prices reached an all-time high of more than $200/bbl, with broad economic consequences for the price of goods and inflation. Inventory drawdowns mean country-level reserves of oil products are now at their lowest levels in nearly 10 years, with winter approaching in the Northern Hemisphere. Energy importers are increasingly turning to domestic renewable solutions to reduce their dependence on imported fuels. Even so, fossil energy sources will continue as the largest global primary energy supply into the 2050s. This emphasises the importance of reducing carbon intensity (carbon dioxide and methane) during upstream oil and gas extraction and downstream manufacture, followed by combustion of hydrocarbon fuels. Emissions from road transport are declining due to the growing share of electric vehicles. However, for the harder-to-electrify transport sectors, biofuels and e-fuels are the only practical ways to reduce the carbon intensity of marine and air transport. Industrial clusters are being designed to minimise carbon emissions by sharing investments in facilities such as carbon (dioxide) capture, pipelines, and storage. Rethinking the use of waste streams from agriculture and forestry operations can reduce the carbon intensity of food and forestry products to help restore a healthy balance in the carbon cycle. Developments such as capturing methane from palm oil mill effluent and using lignin as a refinery feedstock show that the future of sustainable hydrocarbons, like renewable electricity generation, involves integrating a diverse mix of energy sources. Referring back to DNV’s Outlook 2026 , global emissions are likely to be reduced by 44% by 2050. This still means we are likely to exceed the 2.0ºC global warming target by 2051. Perhaps we can all consider what more we can do as individuals to reduce our domestic emissions?
Managing Editor Rachel Storry rachel.storry@emap.com Consulting Editor
Robin Nelson robin.nelson@ decarbonisationtechnology.com Sub-Editor Lisa Harrison lisa.harrison@emap.com Graphics Peter Harper Account Director Renzo Latella renzo.latella@emap.com Business Development Director Paul Mason info@decarbonisationtechnology.com tel +44 844 5888 771 Managing Director Richard Watts richard.watts@emap.com
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Cover story Dragon LNG Terminal, Milford Haven, UK. Courtesy of Shell
Robin Nelson
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EU storage targets established: Now the grid has to catch up How the EU’s Tripartite Agreement for Energy Storage will drive deployment with behind-the-meter and co-located battery solutions for faster connections
Graeme Hutchison Eclipse Power
E arlier this year, parties from the public sector, energy-consuming industries, and clean energy developers signed a shared pledge on energy storage brokered by the European Commission. Signatories to the Tripartite Agreement for Energy Storage (European Commission, 2026) committed to lifting the EU’s annual pace of storage deployment from around 12GW per year to roughly 45GW annually between 2026 and 2028. The target is to hit the 200GW of capacity that the bloc’s own analysis says it will need by 2030 – more than three times the approximately 55GW installed at the start of this year. It is perhaps easier to understand the scale of the ambition in another way. Storage is expected to supply around 10% of peak electricity demand by 2028, up from roughly 5% in 2025 (pv magazine, 2026) . However, analysis of the agreement shows that the commitment does not yet fully live up to that ambition. Formal pledges submitted by member states so far add up to 30-35GW, some way short of the 45GW figure in the agreement text itself (Energy-Storage.News, 2026) . Bringing government, finance, and industry behind a shared commitment is exactly the kind of alignment needed to deliver large-scale battery rollout, so the agreement is a welcome signal. It points towards a more secure, flexible, and decarbonised electricity system that should ultimately become cheaper for the businesses and households who pay for it. However, as we often see with policy, this might not result in the solution we actually need. The agreement is explicitly non-binding,
yet its targets are aggressive. Turning pledges into energised assets will take considerable political will. Member states will need to move their regulatory frameworks quickly, as will the developers and financiers of pledged projects – a 2028 milestone is already looking uncomfortably close. To support the agreement, the European Investment Bank (EIB) is extending its existing €1.5 billion grids manufacturing package to cover storage-component manufacturers. However, while meaningful, it is modest when set against the scale of what a continent-wide storage build-out will actually cost. The scale and ambition of this agreement is exactly what Europe needs to help galvanise its deployment of storage and, in turn, support the deployment of more renewable power to its grids. There is no doubt that signing this agreement will attract private and member- state investment to get the required capacity built. What remains in question is just how fast this massive extra storage capacity can be connected to the grid it is meant to serve. Grid connections are now the main constraint For any battery project, the biggest constraint on how quickly it reaches the network is the availability of a suitable connection. Grid connections are highly contested across the continent. New transmission lines take years to plan, consent, and construct – years that are added to the energisation date of the storage projects waiting for them. The EU’s Grids Package and its accompanying Action Plan (distinct from the EIB’s finance mentioned above) aim to tackle this
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Examples of behind-the-meter storage models
Country/model
Structure
Notes
Netherlands/group transport
Private, multi-party connection structure
Estimated 6GW of behind-the-meter battery deployment achieved under this structure Take-up slower than the Dutch model; regional and local regulatory variation cited as a factor Enables co-located connections within a Focused initially on demand connections; full framework still some years from completion defined site
agreement (GTA)
Germany/Kundenanlage industrial park model
Private-network structure for co-located
demand and generation
Italy/closed distribution
Comparable private-network framework
systems
Ireland/CRU-developed
IDNO-style rules in development
framework
UK/IDNO
Overarching licence, first awarded in 2004, Not directly replicated elsewhere in portable across multiple sites and regions Europe; enables economies of scale unavailable to single-site private networks
Table 1
transmission bottleneck directly, chiefly by clarifying how the cost of cross-border ‘projects of common interest’ is shared between the member states benefiting from them. In theory, that should make it easier to justify grid reinforcements that serve a wider region rather than a single country. It also promotes planning networks on a more holistic, cross-border basis rather than state by state. This is best understood as a parallel measure, not one that directly fixes battery connection times. Over time, it may make it easier to build the transmission capacity on which storage ultimately depends. However, it will not shorten the queue any given battery project sits in today. That is a critical gap, so what can be done to bridge it? Behind-the-meter and co-located solutions are one way to address the grid connection shortage. Pairing, say, a battery with a generation or demand asset such as a data centre, solar farm, or industrial site, and placing both behind a single connection point can reduce the dependency on the grid. Because demand and generation are partially balanced locally, the connection to the wider network can be smaller, which makes it faster, cheaper, and less disruptive to build. Local storage capacity may be used purely to balance supply and demand behind the meter or be allowed to ‘spill’ back into the network as an
additional source of power. If a large industrial or data centre customer would otherwise be drawing directly from the network, behind-the- meter balancing reduces gross demand: electrons find their way to wherever they are needed. Europe already has some of the regulatory building blocks this needs, even without an independent distribution network operator (IDNO) framework as found within the UK (see Table 1 ). One example, the Netherlands’ group transport agreement structure, has enabled an estimated 6GW of behind-the-meter battery deployment. A second example is Germany’s Kundenanlage industrial park model, which provides a comparable private-network structure, though its take-up has been slower. Italy has its own closed distribution system framework, and Ireland’s regulator, the Commission for Regulation of Utilities (CRU), is developing IDNO- style rules for demand connections. None of these is a direct equivalent of the UK’s IDNO model, and Europe does not need to import it wholesale to capture its benefits. A Europe-wide, harmonised version in which a single network operator could build, operate, and recover costs for assets across national borders would be an unnecessarily slow route to faster battery deployment. Arguably, it would also be difficult to reconcile with the different ways individual member states remunerate their networks. More realistic, and more useful, is
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The Tripartite Agreement gives Europe’s storage ambitions a shared direction
taking the best practice each of these national models represents and applying it within the regulatory regime each country already has. Bringing resources online is not just a case of solving the physical connection, though: the commercial part can often be challenging, too. Getting every party behind a single connection point – which might include the generator, demand customer, and potentially multiple off-takers – to agree on how the asset will be operated and paid for is not necessarily easy. There are technical considerations, too. A battery co-located with a wind farm and a data centre might be expected to provide both long-duration storage and fast-acting ancillary services. However, each use-case can call for a different battery specification. A system providing one is not available for the other at the same time. These are solvable problems, but they do take good-faith negotiation. Lessons from UK connection reform The UK has its own problems when it comes to grid connections. This challenge is further highlighted by the oversubscription of battery projects within the CP2030 Action Plan, where battery connection applications currently exceed available capacity by approximately 61GW, underlining the need for continued connection reform and more flexible approaches to grid access.
However, it also offers lessons for the wider European grid network. Reforms to the National Energy System Operator (NESO)’s connections queue (NESO, 2026) have moved the UK system from a first-come, first-served model – which became clogged with hundreds of gigawatts of largely undeliverable generation and storage projects – towards one that prioritises schemes that are genuinely ready to build. The reformed queue has reduced from around 700GW of applications to approximately 300GW, removing around 400GW of stalled or non-viable projects and freeing up capacity for schemes that can genuinely proceed. Ofgem’s own figures put the effect at around 7.8GW of energy assets of which connection dates have been brought forward by an average of six years (Ofgem, 2026b). That is a substantial acceleration, and one that Europe’s own grid operators, working through their own versions of queue reform, could plausibly replicate. The IDNO model also offers an example of what can happen when you break the geographical link between network operators and their assets. Unlike the UK’s distribution network operators (DNOs) and most of their European counterparts, IDNOs are not tied to a single site or region. An IDNO can own and operate assets in Scotland and in Gloucestershire under the same licence. That portability lets IDNOs spread fixed costs such
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as operations and maintenance across a larger asset base, which is part of why the UK has built what is, by some measure, the largest operational battery fleet in Europe (European BESS Index, 2026) . The IDNO model has also given developers, network owners, and off-takers more commercial and technical latitude in design and supply- chain choices than a conventional, single-region distribution licence typically allows. Crucially, it also allows private investment into the UK electricity network, helping expand what it is possible to build and connect. Europe does not need a carbon copy of the IDNO licence, but it has been a significant success. Ofgem granted the first licences in 2004; as of August 2026, there are 27 licensed IDNOs ( Ofgem, 2026a ), and together they connect around 80% of new homes in England ( INA, 2025 ). The underlying principles of the IDNO concept would travel well. An EU equivalent might be founded on giving independent operators enough commercial and technical flexibility to connect demand and storage assets behind a single point, within states’ existing regulatory regimes, rather than trying to harmonise every national framework into one European model before anything gets built. Individual member states could adopt a lighter touch version of this without a full IDNO-style licence. Rather than attempting to harmonise how entire networks are remunerated, a regulator could instead introduce a distinct connection or network tariff specifically for independent, co-located operators. That alone would capture much of the IDNO model’s practical benefit: clearer investment signals, competition for assets, and pressure to optimise pricing for the customer, without requiring the kind of pan-European regulatory harmonisation that would take years to negotiate. Behind-the-meter storage as the accelerator Taken together, this forms a practical argument for behind-the-meter and co-located storage as the fastest route to the tripartite agreement’s targets. It does not depend on a fresh wave of primary legislation, and it works within existing member-state frameworks rather than against them. Reducing the net capacity a project needs
from the wider grid reduces both the cost and the lead time of the connection, which is the single biggest driver of how quickly a storage project actually gets built. This is already proven in practice in the UK, where Eclipse is delivering microgrid and private network projects that combine co-located generation, demand, and storage behind a single connection point. Elsewhere in Europe, the model is still taking shape: developers are progressing co-location and behind-the-meter connections on active projects in Germany, France, and other EU markets. However, their underlying connection agreements and commercial structures are the same ones that make co-located battery storage possible, and there is no technical barrier to adding storage to sites built this way. With the increased use of flexibility to balance networks, demand itself is becoming more useful to network planners. Large flexible loads such as data centres or manufacturing plants can in principle turn down or defer their consumption during system peaks and offer that flexibility back to the network as an ancillary service. That complements co-located storage, so when planned together, co-located storage and flexible demand can take pressure off the wider transmission network rather than adding to it. It is important to clarify that none of this makes storage a complete substitute for new transmission capacity. Some grid reinforcement is unavoidable, and the Tripartite Agreement’s targets will not be met by co-location alone. However, behind-the-meter is a meaningful part of the solution, and one that is already available within the regulatory tools most member states already have, rather than years away pending a fresh round of EU-wide legislation. The Tripartite Agreement gives Europe’s storage ambitions a shared direction. Now we just need to accelerate how quickly individual projects connect to the grid. Behind-the-meter and co-located solutions are not the whole answer, but they are solutions developers, network operators, and regulators can act on today. VIEW REFERENCES Dr Graeme Hutchison enquiries@eclipsepower.co.uk
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Grid flexibility: The UK’s most overlooked clean power tool Unlocking the potential of grid flexibility for sustainable energy by balancing supply and demand in the UK’s clean power future
Enel X
T he UK has set itself one of the most ambitious clean power targets in the world: by 2030, at least 95% of its electricity generation should come from low- carbon sources. However, achieving this requires a massive expansion of renewable capacity, and generation is only half the story. A grid powered by widely distributed renewable sources, rather than traditional centralised power stations, needs to balance supply and demand in real time across millions of connected assets. Variable levels of wind and sun translate into variable supply and create the need for demand that can be varied in response. This is demand flexibility in a nutshell: the ability to intentionally adjust consumers’ use of electricity to help balance the grid. However, the UK does not have nearly enough flexible capacity. The government’s Clean Flexibility Roadmap calls for 51-66 GW by 2030, which is two or three times what was available in 2023. Much of the conversation around flexibility in the UK centres on the Capacity Market, which pays organisations to release capacity at peak demand, either by generating electricity or by ‘turning down’ processes and reducing demand. This demand response market has been operating for 12 years. However, it is just one tool in a much larger toolbox. The real opportunity for participants lies in combining it with all the other flexibility mechanisms. What flexibility means Grid flexibility goes beyond demand response to encompass frequency response, wholesale market trading, the balancing mechanism, and a growing number of ancillary services. Each represents a different way for energy assets
– whether they are generating, storing, or consuming electricity – to respond to what the grid needs at any given moment. Each programme generates value for participants, typically offering payments for an enrolled capacity regardless of whether that capacity is actually called on. Realising the maximum value means enrolling an asset in several mechanisms at the same time. This value-stacking principle is at the heart of the Virtual Power Plant (VPP) model, which Global insight: The Clean Flexibility Roadmap To support its goal of delivering 95% clean electricity by 2030, the UK government launched the Clean Flexibility Roadmap. While traditional grids rely on predictable, centralised power stations, a renewables- heavy grid depends on the weather, meaning supply fluctuates constantly. Instead of trying to adjust electricity generation to meet demand, the UK is adjusting demand to match generation. The goal: Rapidly scale the UK’s flexible energy capacity to 51-66 GW by 2030. Beyond the capacity market: Rather than relying solely on large industries turning down power during peak hours, the strategy integrates a vast, interconnected ecosystem. The strategy: The roadmap unlocks capacity from millions of distributed assets by combining industrial demand response with consumer-led flexibility (smart EV charging and home batteries), grid-scale battery storage, and cross-border interconnectors.
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aggregates diverse distributed assets so they can deliver flexibility across many markets, adapting in real time to where the value is greatest. For businesses, the VPP model means assets such as a battery energy storage system (BESS) or a flexible manufacturing process are not locked into a single revenue stream. They could earn from the Capacity Market, participate in frequency response, trade on the wholesale market, and contribute to the balancing mechanism, all managed through a single platform. The result is a stronger business case and an accelerated return on investment for energy assets such as a BESS. A VPP also offers participants greater resilience against any one market shifting and allows them to make a more useful contribution to the electricity system as a whole. Global picture The Enel Group VPP has more than 11 GW of demand response capacity under management. That capacity spans 13 countries and more than 100 demand response programmes. Just as importantly, the VPP aggregates capacity from 8,000 customers across multiple sectors – from hydropower and grid-scale battery storage, through industrial and agricultural users, to major data centre operators and food and beverage manufacturers. In Australia, Enel launched the first VPP under the New South Wales (NSW) Government’s Electricity Infrastructure Roadmap in 2025. This programme uses demand response to firm renewable generation and support grid security during peak periods. In North America, the group manages nearly 5GW of flexible demand response capacity. In South Korea and Taiwan, it is helping drive the evolution of flexibility markets, supporting the transition towards more distributed and renewable-based power systems. In many countries, it works with regulators and transmission system operators (TSOs) to develop programmes that encourage customer participation, while ensuring that TSOs receive appropriate services. These examples show that the need for demand flexibility is global. However, in the UK, with its mature market mechanisms,
sophisticated system operator and a strong industrial base, participation remains well below its potential. The country has the policy ambition and the market infrastructure, but participation must ramp quickly to meet demanding targets. Closing the gap requires rapid take-up from commercial and industrial energy users. The good news is that there is plenty of motivation. Flexibility programmes are revenue- generating, particularly when accessed by value-stacking within a VPP. They support grid stability, which is becoming ever more essential to organisations relying on clean electricity to decarbonise. Moreover, they come with a wider benefit. By supporting a greater proportion of renewables on the grid, organisations help decarbonise power for themselves and other users. That is an important benefit in the context of increasing environmental scrutiny and raised investor expectations. Putting the fizz in These motivations already resonate across a range of sectors beyond the energy-intensive heavy industries that have historically dominated demand response. Carlsberg Britvic, one of the UK’s largest drinks producers, participates in flexibility markets through its production facilities, temporarily switching off machinery or rescheduling a production process to relieve pressure on the grid. In return, it generates revenue against its enrolled capacity and receives advance warning of potential grid stress events, giving it time to act before supply is at risk. For a manufacturer of perishable goods, where unplanned interruptions can jeopardise customer orders, that early visibility is as valuable as the income. Carlsberg Britvic’s experience demonstrates that flexibility comes from understanding your own operations well enough to identify where capacity exists, and the principle is not sector-specific. Severn Trent Water, a regulated operator of critical national infrastructure, has enrolled 5 MW of flexible capacity across seven sites by turning down pumping and treatment processes at agreed times. The utility has already generated more than £670,000 in Capacity Market revenue without any disruption to its operations. If a water company
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supplying two billion litres of drinking water a day can find meaningful flexibility, most commercial and industrial organisations can too. While ‘turn down’ participation is valuable, BESS assets unlock even greater returns from flexibility programmes because they can quickly respond across multiple simultaneous markets. This elevates a BESS from a local energy storage device into a resource that can participate in flexibility, trade on the wholesale market, contribute to the balancing mechanism, and provide backup power when needed. However, the full potential of BESS can only be unlocked through value-stacking in a VPP. As with any growing sector, there is a gap between what is credible and what some flexibility partners claim they can offer. Revenue projections should be scrutinised carefully to ensure they are based on sustained market participation across a diversified set of programmes, rather than assumptions about peak pricing conditions. Businesses evaluating BESS need to ask partners about operational scale, forecasting methodology and, most importantly, whether they can demonstrate proven performance. A BESS is a long-term asset, lasting more than 15 years. The right optimisation partner will build a conservative case and over-deliver, rather than promise headline returns that depend on conditions no one can guarantee. Flexing the future The Clean Flexibility Roadmap recognises that flexibility provided by both households and businesses will be central to a clean, affordable, and secure power system. The appointment of a Flexibility Commissioner and the establishment of annual progress forums signal that the government is serious about driving flexibility forward. However, not enough businesses yet realise that their existing operational assets may be able to generate income. Manufacturing processes, heating, ventilation, and air conditioning (HVAC) systems, combined heat and power (CHP) plants, backup generators, and battery storage are all potential sources of flexibility revenue, not just Capex or Opex. The UK has the potential to be a global leader in grid flexibility. What it needs is for more businesses,
Carlsberg Britvic participates in flexibility markets through its production facilities
working with the right partners, to deliver on that promise. About Enel Enel is a multinational power company and, globally, the largest renewable player, the foremost electricity distribution network player by number of grid customers served, and the biggest retail operator by customer base.1 Enel generates electricity with more than 92 GW of total capacity. Enel Green Power, the Group’s renewables arm, has a total capacity of 67 GW and a generation mix that includes wind, solar, geothermal, and hydroelectric power, as well as energy storage facilities, installed in Europe, the Americas, Africa, Asia, and Oceania. Enel Grids, the Group’s global business line dedicated to the management of the electricity distribution service worldwide, delivers electricity through a network of 1.9 million km with more than 69 million end users connected to its distribution grids. VIEW REFERENCES
Enel X enelxuk@enel.com
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Reliable by Design Proven in Execution Watlow is your partner for electrifying large thermal loads in Oil & Gas applications
Satellite-informed methane decarbonisation By pairing orbital visibility with precision bioenergy engineering, orbital platforms can turn an environmental liability into a bankable, clean energy asset
Ihwan Rafina MosaiX
G lobal agricultural supply chains are policies and rising market expectations. While most strategies focus on grid power and solar, a concentrated source of greenhouse gas emissions remains largely untapped: methane venting from industrial wastewater across the tropical belt. Methane has roughly 80 times the warming impact of carbon dioxide (CO₂) over a 20-year horizon (IPCC, 2021) . Within palm oil milling, the organic wastewater generated during extraction – palm oil mill effluent (POME) – represents a major, historically unmeasured environmental liability. Capturing POME methane and converting it into power or renewable natural facing intense pressure to decarbonise, driven by tightening international climate
far from universal across major producing regions (Valverde, et al., 2024) . Open treatment ponds in palm oil production are rarely directly measured. Instead, asset owners and corporate buyers often rely on generic estimates that may not capture site- specific operating conditions or actual methane release rates. Without reliable, site-specific data across Southeast Asia, mill operators and clean-tech investors will struggle to justify the upfront Capex for capture-and-use infrastructure. Combining orbital satellite tech with ground-level precision engineering changes this equation, turning an invisible compliance risk and source of emissions into a quantified, investable energy asset.
gas (RNG) is relatively standard technology, yet it remains hugely underused across Southeast Asia (Valverde, et al., 2024) . Why? Cost or perhaps more due to a lack of verifiable data? Biogas systems are installed at fewer than 10% of palm oil mills (POM) in Indonesia, compared with around 30% in Malaysia and 12% in Colombia, indicating that methane capture remains
POME management by region (N/A excluded)
1,000 1,200 1,400 1,800 1,600 2,000
1,726
Open lagoon Covered + are Covered lagoon
0 200 600 400 800
224 196
135 64
62 13
29
17
15
5
4
3
2
0
Southeast Asia Paci c
Latin America
Africa
South Asia
North America
Figure 1 POME management in palm oil mill s
Source: Earthqualizer Global Palm Oil Mill List Database (2026)
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based measurements reported average methane releases of about 114 kg CH₄/hour and 315 kg CH₄/hour per pond, while the broader literature places typical POME pond emissions in roughly the 100- 450 kg CH₄/hour range (Valverde, et al., 2024) . De-risking Capex and precision engineering On paper, operators rely on theoretical models that use static annual averages and fixed conversion factors and ignore real-world venting losses. In reality, POME
Figure 2 Geospatial mapping of POME treatment infrastructure
Source: Inovasi Digital analysis (2026)
Finding the invisible asset: Orbital monitoring of POME emissions Extracting crude palm oil is a water-heavy process. For every metric tonne of crude palm oil produced, mills discharge about 2.5-3.0 tonnes of 80-90°C POME. It carries massive organic loads, with chemical oxygen demand (COD) concentrations topping 50,000 mg/L and biological oxygen demand (BOD) exceeding 25,000 mg/L (Wang, et al., 2015) . Standard industry practice routes this waste into open, unlined cooling and anaerobic digestion lagoons. Deep within these oxygen-starved ponds, microbes break down the organic material, releasing a heavy stream of biogas – mostly methane (55-65%) and CO 2 (35-45%). When these lagoons are uncontained, the generated biogas simply bubbles to the surface and vents freely into the air. For decades, the industry has relied on estimates to calculate these emissions. Default emission factors from standard frameworks assume every mill vents a static volume of methane per tonne of fruit. However, real-world operations tell a different story. Operational parameters like hydraulic retention time, pond depth, organic loading rates, seasonal temperatures, and sludge build- up cause huge swings in actual emissions compared to theoretical models. Published field studies illustrate this variability: chamber-
ponds are highly dynamic systems shaped by ever-shifting hydraulic retention times, fluctuating organic loads, and variable microbial activity. Bridging this gap between desktop calculations and physical reality requires moving from rough estimates to direct atmospheric measurement via orbital verification. Modern imaging spectrometers mounted on Earth-observation satellites utilise shortwave infrared (SWIR) sensors to track atmospheric gas concentrations. Since methane absorbs electromagnetic radiation at specific wavelengths in the SWIR spectrum (around 1.6 µm and 2.3 µm), these space-based sensors pinpoint elevated methane plumes as soon as they rise above ambient levels (Jacob, et al., 2022) . Satellite observations also have practical limits: usable measurements depend on sensor sensitivity, revisit frequency, atmospheric conditions, and surface reflectance, and some POME sources can fall below the detection threshold of current spaceborne instruments (Valverde, et al., 2024) . High-resolution point-source satellites home in on individual processing facilities to pinpoint exact plume locations, while wide-area constellations track how emissions fluctuate across peak harvest seasons (see Figure 2 ). By pairing orbital spectral readings with local ground data – such as mill processing rates, wastewater discharge volumes, and
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Design methodology comparison for POME biogas infrastructure
Engineering parameter Primary feedstock data
Conventional estimation Default emission factors and operating assumptions Often based on annual or periodic
Satellite-informed assessment
SWIR plume observations combined with ground and operating data where available Can provide repeated observations that reveal temporal and seasonal variability, subject to satellite revisit and detection conditions Observed emission patterns can improve site-specific gas yield assumptions, but engineering design still requires ground and process data Time-series evidence can support more representative load assumptions and operating scenarios Better site-specific evidence can reduce uncertainty in sizing and strengthen Adds independent empirical evidence that can strengthen technical due diligence; it does not replace engineering validation or lender requirements investment planning
Time resolution
averages
Digester and engine sizing
Sizing based on modelled gas yield; uncertainty can lead to conservative
design margins
Parasitic load optimisation
Typically based on expected
operating ranges
Capex efficiency
May require larger uncertainty buffers where feedstock and gas yield data
are limited
Financial due diligence
Relies mainly on modelled feedstock and gas production assumptions
Table 1
local weather – analytical platforms build a continuous, real-world emissions baseline. Instead of guesswork, facility managers and investors get audited numbers on true mass emission rates, turning what was once an unquantified liability into a transparent, actionable decarbonisation opportunity. Building industrial biogas capture and conversion systems is a significant investment. Installing a covered lagoon digester or a continuous stirred-tank reactor (CSTR) complex – complete with gas scrubbing, moisture removal, flare systems, and power engines – can cost millions of dollars. That scale of investment shows why precise engineering matters. If a biogas plant is designed around generic assumptions that overestimate actual gas output, the facility ends up over-engineered. Oversized reactors, gas holders, and combined heat and power (CHP) engines run below capacity, tanking efficiency and stretching payback periods. Conversely, if a system is undersized because paper calculations missed peak harvest loads, the digester gets overloaded. That leads to acidic souring, system instability, and forced emergency methane venting, defeating the point of the project.
Satellite data helps to solve this by delivering a verified, year-round timeline of actual methane output. Design engineers can track seasonal changes, map emissions directly against fruit processing volumes, and size infrastructure to match the true volumes of gas. The result is optimised capital spend and infrastructure that works for the volumes produced (see Table 1 ). This data is also relevant to project finance. Institutional lenders, infrastructure funds, and clean-tech investors need confidence in expected gas volumes before committing capital to long-term assets in emerging markets. Satellite-derived emissions profiles can strengthen project due diligence and financing confidence by adding independent evidence to engineering models and operational records. They should therefore be treated as a complementary input to bankable feasibility studies rather than a substitute for site-level engineering validation. Turning wastewater into power Once emissions are accurately measured and the right systems are in place, raw POME biogas becomes a valuable energy resource and income stream.
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However, accessing it requires more processing. Freshly captured biogas is saturated with water vapour and contains CO 2 alongside corrosive hydrogen sulphide (H₂S). Studies of POME-derived biogas report H₂S concentrations commonly in the low thousands of ppm. For example, Saputro and Sudibandriyo report approximately 1,500-3,000 ppm, reinforcing the need for gas cleaning before engine use or upgrading (Saputro & Sudibandriyo, 2020) . Processing and utilisation pathways for captured biogas u Raw wastewater intake: Liquid effluent is collected from milling operations and fed into a sealed anaerobic digester. v Biogas capture and conditioning : Raw biogas (CH₄, CO₂, H₂S, moisture) is scrubbed of corrosive H 2S and dried to protect downstream equipment. w Utilisation pathway A (on-site CHP power): Scrubbed gas powers engines to provide base- load electricity and steam for mill operations, replacing fossil diesel. x Utilisation pathway B (RNG upgrading): Gas undergoes membrane separation or pressure swing adsorption to achieve >95% purity CH₄ for pipeline injection or heavy transport fuel. Raw biogas must be treated before hitting downstream equipment. Biological or chemical scrubbers remove the corrosive H₂S, while chillers strip out moisture. Once purified, the gas follows one of two main value pathways: Pathway A: On-site CHP generation For energy-hungry applications like palm mills, generating power on-site is an immediate win. Mills require electrical power for heavy machinery and thermal energy (steam) for fruit sterilisation. A typical facility handling 60 tonnes of fruit per hour generates enough POME to power a 1.5-2.0 MW CHP engine. This allows the mill to remove expensive diesel generators, cutting Scope 1 carbon intensity and running costs. Waste heat harvested from the engine exhaust is fed back into mill operations, while excess electricity can be exported to local grids. Pathway B: Upgrading to renewable natural gas (RNG) Where facilities sit near gas pipelines or heavy
transport corridors, upgrading biogas to RNG opens even bigger markets. Stripping out CO₂ boosts methane purity above 95%, matching natural gas grid specifications. Industrial upgrading technology includes: • Membrane separation: Polymer membranes separate gas molecules under pressure based on permeability. • Pressure swing adsorption (PSA): Adsorbent media selectively binds CO₂ while releasing pure methane. • Water scrubbing: Uses high-pressure water washing to dissolve CO 2 . Upgraded RNG can be compressed (CNG) or liquefied (LNG) to fuel heavy truck fleets, creating a closed-loop transport ecosystem that displaces fossil diesel across the value chain. There is an additional advantage here for palm oil operators. By reducing diesel exhaust fumes, it can help to prevent mineral oil saturated hydrocarbons (MOSH) and mineral oil aromatic hydrocarbons (MOAH) contamination, keeping levels within legal limits. Verifying reductions for CSRD and CSDDD compliance While generating energy delivers solid operational return on investment (ROI), tighter regulation is largely driving faster corporate action. Voluntary Environmental, Social, and Governance (ESG) pledges are giving way to mandatory, financial-grade reporting mandates. Two key legislative acts are leading the way: • Corporate Sustainability Reporting Directive (CSRD): Mandates comprehensive disclosures on environmental impacts for thousands of companies operating in or exporting to the EU, requiring audited Scope 1, 2, and 3 footprints based on verifiable primary data. • Corporate Sustainability Due Diligence Directive (CSDDD): Requires large enterprises to actively identify, prevent, and mitigate environmental risks across their global supply chain, with heavy financial penalties for non- compliance. For companies buying palm oil, mill wastewater emissions represent a massive chunk of their supply-chain carbon footprint. Historically, downstream buyers relied on spend- based estimates and generic industry averages. Under CSRD and CSDDD, those vague
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proxies will no longer be acceptable. Space-based measurement, reporting and verification (MRV) gives corporations the proof they need. Satellite constellations provide independent, third-party verification that operates completely outside supplier self-reporting. Historical satellite data sets a clear pre-project baseline, while ongoing monitoring proves the methane plume has actually been eliminated (see Figure 3 ). This gives corporate buyers primary data for their financial filings, protecting them against greenwashing litigation and keeping them fully compliant with EU laws.
Figure 3 Regional atmospheric methane concentrations observed by Sentinel-5P, illustrating the potential of satellite monitoring to identify methane hotspots. Attribution to individual facilities and verification of emission reductions require complementary higher-resolution observations and ground-based measurements
Evolving beyond passive conservation Combining satellite remote sensing with smart wastewater engineering represents a major evolution in agricultural decarbonisation. For two decades, environmental interventions in tropical commodities focused almost entirely on land use through No Deforestation, No Peat, and No Exploitation (NDPE) frameworks. While protecting standing forests is vital, it is ultimately a passive conservation strategy. Preserving trees maintains terrestrial carbon sinks, but it does not actively abate the industrial emissions generated by processing operations day in and day out. To meet growing global demand sustainably, passive conservation must be paired with active industrial abatement. The technology behind methane capture – anaerobic digesters, gas scrubbers, and power engines – is mature and commercially proven. A persistent barrier has been the lack of consistent, site-specific emissions data across remote processing sites. Under incoming European mandates like CSRD and CSDDD, downstream corporate buyers can no longer rely on unverified spend-based proxies or self-reported estimates. They need audited, primary data.
For downstream buyers, combining land-use intelligence with mill-level methane evidence provides a more complete view of agricultural value-chain emissions, linking what happens on the land with what happens during processing. Space-based spectrometry solves this data vacuum. By tracking shortwave infrared absorption from orbit, satellites establish empirical emission baselines, de-risk Capex investment for developers, and provide lenders with bankable financial models. Continuous monitoring also gives corporate buyers unalterable proof that methane plumes have been physically eliminated. Satellite observations, when integrated with mill-level operational data and ground-based measurements, can help identify methane emission risks, strengthen the evidence base for biogas investment decisions, and support more credible monitoring of emission reductions across palm oil supply chains.
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Ihwan Rafina ihwan@ mosaix.earth
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Can lignin become a refinery feedstock? With targeted pretreatment and use of existing brownfield infrastructure, lignin could become a valuable renewable carbon feedstock for the refining sector
Simge Oğuz Ankara University, Department of Chemical Engineering Vahide Nuran Mutlu SOCAR Türkiye R&D and Innovation Co.
R efineries are built around carbon. The question is increasingly where that carbon comes from. As the refining and petrochemical industries look beyond fossil feedstocks, attention has increasingly turned to biomass-derived carbon that can be connected to existing industrial infrastructure. However, not all biomass streams are equally attractive to a refinery. Their composition, oxygen content, moisture, inorganic contaminants, and conversion requirements can determine whether they can be integrated into established processes or require an entirely new value chain. Lignin presents a different case. Unlike conventional aliphatic biomass, lignin provides an industrial-scale source of aromatic carbon with potential relevance to petrochemical infrastructure. Under appropriate cracking and upgrading conditions, its phenolic structure can be converted into aromatic and cycloalkane- rich products. This makes lignin a potential refinery feedstock, provided the challenges of conversion and integration can be addressed. When integrated into suitable catalytic conversion routes, lignin-derived streams can contribute to gasoline-range products, marine and middle-distillate fuels, and high-value aromatic building blocks for the petrochemical industry. By serving a broader product portfolio, lignin could therefore move beyond its traditional role as a source of process energy and become a potential feedstock for higher-value applications. The question, however, is how this carbon can be converted into a form that a refinery can process. Beyond the paper: The Kraft fibre economy To enable large-scale refinery integration,
securing a reliable lignin source is essential. Viewing this resource merely as a by-product of the printing paper industry does not capture the broader Kraft fibre economy. Kraft pulping supports a wide range of paper, packaging, paperboard, and fibre products, creating an established industrial basis for lignin generation. On a global scale, the pulp and paper industry generates approximately 50 million metric tons of Kraft lignin annually ( Bajwa, Pourhashem, Ullah, & Bajwa, 2019; Dessbesell, Paleologou, Leitch, Pulkki, & Xu, 2020 ). Currently, more than 98% of this lignin is burned on-site within “ When integrated into suitable catalytic conversion routes, lignin- derived streams can contribute to gasoline-range products, marine and middle-distillate fuels, and high-value aromatic building blocks for the petrochemical industry ” mill recovery boilers as black liquor to meet internal energy requirements for steam and power generation, leaving less than 2% isolated for non-energy applications ( Chio, Sain, & Qin, 2019 ). While internal combustion enables energy self-sufficiency, recovery boilers often represent the principal operational bottleneck for pulp production expansions ( Tomani, 2010 ). Consequently, extracting a portion of the lignin for downstream refining not only provides an abundant biogenic carbon stream, but also debottlenecks the recovery boiler, allowing pulp mill throughput to increase ( Tomani, 2010; Benali, Kouisni, & Paleologou, 2014 ).
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