Issuu

2026

A SUPPLEMENT TO HYDROCARBON ENGINEERING

STALLED...

Stuck isn’t the end for carbon capture projects. It’s where Black & Veatch starts.

LEARN MORE

CONTENTS EnviroTech 2026 Volume 03 Number 01 ISSN 1468-9340

03 Comment

35 Securing sulfur removal Mark Knobloch, Merichem Technologies, discusses how hydrogen sulfide removal in gas streams could play an important role in decarbonising downstream operations.

04 Energy resilience drives faster decarbonisation Global conflict throughout 2026 has upset traditional oil supply chains. Alan Gelder, Wood Mackenzie, considers how such turmoil has prompted growing diversification to secure energy resilience.

10 Moving from concept to industrial reality Sophia Asal, Endress+Hauser, Switzerland, and Adrian Kortmann, DACMA, Germany, explore the importance of measurement accuracy within the carbon removal market.

14 Choosing an e-SAF pathway Tamoor Mughal, Stanislav Jaso, and Chippla Vandu, Shell Catalysts & Technologies, the Netherlands, compare the Fischer–Tropsch and Methanol-to-Jet pathways to e-SAF production. Their analysis finds that, although energy efficiency and levelised production cost are broadly comparable, technology readiness and deployment risk may prove decisive in project selection.

22 Embedding sustainability into chemical manufacturing Increasing environmental demands are currently being placed on chemical manufacturers. Debanjana Chakraboty and Julia Panko, Honeywell Technologies, discuss how practices have been embedded at the Emmerich and Oberhausen sites in Germany, and the improvements made.

27 Challenges of chemical recycling Birendra Adhikari and Robert Rapier, Aduro Clean Technologies Inc., present a different approach for converting waste plastics to naphtha-cracker-ready feedstock, without extensive upgrades to petrochemical infrastructure.

31 Boosting economics while cutting emissions Igor Kostromin and Marie Vognsen, Topsoe, consider how sulfurous waste streams can be converted from a liability into a commercial asset.

39 Evaluating electrification José Miguel González, Tecam, considers the role that electrically heated oxidation systems could play within industrial emissions abatement.

41 Engineering electrification Domenico Marzocchi, Watlow, explores how process heat is moving closer to the centre of industrial decarbonisation strategies.

45 The role of fuel gas in decarbonisation As refiners consider decarbonisation of their assets, the options around fuel gas and disposal are a critical step in moving towards net zero. Michael Stockle and Richard Spires, Wood, look at how refinery fuel gas can become a key lever for decarbonisation and the various options to deal with fuel gas in such scenarios.

49 From hindsight to foresight Juan Ruiz and Michelle Wicmandy, KBC (A Yokogawa Company), discuss why industrial energy management is becoming forecast-driven and how this can optimise refinery operations.

53 Sustainability starts with reliability Nikolaj Fischer, Burckhardt Compression, looks at how the reliability and efficiency of essential assets, such as compressors, influence the sustainability of hydrocarbon operations.

57 Advancing valve performance Recent improvements in isolation, control, and pressure relief valves can reduce emissions and cost of ownership, while improving performance and longevity. Jean Paul Boyer, Oznur Celikkol, Jacqueline Onditi, and Sergio Zaghen, all from Emerson, explain.

61 The evolution of materials science Hydrogen and CCUS projects are exposing materials limitations in conventional downstream facilities. Kerry Drake and Philippe Allienne, Greene Tweed, discuss how organisations can use new developments in materials science to ensure longevity for future projects.

65 Gas analysis beyond compliance Rhys Jenkins, Servomex, discusses how gas analysis can drive performance and decarbonisation efforts in downstream operations. Direct Air Capture (DAC) is emerging as a promising carbon removal technology, but its commercial success depends on more than innovative capture systems alone. The article starting on p. 10 explores the engineering challenges of removing CO2 directly from ambient air, highlights DACMA’s modular approach to scaling DAC, and examines why accurate measurement and verification are becoming essential to the future of carbon removal.

JOIN THE CONVERSATION Follow

@HydrocarbonEng

Hydrocarbon Engineering

Join Hydrocarbon Engineering

Copyright© Palladian Publications Ltd 2026. 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. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK. CBP019982

Reaching a sustainable future is like kayaking. With a skilled partner, you can make the right decisions. Reaching a sustainable future is demanding in many ways. Obstacles and change must be well anticipated to make the right decisions. We are ready to tackle these challenges with you! We will help you to improve your processes to meet your ESG goals, operational optimization and sustainable manufacturing efforts. Let’s team up to improve!

Do you want to learn more? www.endress.com

CONTACT INFO MANAGING EDITOR James Little

james.little@palladianpublications.com SENIOR EDITOR Callum O'Reilly

callum.oreilly@palladianpublications.com ASSISTANT EDITOR Ellie Brosnan

ellie.brosnan@palladianpublications.com EDITORIAL ASSISTANT Olivia Smith

olivia.smith@palladianpublications.com SALES DIRECTOR Rod Hardy

rod.hardy@palladianpublications.com SALES MANAGER Chris Atkin

chris.atkin@palladianpublications.com PRODUCTION MANAGER Kyla Waller

kyla.waller@palladianpublications.com HEAD OF EVENTS Louise Cameron

louise.cameron@palladianpublications.com DIGITAL EVENTS COORDINATOR Merili Jurivete

merili.jurivete@palladianpublications.com

DIGITAL CONTENT COORDINATOR Kristian Ilasko

kristian.ilasko@palladianpublications.com

DIGITAL ADMINISTRATOR Nicole Harman-Smith

nicole.harman-smith@palladianpublications.com MARKETING & DIGITAL EXECUTIVE Sophie Birss

sophie.birss@palladianpublications.com ADMIN MANAGER Laura White

laura.white@palladianpublications.com

SUBSCRIPTION RATES Annual subscription £120

SUBSCRIPTION CLAIMS Claims for non receipt of issues must be made within 3 months of publication of the issue or they will not be honoured without charge.

APPLICABLE ONLY TO USA & CANADA Hydrocarbon Engineering (ISSN No: 1468-9340, USPS No: 020-998) is published monthly by Palladian Publications Ltd GBR and distributed in the USA by Asendia USA, 701C Ashland Avenue, Folcroft, PA 19032. Periodicals postage paid at Philadelphia, PA & additional mailing offices. POSTMASTER: send address changes to HYDROCARBON ENGINEERING, 701C Ashland Ave, Folcroft PA 19032.

15 South Street, Farnham, Surrey GU9 7QU, UK Tel: +44 (0) 1252 718 999

2026

A SUPPLEMENT TO HYDROCARBON ENGINEERING

COMMENT CALLUM O'REILLY SENIOR EDITOR

elcome to the 2026 edition of Hydrocarbon Engineering’s EnviroTech supplement, which is released following a turbulent year for global energy markets. Conflict in the Middle East – and the accompanying shortfall of oil and gas – has placed energy security and affordability firmly in the spotlight. Geopolitical instability has underlined the importance of reliable energy supplies, while industrial operators continue to face pressure to reduce their environmental impact. For refineries, gas processing facilities, and petrochemical plants, these priorities are closely connected: energy efficiency, process optimisation, and emissions reduction can all contribute to more resilient and competitive operations. Improving the performance of existing assets remains an important part of the decarbonisation equation, as does exploring new technologies, processes, and pathways to lower-carbon operations. This issue of EnviroTech brings together detailed technical articles and case studies examining how these ambitions are being translated into practice, from established approaches and operational improvement to emerging technologies and solutions shaping the future of the downstream sector. We explore energy efficiency improvements and emissions reduction, equipment maintenance and reliability, electrification, the role of hydrogen and carbon capture and storage, as well as carbon dioxide removal technologies (and the importance of measurement accuracy). You will also find articles looking at different pathways to SAF production, methods to embed sustainability into chemical manufacturing, and the challenge of converting waste plastics to naphtha-cracker-ready feedstock, without the need for extensive upgrades to petrochemical infrastructure. And given the tumultuous events of this year, this issue begins with a detailed report from Wood Mackenzie, outlining how conflict in the Middle East has promoted energy resilience, which drives faster decarbonisation in the downstream sector. The piece, authored by WoodMac’s VP of Refining, Chemicals & Oil Markets, Alan Gelder, guides us on the growing role of liquid renewables to satisfy transport fuel demand, and how the refining sector needs to adapt to this change. It also explores how decarbonisation of the downstream sector is not only about reducing the carbon intensity of transport fuels – it is also vital to reduce carbon emissions from downstream operations. Gelder outlines how downstream decarbonisation is a complex equation, with success requiring parallel adoption of several technologies. Progress will ultimately depend on combining incremental improvements to existing processes with targeted investment in new technologies, supported by robust measurement of emissions. Collaboration between governments, operators, engineering companies, and technology providers will be essential to turn promising innovations – such as those outlined in the pages of this issue – into practical, scalable solutions.

Global conflict throughout 2026 has upset traditional oil supply chains. Alan Gelder, Wood Mackenzie, considers how such turmoil has prompted growing diversification to secure energy resilience.

026 has been a tumultuous year for the oil value chain. The prices of crude oil and refined products are materially higher this year due to ongoing conflicts in both the Middle East and Russia-Ukraine. During August 2026, Dated Brent was near US$100/bbl, far higher than the prior year but still below the peak monthly average price of over US$120/bbl reached in April 2026. Diesel and jet fuel wholesale prices are close to their April 2026 highs from the record product premiums over crude prices (crack spreads) that are necessary for the available refining system to run flat out. The Russia/Ukraine conflict has now lasted longer than World War One. Ukraine has been successfully targeting Russian energy infrastructure over recent months. As of the end of August 2026, over 3.5 million bpd of Russian refining capacity is unavailable due to drone strikes and Russia has declared an exports ban of refined products until early 2027. The 800 000 bpd of diesel/gas oil that Russia would typically export to the global market is no longer available. Both oil and refined products are further impacted by the US/Iran conflict. The Strait of Hormuz was a key export route for both crude oil and refined products. Export flows have

been restricted for the past six months, draining global crude and refined product inventories, supporting higher prices. As of mid-August 2026, Figure 1 shows the blockade by both Iran and the US to be more porous than the initial stage of the conflict, as oil production cuts by Gulf producers are estimated to be around 6 million bpd. Global oil demand has fallen but has not yet reached the levels where it matches the loss of global supply. Asian refiners struggle to secure crude oil feedstock, and many Asian nations have curtailed refined product exports to manage their oil and refined product inventories, therefore tightening supplies to deficit markets in Europe and Africa. The resolution of the Middle East conflict does not look imminent. After the global pandemic and the Russia/Ukraine conflict, the oil value chain is suffering yet another supply shock. Growing diversification is the typical consequence of a supply shock, either in sources of supply or a shift in demand to alternative energy sources. Energy resilience is now a critical topic for policymakers in fossil fuel importing countries given the high energy prices and concerns of future security of supply. Many nations are looking at greater use of domestic resources to reduce their import dependence.

26 5

contain oxygen as part of their chemical structure (ethanol for gasoline and Fatty Acid Methyl Esters) typically have maximum blending limits. Biological materials such as plant-based oils, animal fats, and waste cooking oils can be hydroprocessed to produce high-quality distillates that have no such blending limits. Figure 2 shows the almost linear relationship between the yield of renewable diesel (RD or HVO) to its gross product worth (GPW) across both Europe and North America. Refinery based co-processing of vegetable oils is commercially attractive for refiners and such Growing role of liquid renewables an approach typically provides a low capital means to comply Liquid renewables have played a significant role in road with the liquid renewable blending requirements. transport fuels for many years, with the US Renewable Fuel The role of liquid renewables is heavily dependent on Standard (RFS) first coming into existence in 2005, though policy support, as production costs continue to exceed those reformulated gasoline was part of the Clean Air Act from of fossil fuels, even in the current high-price oil environment. 1990 onwards. Europe’s Renewable Energy Directive was Against the backdrop of the current geopolitical established in 2009, and it is now on version 3. These environment, countries increasingly view liquid renewables as regulations, typical of many others that followed, require a strategic tool to reduce dependence on gasoline and diesel liquid renewables to become a growing fraction of the imports, strengthen energy security, and support domestic transport fuel sold to consumers. Benefits include air quality industries. This has driven higher blending mandates across improvements and decarbonisation in addition to key producers in Asia (Indonesia, Malaysia, Thailand, and diversification of supply and support for the regional Vietnam), with Indonesia targeting a 50% biodiesel mandate, agricultural sector. which would eliminate its imports by the early 2030s. In The introduction of liquid renewables to transport fuels Latin America, easing inflationary pressures have added requires the refining sector to adapt. Biocomponents that momentum to higher mandates across Argentina, Brazil, Paraguay, and Guatemala. Across the EU, member states continue to advance the implementation of RED III, albeit with delays, with policy increasingly focused on more Figure 1. Production cuts for Gulf producers as of 16 August 2026. Source: Wood Mackenzie stringent High Frequency Oil Production Monitor. emissions targets and tighter eligibility criteria for feedstocks. In the US, the RFS ‘Set 2’ rule for 2026 - 2027 sets the highest renewable fuel volume obligations in the programme’s history, raising the total renewable fuel obligation from 22.33 billion RINs in 2025 to nearly 26 billion by 2027. Figure 2. Role of renewable diesel in refinery GPW across selected Europe and North America Biomass-based refining sites (2024). Source: Wood Mackenzie Refinery Evaluation Model. diesel volumes In some locations, this is a reversion to coal in the power sector. For others, the focus has shifted to the opportunity for liquid renewables to take a growing role in satisfying transport fuel demand. Europe’s diesel and jet fuel imports rely on a globally well-supplied distillate market. Geopolitical supply disruptions expose Europe to the threat of shortages. The development of liquid renewable fuel projects across the region could be accelerated to mitigate this threat.

need to rise by more than 60% between 2025 and 2026, a trajectory that would bring currently idle US capacity back online and renew the draw on imports from Canada and Singapore (Figure 3). Wood Mackenzie’s analysis suggests the RIN balance will remain tight throughout 2026 and 2027, providing a supportive price environment during this period and offering meaningful tailwinds for the profitability of both biofuel producers and feedstock suppliers. Producers still need to be cautious as should a supply deficit materialise in 2027, the EPA could respond by issuing emergency waivers or, more likely, setting lower volume targets for the Set 3 rule (from 2028 onwards). Europe’s aggressive mandates for sustainable aviation fuel (SAF) will require high levels of imports – of either the SAF or the feedstock. European SAF and HVO producers are often significant consumers of China’s exports of used cooking oil (UCO). Chinese SAF exports to the EU have risen sharply since the start of 2026, primarily into Belgium, the Netherlands, and Spain, with a significant pipeline of SAF projects scheduled to come online in 2026 and 2027. As shown in Figure 4, Chinese supply will therefore become increasingly critical to the EU. China’s SAF rollout could have a direct impact on the EU’s ability to achieve its mandates. There is a risk that future constraints on UCO collection will drive China to divert its UCO exports towards domestic SAF production. This requires European producers to continue their journey of feedstock pool diversification through investment in pre-treatment units, whilst exploring new feedstocks and technology pathways for longer-term supply growth.

Figure 3. US biofuels imports, by type. Source: Wood Mackenzie Liquid Renewable Fuels Service.

Decarbonising operations Downstream decarbonisation is not only about reducing the carbon intensity of transport fuels. It is also about reducing the carbon emissions from downstream operations. As carbon prices rise, energy efficiency becomes increasingly critical for refineries to remain competitive; inefficient sites face the dual penalty of higher operating costs and increasing carbon liabilities. Optimising energy consumption remains one of the lowest-cost ways to protect margins, reduce emissions, and stay competitive in tougher market conditions. Figure 5 shows the typical distribution of refinery emissions and refinery decarbonisation options. Absolute energy consumption alone provides limited insight into refinery energy performance, so the analysis leveraged the PetroPlan simulation models to develop an Energy Intensity metric that normalises energy use for crude throughput and refinery complexity, measured by the Energy Complexity Index (ECI). This analysis shows that nearly 55% of global refineries perform above the

Figure 4. SAF installed capacity by country and China HEFA-SAF development. Source: Wood Mackenzie Liquid Renewable Fuels Service.

26 7

Figure 5. Decarbonisation options available for refiners (left) and typical distribution of refinery emission sources (right). For a typical refinery, the combustion process (including combustion in gasification and FCC processes) contributes close to 80% of site emissions. Source: Wood Mackenzie Refinery Evaluation Model. throughput weighted global average of 24 million Btu/000 bpd/ECI, indicating significant room for improvement. A modest 5 million Btu/000 bpd/ECI improvement in energy intensity could reduce typical operating costs by around US$1/bbl at pre-Middle East conflict utility prices and potentially reduce the emissions from global refineries by around 150 million tpy (around 18% of current global refining emissions). Interestingly, the less competitive refineries globally (in terms of net cash margin) generally exhibit higher Energy Intensity than average, reinforcing the need for continuous energy intensity improvements. To protect its domestic industrial base that is to be increasingly exposed to the full cost of their carbon emissions via the Emissions Trading Scheme (ETS), Europe is looking to implement a Carbon Border Adjustment Mechanism (CBAM). By imposing a carbon intensity tariff on refined product imports, the CBAM aims to correct for the difference between the cost of emissions paid by European producers and competing imports. The rising cost of carbon emissions provides an investment opportunity for exporters to the EU to decarbonise their operations to secure market access through lowering their CBAM tariff. Wood Mackenzie’s analysis of global distillate trade confirms CBAM implementation reduces the volume of US Gulf Coast (USGC) exports sold to Europe. The deployment of carbon capture utilisation and storage (CCUS) in the USGC abates carbon from hydrogen production and FCC flue gas (about 25% of the average USGC refinery’s emissions), therefore cutting the CBAM tariff by roughly 25%. Such an investment would restore trade to Europe, but not permanently as the CBAM’s tariff has two components: the product’s carbon intensity (CI), and the carbon price applied, net of any credit for carbon already priced in the exporting region. CCUS only addresses the first aspect so regions with their own (escalating) carbon-pricing become better placed to export to EU destinations. The EU ETS provides an incentive for decarbonisation of the petrochemical sector, as the carbon costs will directly hit producer margins. Bio-naphtha, a by-product of the HEFA 8

process, provides a shield against the cost of emissions, accompanied by the broader benefits of circularity. However, in the initial years, only premium brands where circularity is a USP to differentiate can share the costs with their consumers to drive initial adoption. A combination of greater availability of liquid renewable feedstocks and technology improvements are needed to decarbonise the petrochemical sector. Decarbonising the downstream sector is complex, for success requires parallel adoption of several technologies. Electrification, sustainable feedstocks, and circularity are interdependent, as the scale-up of SAF production is critical to supply more bio-naphtha.

Conclusions Changing aspiration for energy resilience and energy security will keep reshaping the pace and direction of downstream decarbonisation, not just its ambition. The Middle East and Russia/Ukraine conflicts are likely to linger long in the memory of policymakers, supporting investment in domestic and regionally diversified feedstocks for liquid renewables. Regulatory tightening will continue to outpace market economics. The US RFS ‘Set 2’ volumes, EU member states’ ambitions beyond RED III, and rising biofuel mandates across Asia and Latin America all point to structurally higher demand for liquid renewables, but with diversified feedstock capability. Aviation is set to become the primary growth vector for HEFA investment as road fuel obligations bite against a shrinking liquid pool, while petrochemical decarbonisation via bio-naphtha will remain reliant on premium-brand economics until costs fall further. On operations, energy efficiency will remain the lowest-cost decarbonisation lever available to refiners. CBAM will increasingly determine competitive access to the EU market, rewarding exporters who decarbonise their operations and operate in regions with their own rising carbon price. Governments must play an active role in driving technology development, overcoming the barriers introduced by regulatory requirements, capital availability, and industry adoption.

Energy security starts with seeing the whole value chain When disruption hits, its impact doesn’t stop at borders, commodities or assets Wood Mackenzie connects oil, gas, LNG, refining and petrochemicals in one framework, helping you see how changes anywhere affect markets everywhere Spot disruption early Connect the value chain Protect margins and security of supply Stress-test strategy with confidence

See the whole picture. Make better decisions. www.woodmac.com/winning-insights/chart-your-path-to-energy-security

Sophia Asal, Endress+Hauser, Switzerland, and Adrian Kortmann, DACMA, Germany, explore the importance of measurement accuracy within the carbon removal market.

s industries work toward net zero targets, attention is increasingly turning toward technologies capable of addressing emissions that are difficult or impossible to eliminate entirely. While energy efficiency, electrification, renewable power, and carbon capture at emission sources remain essential decarbonisation strategies, many climate scenarios indicate that carbon dioxide removal (CDR) technologies will also play a role in balancing residual emissions. Among the emerging carbon removal approaches, Direct Air Capture (DAC) has attracted significant interest. Unlike conventional carbon capture systems that remove CO2 from concentrated industrial exhaust streams, DAC extracts carbon dioxide directly from ambient air. The captured CO2 can then be permanently stored underground, used as a feedstock for synthetic fuels and chemicals, or applied in a growing range of circular carbon economy pathways. Beyond dedicated carbon removal projects, interest in DAC is also growing among refining and petrochemical companies, where captured CO2 could serve as a future feedstock for synthetic fuels, chemicals, and other carbon utilisation pathways that support the transition to lower-carbon operations. Realising this potential, however, will depend on the industry’s ability to deploy DAC at commercial scale while demonstrating that carbon removal can be achieved reliably, efficiently, and economically.

Overcoming the challenge of dilute CO2 concentrations The fundamental difficulty of DAC lies in the composition of the atmosphere itself. At roughly 420 ppm, carbon dioxide represents only a small fraction of ambient air. Capturing meaningful quantities of CO2 therefore requires enormous volumes of air to pass through capture systems while keeping energy consumption under control. To become commercially viable, DAC developers must successfully balance several competing objectives: n Maximising CO2 capture efficiency from air containing only trace concentrations of carbon dioxide. n Minimising energy consumption associated with air movement, adsorption, and regeneration. n Managing process conditions such as flow, temperature, pressure, and airflow under changing environmental conditions. n Ensuring scalability and operational reliability as systems move from pilot installations to industrial deployment.

26 11

Many modern DAC concepts rely on liquid solvents or solid sorbent materials that selectively adsorb CO2 from ambient air. Once saturated, the sorbent is regenerated through heat or pressure changes, releasing a concentrated CO2 stream that can be collected for storage or utilisation. The efficiency of this process depends not only on the adsorbent material itself but also on system design. Airflow management, flow and temperature control, pressure stability, and process integration all influence overall capture performance and operating costs. As a result, DAC increasingly represents a multidisciplinary engineering challenge spanning mechanical engineering, process engineering, materials science, and automation.

Instead of relying on a single large facility configuration, DACMA’s approach focuses on modular units that can be replicated and adapted according to project requirements. This strategy enables gradual scale-up while providing flexibility for deployment across different geographies and operating conditions. The modular philosophy has already moved beyond the development stage. DACMA is involved in international projects, including deployments in Brazil, demonstrating how DAC can be adapted to varying environmental conditions while maintaining process performance.

A modular approach to scaling carbon removal

While advanced adsorbents and innovative reactor design often attract the most attention, the success of DAC will depend equally on the ability to quantify performance. For DAC operators, every tonne of captured CO2 must be measured, documented, and verified. Investors, regulators, certification bodies, and carbon markets increasingly require transparent evidence that claimed removals accurately reflect operational reality. At DACMA, questions around measurement emerged early in the development process. Beyond understanding capture performance, the company needed reliable methods to quantify exactly how much CO2 was being removed from the atmosphere and how much energy was required to achieve those results. Recognising the importance of high-quality process data, DACMA collaborated with Endress+Hauser to establish a robust measurement concept supporting both process optimisation and performance verification. Accurate monitoring of CO2 flows, energy consumption, steam demand, and process conditions enables DACMA to evaluate capture efficiency, improve operational performance, and provide the traceable data increasingly required by investors, regulators, and future carbon removal certification schemes.

One company contributing to this transition from laboratory-scale development to industrial deployment is Hamburg-based DACMA GmbH. The company develops modular DAC systems designed to operate under a wide variety of climate conditions. Rather than relying on a single sorbent solution, the company has evaluated multiple adsorbent materials, assessing parameters such as CO2 loading capacity, adsorption and desorption kinetics, cycle stability, and long-term resistance to degradation under realistic operating conditions. This material characterisation supports the selection of sorbents best suited to specific applications and climate locations. A key element of this approach is the patented reactor design, which applies engineering principles from aerospace technology to optimise airflow distribution through the contactor. The objective is to achieve highly uniform airflow across the sorbent structure while minimising pressure losses, thereby maximising contact efficiency between air and adsorbent material without unnecessarily increasing energy demand for air conveyance. Such design considerations are particularly important in DAC, where large volumes of air must be processed to recover relatively small concentrations of CO2. The capture process itself follows a cyclic temperature-vacuum swing adsorption (TVSA) approach. During adsorption, CO2 from ambient air is selectively captured by the sorbent material. This is followed by an evacuation phase to remove residual air before heat and vacuum are applied to release a concentrated CO2 stream. The sorbent is then cooled and prepared for the next capture cycle.

Figure 1. The modular plant design supports flexible deployment and scale-up, enabling DAC capacity to be added wherever carbon removal is required.

Building confidence through measurement

Measurement throughout the DAC process Although CO2 quantification often attracts the most attention, successful DAC operation depends on a broader set of measurements to maintain stable operation and optimise energy consumption: n CO2 flow measurement provides accurate quantification of captured carbon dioxide for reporting, verification, and process optimisation. The greatest advantage of using a Coriolis flowmeter for this task is, apart from its accuracy, the fact that the measurement principle is independent of density, pressure, or temperature, and directly measures the required mass. Since reporting under statutory regulations (e.g. the EU Emission Trading Scheme) and carbon accounting are based on the mass of CO2 captured, a direct mass measurement provides verifiable, traceable values without the need for conversion assumptions. n Steam flow measurement helps operators determine the thermal energy required for sorbent regeneration and to assess overall process efficiency. In addition, measuring steam reliably is one of the more demanding tasks in a carbon capture plant, because steam is not a stable, single-phase

medium. Vortex flowmeters such as Proline Prowirl from Endress+Hauser are designed specifically to overcome these challenges. The energy content of steam depends directly on its pressure and temperature, which vary continuously along the regeneration cycle. As a multivariable device, Prowirl integrates temperature and (optional) pressure measurement. Robust level instrumentation supports the monitoring of utilities and process media throughout the plant. It ensures reliable monitoring of liquid sorbent/solvent inventory in storage and regeneration tanks, wash water and process water reservoirs, as well as utility media (e.g. steam drums and cooling water). This safeguards continuous, uninterrupted operation, prevents overfill or dry-run situations, and could support precise mass balancing of sorbent circulating through the capture-regeneration cycle. Condensate flow measurement enables energy balance calculations and identifies opportunities for heat recovery and utility optimisation. Temperature measurements are equally important. Adsorption and desorption cycles are highly dependent on thermal conditions, making temperature monitoring essential for optimising regeneration performance and minimising energy consumption. Pressure measurement provides further insight into airflow behaviour, system resistance, and equipment health. The differential pressure across filters or process steps indicate if the system is clogged. This measurement helps to indicate and monitor and shutdown before efficiency losses or a critical failure occurs.

Together, these measurements create the operational transparency necessary for efficient and trustworthy DAC operation. Rather than viewing instrumentation as a supporting component, many developers increasingly regard measurement infrastructure as an integral part of the carbon removal process itself. Reliable process data enables performance optimisation, predictive maintenance, improved energy management, and transparent reporting. For DAC operators, the importance of utility measurements is growing rapidly. Regeneration of sorbent materials typically represents one of the most energy-intensive steps within the process. Accurate steam and condensate measurements therefore provide critical insights into thermal efficiency, energy consumption, and operating costs. As carbon removal projects move toward commercial operation, understanding the relationship between captured CO2 and the energy required to achieve that removal will become increasingly important.

From process data to verified carbon removal Reliable measurement supports three critical objectives: n Operational optimisation through improved visibility of capture efficiency, energy performance, and equipment behaviour. n Performance verification by providing transparent evidence of the quantity of CO2 removed from the atmosphere.

Figure 2. The DACMA competence centre in the Hamburg port area, Germany, will be inaugurated in the autumn of 2026.

Figure 3. Reliable instrumentation ensures real-time process insights and billing accuracy. n Commercial and regulatory compliance through support for carbon accounting, certification frameworks, and future carbon credit markets. This is where measurement transitions from a process requirement to a strategic business enabler. Together, the technology developer and measurement partner illustrate an important principle for the emerging carbon removal industry: climate impact must not only be achieved, it must also be demonstrated.

The path forward The future of DAC will depend on more than capturing larger quantities of carbon dioxide. The industry must also demonstrate that carbon removal can be measured accurately, verified independently, and scaled economically. Companies such as DACMA are helping advance the engineering capabilities needed to make DAC commercially viable, while partnerships with technology providers such as Endress+Hauser help establish the transparency and accountability required to build confidence among regulators, investors, and customers alike. As the carbon removal market continues to mature, measurement accuracy will increasingly become a competitive differentiator. In an industry built on quantified environmental impact, trusted process data may ultimately prove just as important as the carbon capture technology itself.

26 13

Tamoor Mughal, Stanislav Jaso, and Chippla Vandu, Shell Catalysts & Technologies, the Netherlands, compare the Fischer–Tropsch and Methanol-to-Jet pathways to e-SAF production. Their analysis finds that, although energy efficiency and levelised production cost are broadly comparable, technology readiness and deployment risk may prove decisive in project selection.

ischer–Tropsch (FT) and Methanol-to-Jet (MtJ) are the two most-studied pathways for producing synthetic aviation fuel (e-SAF) from renewable (green) hydrogen and captured carbon dioxide (CO2). Existing studies1, 2 and the analysis presented here suggest that the two routes are broadly comparable in terms of energy efficiency and levelised production cost. The key differentiators therefore lie elsewhere; this article examines FT and MtJ through the lens of two factors that can influence commercial deployment – technology readiness and deployment risk. The relevance of these factors is heightened by the EU’s ReFuelEU Aviation regulation, which introduces an e-SAF mandate from 2030. This is expected to create demand for approximately 0.5 million tpy of e-SAF by 2030, increasing fourfold by 2035. Although technology readiness and deployment risk do not replace energy efficiency or levelised production cost as decision criteria, they help project developers assess the relative deployment prospects of each route and identify the pathway that best fits their project objectives, location, and route to market. On that basis, FT currently offers the clearer near-term deployment case, whereas MtJ’s potential flexibility will likely depend on project-specific conditions and assumptions that need to be tested in practice. Drawing on Shell’s experience in developing, designing, constructing, and operating FT-based gas-to-liquids (GTL) facilities, including Pearl GTL, which produces 6 million tpy of products, this article compares the two pathways from process modelling and practical deployment perspectives.

26 15

The developing project landscape provides useful context for this comparison. Figure 1 shows that, according to independent tracking by T&E, a European non-profit focused on clean transport and energy, most announced commercial e-SAF projects – that is, projects beyond pilot-scale demonstration – are currently based on the FT pathway.

Figure 1. Announced e-SAF projects by technology pathway. Note: Mt = million tonnes.

FT pathway overview In the FT pathway, syngas is converted in an FT reactor into long-chain hydrocarbon waxes. These waxes are then upgraded through hydrocracking, isomerisation, and distillation to produce jet-fuel-range hydrocarbons and other coproducts. Syngas can be produced either by combining renewable hydrogen from water electrolysis with captured CO2, yielding e-SAF, or through biomass gasification, yielding bio-SAF. The FT route benefits from decades of industrial experience, proven commercial deployment, an established ASTM certification for FT-derived synthetic paraffinic kerosene and the production of high-quality paraffinic fuels, making it one of the more mature pathways for e-SAF production. First developed in the 1920s and commercialised in the 1930s and 1940s, FT technology has accumulated nearly a century of operating, research, and development experience across coal-to-liquids, GTL, and sustainable fuel applications. The FT-based power-to-liquids (PTL) process is summarised in Figure 2.

MtJ pathway overview In the MtJ pathway, renewable (green) hydrogen and CO2 are first converted into methanol (MeOH), either directly or

Figure 2. FT-based pathway for e-SAF production. Other configurations are possible, such as biomass-to-liquids (BTL) for bio-SAF production.

Figure 3. One possible direct methanol synthesis-based pathway for e-SAF production. Other configurations are possible, including for bio-SAF production.

via an intermediate syngas step. The methanol is then transformed into jet-fuel-range hydrocarbons through a sequence of methanol-to-olefins (MTO), olefin oligomerisation, hydrogenation, and distillation processes. The route benefits from the commercial maturity of methanol synthesis and MTO technologies, as well as the logistical flexibility offered by methanol as an intermediate that can be produced, transported, and upgraded at different locations. However, the olefin oligomerisation step remains less mature in this e-SAF application and plays a critical role in determining product yield and quality. This is a key consideration in assessing the technology readiness and scalability of the MtJ route for e-SAF production. A direct methanol-based pathway for e-SAF production is shown in Figure 3.

Table 1. Overview of process simulation scenarios developed Pathway

Process line-up

Products

Kerosene selectivity (mass basis)

Base – no naphtha recycle

Kerosene, naphtha

84%

Naphtha recycle

Kerosene

100%

MtJ

Direct route

Kerosene, naphtha, diesel

80 - 90%

MtJ

Indirect route

Kerosene, naphtha, diesel

80 - 90%

Side-by-side comparison To compare the FT and MtJ pathways on a like-for-like basis, process simulations were developed for e-SAF facilities producing approximately 100 000 tpy of total liquid products. Multiple configurations were assessed, including FT with and without naphtha recycle, and MtJ cases Figure 4. Energy efficiency comparison of the FT and MtJ assuming 80% and 90% kerosene selectivity. pathways on a SAF basis. The results show that FT and MtJ deliver broadly similar performance. MtJ exhibits slightly higher energy efficiency in most cases, while FT benefits from improved efficiency when naphtha is recycled to maximise kerosene production. However, these differences are relatively small and consistent with values reported in the literature.2 Levelised production cost was also found to be broadly comparable across all configurations. In both pathways, the electrolyser represents the largest capital investment, whereas electricity consumption is the dominant operating cost, accounting for most of the total operating expenditure. Consequently, project economics are driven more by renewable power and Figure 5. Levelised production cost for the FT and MtJ pathways. hydrogen costs than by the choice of conversion pathway itself. The similarities in efficiency and cost are not unexpected. Technology readiness should not be Both routes start from the same feedstocks – renewable underestimated hydrogen and captured CO2 – and ultimately produce similar Although FT and MtJ appear closely matched across hydrocarbon products. The key differentiators lie not in efficiency and cost metrics, a divergence emerges in thermodynamics, but in reaction kinetics, product selectivity, technology readiness – an area that can be decisive at process integration, and technology readiness. FT benefits from commercial scale. predictable product distributions and extensive commercial Both pathways rely on the production of a syngas operating experience. By comparison, MtJ offers greater intermediate which is further converted to e-SAF. For FT, syngas flexibility through its methanol intermediate but relies on production relies on the reverse water gas shift (RWGS) process, less-mature oligomerisation technology and less-established whose level of technology readiness varies. High-temperature product selectivity assumptions. The simulation model autothermal reforming (ATR) and partial-oxidation-based scenarios are presented in Table 1, and energy efficiency and systems are commercially established, while electrically heated levelised production cost are shown in Figures 4 and 5. RWGS variants represent a newer technology class. The choice between FT and MtJ is unlikely to be decided Although electrically heated RWGS is generally considered the by these headline metrics alone. The more meaningful most novel step in the FT pathway, extensive technology differences emerge when the pathways are assessed in terms development and de-risking activities, including more than of technology readiness and deployment risk. 10 000 hours of successful operation in pilot facilities,

26 17

Electrolyser

Reverse water gas shift (RWGS)

CO2 removal (amine-based)

Partial oxidation gasifier

Fischer–Tropsch synthesis

Wax hydroconversion (including distilation)

Assigned TRL

TRL justification

Deployed in industry though not widely at scale required

Prototype demonstrated and deployment ready

Industry standard technology. Commercially deployed

Commercially deployed with proven track record

Biomass drying and torrefaction

Biomass milling and gasification

Syngas shift

CO2 removal

Assigned TRL

7–8

8–9

TRL justification

Deployed at small scale with proven record of continuous operation

Industry standard technology based on coal gasification. Commercially deployed

Industry proven and commercially deployed technology

Industry standard technology. Commercially deployed

Figure 6. TRLs of the FT pathway steps for both e-SAF and bio-SAF. RWGS TRL shown is for advanced electrically heated reactor design.

Figure 7. TRLs of the MtJ pathway steps for both e-SAF and bio-SAF. Oligomerisation TRL shown is for heterogeneous oligomerisation technology using a mixed ethylene-propylene feed.

have demonstrated its robustness and readiness for commercial deployment.3 Importantly, some electrically heated RWGS configurations benefit from common design features and, in some cases, operational similarity to FT reactor systems, supporting eventual scaleup pathways. Like for FT, most MtJ process steps have a high technology readiness, with the exception of mixed olefin oligomerisation, which has not yet been deployed on a commercial scale. Consequently, the key uncertainty and principal technology risk with the MtJ pathway is associated with the olefin oligomerisation step. Figures 6 and 7 compare the technology readiness levels (TRL) of the FT and MtJ pathways. Although oligomerisation is well established in petrochemical applications, such as the conversion of ethylene to linear alpha olefins, SAF-relevant oligomerisation of mixed ethylene-propylene feeds is less mature. The need to accommodate mixed and heavier olefin streams introduces additional complexity, often requiring intermediate cracking or multistage processing to achieve the desired C9+ product range distribution. Competing process designs, such as feed separation prior to oligomerisation or staged conversion strategies, remain at early commercial or non-licensable stages. Unlike for FT, there are currently no fully integrated, commercially operating MtJ plants demonstrating SAF 18

production with validated oligomerisation performance and product selectivity. SAF-specific yield distribution remains unproven at scale, and catalyst and process robustness for mixed olefin feeds is still unresolved. As a result, whereas FT faces a defined scaleup challenge in RWGS integration, MtJ carries deeper process uncertainty at its core conversion step. The oligomerisation stage therefore represents a material risk factor for near-term deployment, despite the pathway’s otherwise favourable thermodynamics and system-level performance. A summary of current MtJ oligomerisation technologies is provided in Table 2.

Deployment risk: flexibility vs integration Beyond technology readiness, project developers also need to consider how each pathway affects deployment risk. One important difference is the trade-off between an integrated production route and a more flexible, potentially distributed model. The FT pathway is typically configured as an integrated production train, where syngas generation, FT synthesis, and downstream product upgrading are co-located. The Pearl GTL plant exemplifies this approach, integrating syngas production (from natural gas feed), FT synthesis, and product upgrading within a single facility, with the ability to produce a range of

Production processes, above all, must be safe, reliable and efficient. With our level and pressure measurement technology, you get exactly that. Durable sensors and accurate measured values make your work smarter, easier and more sustainable. Everything is possible. With VEGA.

vega.com

AI-generated image

We don’t wait for the future. We make it.

Table 2. Summary of MtJ oligomerisation technologies Oligomerisation Description technology

Product range

Relative technology readiness

Mixed ethylenepropylene feed

Two-stage oligomerisation. In the first stage, the feed is converted to lower-molecularweight oligomers. In the second stage, butenes and short oligomers are converted to higher-molecularweight oligomers

C9+ olefins, which are further hydrogenated to produce naphtha, kerosene and diesel range products

Licensed by third parties, but with no known commercial deployment for SAF production

Ethylene and propylene separated before oligomerisation

Two-stage oligomerisation. In the first stage, ethylene is oligomerised to produce C4+ olefins. In the second stage, the C4+ olefins are combined with propylene and further oligomerised

Not available for C9+ olefins, which are further licensing hydrogenated to produce naphtha, kerosene, and diesel range products

Table 3. e-SAF technology pathways summary Pathway technology readiness

FT pathway

MtJ pathway

High

Medium-high

Technology integration High in an operational environment

Medium

Capital intensity

High

Product quality

High

Good (but evolving)

Hub-and-spoke logistics model

Not feasible

Feasible (but with unproven economics)

Intermediate product valorisation

FT wax (syncrude) could be valorised as a product

Methanol can be valorised as a product

Overall ranking

Offers a strong basis for lower-risk near-term e-SAF deployment, though cost reductions will be required for project deployment

Also offers project deployment opportunities but currently limited by mixed-feed oligomerisation technology

products including kerosene, gasoil, and base oils. This arrangement supports efficient heat and mass integration, improving both energy and capital efficiency and, for an e-SAF plant, the direct conversion of hydrogen-derived and CO2-derived syngas into liquid hydrocarbons. In contrast, the MtJ pathway enables decoupling of methanol production from downstream SAF synthesis. This opens up the possibility of a hub-and-spoke model, in which e-methanol is produced in smaller, modular plants located near low-cost renewable hydrogen and CO2 sources, then transported to a central hub for conversion into jet fuel. In principle, this offers scope for phased investment, improved siting flexibility, and the ability to leverage emerging global methanol infrastructure. However, these advantages are not guaranteed. Decoupling can introduce efficiency penalties by preventing full process integration, and the logistics of transporting methanol – which contains a high oxygen content, at around 50 wt% – are not trivial. Alternatives such as converting methanol to dimethyl ether (DME) prior to transport may mitigate some 20

challenges but would require pressurised handling because DME is gaseous under ambient conditions. The commercial value of the hub-and-spoke model also depends on whether e-methanol has a clear alternative outlet or premium market. Overall, while FT prioritises integration and process efficiency within a single facility, MtJ trades this for potential logistical and deployment flexibility, the benefits of which depend strongly on system design choices and infrastructure constraints.

Conclusion

Both FT and MtJ offer credible routes for producing e-SAF, and the analysis presented here shows that they are broadly comparable on energy efficiency and levelised production cost. The choice between them is, therefore, unlikely to be decided by headline performance alone. Table 3 summarises the two pathways against key comparison criteria. For project developers, the more meaningful differences lie in technology readiness and deployment risk. FT benefits from proven commercial deployment of its core conversion technology, whereas MtJ offers potential flexibility through the methanol intermediate but still faces questions around mixed olefin oligomerisation. Importantly, this comparison reflects the technology choices available today, under which FT and MtJ display broadly similar techno-economic performance. In both pathways, however, hydrogen production via water electrolysis is the dominant cost element. Thus, overall economics are driven more by syngas generation costs than by the downstream conversion technologies. Looking ahead, next-generation syngas production technologies, including solid oxide electrolysis cells (SOEC) and co-electrolysis (co-SOEC) could be applied to both pathways for their potential to reduce hydrogen production costs, thereby further improving the competitiveness of e-SAF. There may be differences between FT and MtJ with respect to how they benefit from breakthroughs in syngas manufacturing. Ultimately, the preferred route will also depend on project-specific factors such as location, feedstock access, integration opportunities, route to market, and investment priorities. However, for projects seeking a lower-risk route to near-term e-SAF deployment, FT currently offers the stronger basis for commercial confidence.

References 1.

EYBERG, V., DIETERICH, V., BASTEK, S., DOSSOW, M., SPLIETHOFF, H., and FENDT, S., ‘Techno-economic assessment and comparison of Fischer-Tropsch and methanol-to-jet based sustainable aviation fuel production integrated with carbon capture’, Energy Conversion and Management, Vol. 315, (September 2024). BUBE, S., BULLERDIEK, N., VOß, S., and KALTSCHMITT, M., ‘Kerosene production from power-based syngas – A technical comparison of the Fischer-Tropsch and methanol pathway’, Fuel, Vol. 366, (15 June 2024). DE, S., SHAH, N., VAN BAVEL, S., and VANDU, C., ‘Benchmarking reverse water gas shift archetypes for eSAF production,’ Hydrocarbon Processing, (May 2026).

What’s ne t? This. e-SAF. Bio-SAF. One flexible platform. Imagine producing Sustainable Aviation Fuel (SAF) from a wide range of lowcarbon feedstocks – with an integrated process built around Shell’s commercially proven Fischer–Tropsch technology.

This isn’t technology from a standing start. The Shell XTL process builds on decades of Shell Fischer–Tropsch experience. Let’s go shell.com/xtl

Increasing environmental demands are currently being placed on chemical manufacturers. Debanjana Chakraboty and Julia Panko, Honeywell Technologies, discuss how practices have been embedded at the Emmerich and Oberhausen sites in Germany, and the improvements made.

he chemical industry is undergoing a period of rapid transition. Expectations from regulators, customers, and investors continue to rise, driving organisations to reduce carbon emissions, minimise waste, and enhance resource efficiency. While many companies have set ambitious targets, fewer have demonstrated how these commitments translate into practical, site-level change within complex manufacturing environments. This article will explore how this transition can be achieved in practice. Honeywell Technologies’ German sites at Emmerich and Oberhausen show how sustainability can be embedded into daily decision making, long-term capital planning, and operational culture in a way that advances both performance and resilience. These achievements reflect how broader sustainability priorities, which span climate, nature, circularity, safety, and diversity, are underpinned by science-based targets including a 44% cut in Scope 1 and 2 emissions by 2030 and a 90% reduction across Scopes 1, 2, and 3 by 2040. These two sites provide a compelling demonstration of how strategic intent, operational discipline, and cross-functional collaboration can come together to drive real progress in the chemical sector.

A foundation built on governance and accountability Honeywell Technologies operates within environmental management frameworks across all sites, with 92% of its manufacturing locations certified to ISO 14001. The Emmerich and Oberhausen sites also hold ISO 50001, demonstrating their commitment to continuous energy performance improvement, as shown in Figure 1. This robust governance structure has created a culture that values data accuracy, collaboration, and

long-range thinking. It has also supported site-level roadmaps aligned with groupwide goals, including targets to reduce hazardous waste by 50% and net water intensity by 30% by 2030. These overarching ambitions provide clear direction while giving operational teams the space to innovate.

Integrating sustainability into capital planning One of the most significant strengths of the German sites is their approach to capital expenditure. Rather than treating sustainability as an afterthought, Emmerich and Oberhausen embed energy, waste, and process efficiency considerations into project scoping from the beginning. Cross-functional collaboration between project engineers, energy teams, and waste leads is a formalised expectation rather than an informal practice. Emmerich’s replacement of an ageing gas-heated calciner (Figures 2 and 3) illustrates the impact of this approach. Instead of commissioning a like-for-like replacement, the team undertook a full assessment of duty requirements, energy demand, and waste outputs. This resulted in the installation of an electric calciner powered by renewable electricity, reducing energy use by 70%, eliminating fossil gas consumption, and cutting the site’s Scope 1 and 2 emissions by more than 10%. The dismantling of the old calciner also became a circularity exercise, with approximately 95% of the material recycled and only a small proportion categorised as hazardous waste. This approach not only reinforced a commitment to circularity and resource recovery but also generated an additional benefit of more than €10 000 through material returns. Oberhausen’s work to replace an old turbine dryer (Figure 4) followed a similar pattern, combining

26 23

process testing, supplier engagement, and energy optimisation. The decision to transition to an electrically powered system is expected to save up to 30% in energy demand while reducing carbon emissions by more than 400 tpy. Enhanced process control also achieved a 30% reduction in hazardous waste. The project secured financial support through a national grant for energy and resource efficiency, supported by wider European decarbonisation incentives that encourage industry to adopt advanced, low-carbon technologies. A key challenge during the project was the safe and clean removal of the old turbine dryer. Through meticulous planning, Figure 1. Energy consumption reductions at Emmerich and Oberhausen, strategic enclosure, and thorough demonstrating year-on-year improvements following ISO 50001 implementation. pre-cleaning of hazardous residues, the team dismantled the equipment without disrupting ongoing production, demonstrating commitment to safety, operational continuity, and environmental responsibility. By carefully separating materials, the site reduced hazardous waste to just 2% and achieved cost savings of approximately €5000. The new electric drying plant at Oberhausen has been designed with a strong focus on EHS, sustainability, energy consumption, and overall equipment effectiveness (OEE). These projects demonstrate a key message for the chemical Figure 2. Schematic overview of the calciner replacement assessment industry: sustainability delivers its undertaken at Emmerich. greatest value when integrated at the point of design. Early analysis reduces long-term operating costs, improves system resilience, and ensures capital investments remain aligned with tightening regulatory and market expectations.

Continuous improvement embedded in daily operations

Figure 3. Segregation and recycling of calciner components, illustrating 95% material recovery achieved by the Emmerich site.

Large capital projects provide step changes, but operational excellence requires continual refinement. Both German sites exemplify a mindset that prioritises incremental improvements supported by accurate data. At Emmerich, hydrogen is used as a reducing agent in the production process. Through careful optimisation, the site reduced hydrogen consumption and associated cost by more than 20%, cutting upstream Scope 3 emissions by approximately 250 t and delivering cost savings of more than 20% compared with historic production. Waste management is another area where disciplined processes can deliver tangible results. Instead of relying on

Consolidated and Continental Disc TM

Advancing Performance Under PressureTM Welcome to a new standard of pressure relief.

Integrated into one pressure relief solution, Continental Disc rupture discs protect and isolate from process media and

pressure fluctuations while Consolidated pressure relief valves help prevent excess process loss and downtime through reliable reclosing performance.

The result? Improved reliability for critical pressure relief systems that plant operators depend on.

estimated waste quantities, Emmerich and Oberhausen worked closely with contractors to measure waste streams accurately. This uncovered significant overestimates and enabled more precise segregation. In the following period, Oberhausen achieved a 40% reduction in non-hazardous waste, while Emmerich reduced municipal waste by 75%. Both sites consistently achieve waste separation rates above regulatory requirements, frequently exceeding 90% and contributing directly to Honeywell Technologies’ 2030 hazardous waste reduction goal. Even routine maintenance has been rethought. When an old, blocked pipeline required dismantling, Emmerich selected a dry-cleaning method rather than the traditional wet-clean approach. This avoided the generation of hazardous sludge entirely, reduced waste by more than 5 t,

and delivered cost savings of over €2000, demonstrating how creative problem solving at the operational level contributes to broader sustainability objectives.

Transforming water use and strengthening resource stewardship Water stewardship is an increasingly important consideration for chemical manufacturers, both in terms of environmental responsibility and operational resilience. Before 2023, Oberhausen was the largest water user within the business unit. The site proactively reviewed its water footprint, supported by a new wastewater permit that allowed greater operational flexibility. This, together with smaller optimisations in pump seal flushing and redesigning process water use, resulted in a 50% reduction in water consumption. This improvement moved Oberhausen from the largest to the fourth largest water user within the business unit, while also delivering water cost savings of approximately €10 000.

A model for sustainable chemical manufacturing

Figure 4. Precleaning of dryer.

The achievements of Emmerich and Oberhausen offer a replicable model for chemical manufacturers seeking to accelerate their sustainability journeys. Several lessons stand out: n Sustainability must be treated as a strategic design requirement rather than a downstream modification. Integrating energy, waste, and resource efficiency at the project definition stage delivers long-term value and avoids carbon lock-in. n High-quality data underpins good decision making. Whether monitoring waste, energy, or water, accuracy enables better targeting and more effective investment. n Collaboration across functions is essential. The most successful initiatives emerged from early involvement of engineering, operations, environmental teams, and procurement. n Circularity should be part of daily practice. From equipment dismantling to waste sorting, treating materials as valuable resources strengthens both environmental and economic performance.

Looking ahead

Figure 5. Reduction in monthly demineralised water consumption at Oberhausen following wastewater permit changes and process optimisation.

These case studies demonstrate that sustainability in chemical manufacturing is not theoretical but achievable. This work reflects a holistic approach that spans energy, waste, water, and responsible sourcing, and is reinforced by a culture of innovation and continuous improvement. As the sector transitions towards lower-carbon and more resource-efficient production, organisations that adopt this integrated, future-focused approach will be best positioned to thrive in the years ahead.

Birendra Adhikari and Robert Rapier, Aduro Clean Technologies Inc., present a different approach for converting waste plastics to naphtha-cracker-ready feedstock, without extensive upgrades to petrochemical infrastructure.

ince the start of the industrial revolution, chemists and chemical engineers have spent their careers learning how to chemically construct new materials, and how to make them last longer; however, considerably fewer efforts have been made to understand how to deconstruct these same materials. Plastics, one of the great successes of the 20th century in chemistry and materials science, are designed to be durable, chemically and mechanically. And, as they are also relatively inexpensive, they have become ubiquitous. At their end-of-life, waste plastics thus present two intertwined challenges: enormous quantities are generated globally, and the chemical nature and diversity of the materials themselves means that their conversion into a resource for the circular economy is not straightforward. Mechanical

recycling plays an important role; yet, its limitations are well recognised, particularly for mixed waste streams. Meaningful progress toward circularity, defined here as converting end of life plastics back into usable intermediates and feedstocks (e.g. naphtha) for chemical processes, will depend on chemical pathways capable of producing lower molecular weight hydrocarbons (LMWHC) compatible with existing petrochemical infrastructure. Among the polymers found in the waste streams, those classified as step growth polymers, such as polyethylene terephthalate (PET) and polyamides (PA), can be depolymerised through solvolysis (e.g. hydrolysis). Chain growth polymers such as polyethylene (PE), polypropylene (PP), and polystyrene (PS), referred to as polyolefins hereafter, are chemically different, possessing long, chemically inert,

26 27

saturated hydrocarbon backbones. Their conversion into steam cracker feedstocks requires cleaving carbon-carbon (C-C) bonds in the hydrocarbon backbones rather than depolymerisation in the classical sense. To date, pyrolysis has been the primary method for achieving this transformation. While conceptually straightforward, thermolytic cracking, as occurs in pyrolysis, introduces well known challenges: high temperature requirements and cascading free radical reaction pathways that lead to a complicated mixture of hydrocarbons with elevated levels of unsaturation and covalent incorporation of heteroatoms from feedstock contaminants. These characteristics limit the use of pyrolysis derived products as feed for naphtha crackers without substantial post processing, such as hydrotreatment. This article presents an alternative technology for converting polyolefins present in waste plastics into naphtha-quality hydrocarbons that overcomes many of the challenges associated with pyrolysis. This approach provides a distinct alternative that employs catalysed C-C scission at moderate temperatures followed by quenching of free-radical intermediates by reducing equivalents generated in situ to produce stable products of markedly different composition.

The challenge of chemical recycling of polyolefins Polyolefins, primarily PE and PP, dominate global waste plastics streams; yet their chemical functionality makes their chemical recycling difficult. Production of polyolefins from

Figure 1. Energy profile diagram for the production of polyethylene (left) and conversion of polyethylene to lower-molecular-weight compounds (right).

Figure 2. Schematic outline of the underlying reactions of hydrochemolytic conversion of polyolefins to LMWHC.

their monomers is a highly exothermic process. Conversely, breaking of C-C bonds in a saturated hydrocarbon backbone is very endothermic, requiring substantial energy input (illustrated qualitatively in the energy profile diagram in Figure 1). Classical depolymerisation of polyolefins, understood as reversing the polymerisation step to yield ethylene or propylene, is not feasible under practical conditions. Accordingly, the objective in chemical recycling of polyolefins is molecular weight reduction to LMWHC. Yet, more than that, it also is to do so in a way that yields a high proportion of naphtha range compounds with low levels of unsaturation and minimal incorporation of heteroatoms from feedstock contaminants. Axiomatically, that outcome depends on cleaving the polymer chains through selective scission of their C-C bonds while limiting uncontrolled secondary reactions. Achieving this selectivity while minimising side reactions remains the central challenge in converting polyolefins into cracker compatible feedstocks.

Thermolytic mechanisms and limitations of pyrolysis The process of pyrolysing polyolefins requires temperatures typically exceeding 440°C, where thermal energy alone initiates the rupture of C-C bonds. These conditions generate free radicals that initiate a complex cascade of reactions, including hydrogen abstraction, radical recombination, β-scission, cyclisation, and thermolytic dehydrogenation, which proceed through free-radical intermediates. The result is numerous competing reaction pathways and extensive ‘carbon scrambling.’ For instance, hydrogen abstraction between free radicals leads to an unsaturation in the product for each C-C bond broken; β-scission of a free radical produces an alkene and another radical; radical recombination involving 2° radicals results in branching; and thermolytic dehydrogenation, which occurs readily at temperatures typical for pyrolysis, creates additional unsaturation. Problematically, feedstock contaminants often contain heteroatoms such as nitrogen, oxygen, and chlorine which become covalently incorporated into the product molecules. In effect, the outcome of pyrolysis is a wide variety of compounds with diverse functionalities and a wide range of molecular weights whose naphtha range fraction typically falls below 40%. With high unsaturation and heteroatom content, that fraction requires extensive post-processing, often hydrotreating, before it can be used in naphtha crackers. This upgrading step is energy intensive, and requires specific catalysts and high partial pressures of molecular hydrogen. For pyrolysis to be viable for chemical recycling of waste plastics, two requirements must be met simultaneously: proximity to large metropolitan areas that generate substantial quantities of waste plastics, ensuring a steady feedstock supply; and integration with a refinery or petrochemical complex capable of providing energy, utilities, operational support, and full upgrading of the pyrolysis product. Large, fully integrated operators with access to both abundant waste streams and refinery infrastructure can make this model work.

However, these conditions are not widely replicable. The very factors that enable pyrolysis to operate effectively also constrain it to a limited role, reducing its relevance as a globally scalable solution for waste plastics conversion.

Overcoming challenges with chemocatalytic conversion

refineries or petrochemical complexes, allowing standalone operations. A side by side comparison of mechanistic and operational distinctions between pyrolysis and HCT, presented in Table 1, reinforces how the two technologies

This conversion pathway, HydrochemolyticTM Technology (HCT) developed by Aduro Clean Technologies, operates in a fundamentally different reaction environment than pyrolysis. Hydrochemolytic conversion of polyolefins can be neatly summarised as a three-step, one-pot process as shown in Figure 2: catalysed scission of C-C bonds in the polymer backbone producing free radical intermediates; concurrent, in situ generation of reducing equivalents, H(equiv), by aqueous reforming of a co-reagent (H-source); and rapid quenching of the free-radical intermediates by the H(equiv). Use of a catalyst allows HCT to achieve C-C bond scission at moderate temperatures, typically 390 - 420°C, contributing to more selective C-C bond cleavage and Figure 3. Qualitative comparison of energy profile and product profile of hydrochemolytic vs thermolytic limited secondary reactions. Another defining feature of conversion of PE to LMWHC. HCT is the in situ generation of reducing equivalents that quench (or stabilise) the free-radical intermediates rapidly after C-C bond Table 1. Key mechanistic and operational differences between cleavage, preventing the cascade of pyrolysis and HCT free-radical reactions that characterises Method Pyrolysis HCT pyrolysis, and preserves the hydrocarbon Principally catalysed C-C scission Reaction Thermolytic cracking at high functionality of the polyolefin feed. The with rapid quenching; limited chemistry temperature followed by differences between this chemocatalytic extensive free-radical reactions: dehydrogenation, allylic scission, and approach and pyrolysis lead to distinct mild cyclisation/aromatisation hydrogen transfer, radical recombination, cyclisation, product profiles; a qualitative comparison aromatisation, polymerisation; being illustrated in Figure 3. thermal dehydrogenation Liquid yields from hydrochemolytic Quenching None; non-reducing In situ aqueous reforming of a conversion of waste plastics typically environment co-reagent generates reducing reach about 85% by mass of the equivalents which quench free-radical polyolefin content in the feed. About intermediates two-thirds of the liquid product consists Temperature Typically >440°C Typically 390 - 420°C of hydrocarbons with carbon numbers of Liquid product 40 60% Typically 85% 20 or below, suitable for naphtha cracker yield feed. Unsaturation levels are low, with Product Complex mixture; typical: ~20% Approximately two-thirds ≤C20 bromine numbers generally in the range hydrocarbons; remainder convertible composition naphtha, 30 - 40% wax of 25 - 40. In contrast, the products of to ≤C20 pyrolysis often have bromine numbers High unsaturation (Br numbers >>50) Low unsaturation (Br numbers 25 - 40) well above 50, in some cases exceeding 100. The reducing environment also PS yields primarily alkylbenzene with minimises covalent incorporation of some di and triphenyl alkanes heteroatoms from feedstock Reducing environment limits covalent Heteroatoms in N, O, Cl from contaminants contaminants into the LMWHC. Low incorporation of heteroatoms; product covalently integrated into molecular weight carboxylic acids or contaminants appear mainly as low product amines derived from trace contaminants molecular-weight acids or amines in the feed can be removed through Relatively lower temperature, and Yield loss Over-conversion readily simple aqueous washing or mild self-limiting kinetics minimise gas generates C1-C4 gases unless formation tightly controlled extraction, rather than hydrotreating. By achieving high yields of Post-processing Severe; hydrotreating required Mild; simple aqueous wash removes naphtha-quality product that does not low molecular-weight acids/amines; requirement to reduce heteroatoms and low heteroatom and unsaturation levels unsaturation require extensive post-treatment, HCT may allow direct use or mild dilution becomes deployable at a ‘right-sized’ Product use Naphtha fraction used as Naphtha cracker feed scale for both small and large naphtha cracker feed communities, and can be decoupled from

26 29

produce fundamentally different product slates and upgrading requirements.

Pre-pilot scale production of hydrochemolytic oil Pre-pilot scale experiments were conducted on a continuous-operation unit (Figure 4) using mixed plastics with composition representative of waste plastics streams, including PE, PP, PS, PET, and PA. Experimental operating conditions reflected commercial design parameters, including reaction temperature, catalyst loading, and residence time. Post-treatment of the product consisted of a simple aqueous wash to remove trace impurities derived from heteroatom containing contaminants. Importantly, no hydrotreating was required to achieve the product quality necessary for downstream evaluation.

Steam cracking trial A global organisation with extensive experience in steam cracking operations conducted a pilot scale cracking trial using the product of hydrochemolytic conversion. The trial evaluated cracking behaviour, product slate, and operational considerations relative to conventional naphtha. The product demonstrated cracking performance consistent with expectations for fungible naphtha. The resulting product slate (shown in Figure 5) aligned with typical

ethylene and propylene yields for conventional naphtha with a comparable hydrocarbon molecular weight range. No operational issues attributable to the feedstock were observed. These results indicate that hydrochemolytic oil can serve as a viable feed for naphtha crackers without the extensive upgrading required for pyrolysis derived products.

Circularity and value chain integration Chemical recycling pathways that produce cracker compatible hydrocarbons offer a route for integrating waste plastics into established petrochemical value chains. The quality and composition of the hydrochemolytic oil supports this integration by reducing the need for extensive upgrading and aligning with existing cracker operations. Distributed deployment can reduce transportation distances for waste plastics and provide a pathway for regions without refineries to participate in chemical recycling initiatives. These features complement broader efforts to develop more resilient recycling infrastructure, and support progress toward circularity, defined as the return of waste derived hydrocarbons to productive use within existing manufacturing systems.

Conclusions

The conversion of polyolefins into naphtha-cracker ready hydrocarbons requires C-C bond scission under kinder and gentler conditions that limit uncontrolled secondary reactions leading to formation of a complicated mixture, and covalent incorporation of heteroatoms into the product. Pyrolysis, while viable under specific conditions, is constrained by its thermolytic mechanisms that create broad molecular weight distributions and high unsaturation, and by its reliance on refinery integration. These factors limit its scalability as a global solution for waste plastics conversion. Chemocatalytic conversion of polyolefins to LMWHC is distinct. Catalysed C-C scission of polymer backbones at moderate temperatures, followed by quenching of the free-radical intermediates by in situ generation of reducing equivalents, produces high yields of substantially saturated hydrocarbons with minimal heteroatom incorporation. The resulting product Figure 4. The pre-pilot scale, continuous-operation, process requires only modest clean-up and is suitable for unit used for the application of HCT to waste plastics. naphtha cracking without hydrotreating. Pre-pilot scale production and cracking experiments conducted with a global steam cracking expert demonstrated the technical viability of the application of HCT for chemical recycling of polyolefins in waste plastics. By addressing the scale, product quality, and infrastructure constraints that limit pyrolysis, hydrochemolytic conversion offers a pathway for right sized, geographically flexible chemical recycling solutions. The results presented here illustrate its potential to support the integration of Figure 5. Cracking yields from steam cracking trials of hydrochemolysis waste plastics into petrochemical value oil: yield of ethylene, propylene, and 1,3-butadiene at different furnace chains and contribute to progress toward temperatures. material circularity. 30

Igor Kostromin and Marie Vognsen, Topsoe, consider how sulfurous waste streams can be converted from a liability into a commercial asset.

efinery operators across the world face a converging set of pressures: tightening environmental regulation, growing demand for energy efficiency, and the need to maintain profitability in an increasingly competitive market. Finding technologies that address all three simultaneously is rarely straightforward. This article will explore a technology that converts sulfurous waste streams into commercial-grade sulfuric acid, recovering energy as superheated high-pressure steam and offsetting direct CO2 emissions from boilers.

A clean solution Wet gas sulfuric acid (WSATM) technology is part of Topsoe’s broader Clean Air solutions portfolio, aimed at converting sulfurous waste streams into value while minimising operating costs and emissions. It enables refiners to stay environmentally compliant, maintain operational reliability, manage feedstock variability, and protect profitability through high-efficiency sulfur recovery. Drawing on real-world deployments across multiple continents, the technical case for WSA as a sulfur

management solution is strong and is increasingly backed by a growing number of refineries who are selecting the technology.

The emissions challenge in refining SO2 emissions are a persistent environmental hazard. To meet fuel quality standards, refineries use hydrotreaters to remove sulfur from oil products. This generates sulfurous off-gases, which are captured from the gas stream in amine treating units. If not treated properly, these hydrogen sulfide (H2S)-rich gases pose serious environmental and public health risks, contributing to acid rain and respiratory illness. Currently, most refineries rely on the Claus process for sulfur recovery. While effective, it carries certain limitations. It struggles with energy inefficiency, particularly when combined with tail gas treatment units – which require large amounts of low-pressure steam – and incinerators that rely on external fuel combustion, both increasing operational complexity and direct CO2 emissions. Processing sour water stripper (SWS) gases in Claus plants presents an additional challenge: high ammonia concentrations can form

26 31

ammonium salts, causing catalyst poisoning and equipment fouling. Claus plants are also poorly suited to lean or variable sulfur streams, creating further inefficiencies in modern, dynamic refinery environments.

How the process works WSA is a catalytic process that recovers sulfur from waste gases as commercial-grade sulfuric acid (H2SO4). Using Topsoe VK-W catalysts, it achieves highly effective sulfur removal – the WSA technology can be designed to achieve SO2 emissions below 10 ppmv – without any chemical additives or waste streams. The process comprises three primary stages. First, sulfur in the feed gas is combusted to form SO2 at the optimal temperature. Second, SO2 is oxidised to SO3 in a multi-bed converter using the VK-W series catalyst. Third, the SO3 gas is hydrated by existing water vapour in the process gas to form sulfuric acid, which is then condensed in the WSA condenser, where heat is simultaneously recovered. The final product is commercial-grade acid ready for storage, and the resulting cleaned gas can be released to atmosphere or directed pretreated to downstream CCUS processes. WSA technology handles feed fluctuations without operator intervention. It also processes lean acid gases containing below 30% vol H2S – a range where conventional Claus units frequently encounter operational difficulties.

The operational and commercial advantages Energy recovery

More than 90% of the thermal energy in the feed gas is recovered and converted into high-pressure steam. This steam integrates directly into the refinery’s steam grid, offsetting output from fossil-fuel-fired boilers and reducing both fuel costs and direct GHG emissions.

A marketable product

The sulfuric acid produced is high-purity and commercially valuable, with applications across fertilizer manufacturing, chemical manufacturing, metallurgical leaching, and water treatment. For refiners, this creates a new revenue stream while contributing to industrial supply chains.

Operational reliability

WSA units are compact and designed for high uptime. All process steps occur near atmospheric pressure, enhancing safety and ease of maintenance. Unlike scrubbers or dry-gas systems, WSA requires no absorbents, activated carbon, or heat transfer salts, making it simpler to operate and more resilient under variable conditions.

Ammonia and soot handling

The process operates in full combustion mode, which means there is no challenge related to ammonia slip from the combustion chamber and no risk of catalyst bed choking due to soot formation – both of which are known issues in the partial combustion mode of the Claus process.

Lower feed pressure requirements

Figure 1. WSA flow chart.

WSA operates at lower pressure than the Claus process, requiring a lower battery limit feed pressure. This enables acid gas from the amine regenerator and sour gas from the sour water stripper to be supplied at reduced pressures, allowing both units to operate more efficiently with lower reboiler duties.

Feedstock flexibility

Figure 2. Direct CO2 emisions offset possibility in a typical refinery using a Claus sulfur recovery unit (SRU) or WSA.

Due to its inherent operational characteristics, the WSA process offers refiners greater flexibility with respect to acid gas composition, maintaining stable operation at very low H2S concentrations – an increasingly important consideration in today’s world as crude types diversify and feedstock slates continue to change.

HYDROGEN CONFERENCE 26

The latest edition of Global Hydrogen Review’s Global Hydrogen Conference is taking place on 18 November 2026. This virtual conference is dedicated to the advancement of the hydrogen industry worldwide. Join us for a series of interesting presentations from industry experts focusing on innovative technology and solutions that will help to accelerate the hydrogen revolution.

Keynote Speaker:

Sponsors:

VIRTUAL CONFERENCE 18 NOVEMBER 2026 REGISTER FOR FREE

Table 1. Technical and environmental comparison – WSA vs Claus Feature

Modified Claus process

WSA technology

Sulfur recovery

99.9+% with tail gas treatment

Up to 99.99%

Energy efficiency

Lower (due to tail gas treatment units and incinerators)

High (uses exothermic heat, generates steam)

Direct CO2 emissions during normal operation

Yes (requires fuel)

None

Capital and operational cost

High for multi-stage setups

Lower due to simpler design

Product

Elemental sulfur Price example: US$870/t, Brazil CFR, April 2026

Market-grade sulfuric acid Price example: US$1100/t of sulfur equivalent (Seq) Brazil CFR, April 2026

Digital performance management

Topsoe’s ClearViewTM digital service platform enhances WSA performance by collecting real-time process data, running advanced simulations, and providing actionable recommendations to maintain optimal efficiency and compliance. This ensures refiners consistently meet daily targets for sulfur removal and steam production with minimal downtime or deviation.

Case studies PetroPeru’s Talara refinery

At the Talara refinery in Peru, Topsoe’s WSA technology was deployed to process waste gases from the refinery’s amine and SWS units. The result is a near-zero emissions process that produces a commercial-grade product with significant local value. The sulfuric acid produced is used in Peru’s copper mining sector and fertilizer industry, reducing the country’s dependence on imported chemicals. The exothermic reactions within the WSA process also generate high-pressure steam now integrated into Talara’s refinery operations, reducing natural gas combustion and contributing to meaningful carbon emission reductions.

Greenfield oil refinery

At a greenfield oil refinery, the WSA process was benchmarked against a modified Claus process with an amine-based tail gas treatment unit configuration. Both systems were designed to achieve 99.9% sulfur recovery, processing 90 mol% H2S amine acid gas and SWS off-gas, producing 270 tpd of sulfur and 800 tpd of sulfuric acid. The comparison evaluated direct CO2 emissions from flue gases and indirect emissions associated with utility consumption. While WSA had slightly higher electrical consumption – primarily due to greater gas volumes and the use of an air-cooled acid condenser – it demonstrated clear advantages in other critical areas. The Claus system relied on natural gas combustion in the incinerator to eliminate residual sulfur compounds, generating elevated CO2 emissions. WSA achieved complete combustion of sulfur compounds internally with no external fuel requirement. On steam management, the Claus process required low-pressure steam input for tail gas treatment unit regenerators, while WSA generated high-pressure superheated steam for direct use in refinery operations, reducing reliance on boiler-generated steam. Although WSA’s 34

cooling water demand was higher due to the acid cooling step, it eliminated wastewater discharge and avoided chemical consumption entirely. The net result was greater energy efficiency and lower total GHG emissions for the WSA configuration – illustrating how greenfield projects can achieve both sulfur compliance and carbon reduction goals from day one.

IndianOil’s Haldia refinery

IndianOil recently commissioned a WSA plant at its Haldia refinery, India. The project treats sulfurous off-gases to produce sulfuric acid, aligning with circular economy objectives. This installation delivered the largest recorded carbon emissions savings across all IndianOil Group projects to date. By converting what would otherwise be waste emissions into a saleable product, the refinery supports domestic industry while minimising its environmental impact. The acid is reintroduced into industrial markets, contributing to fertilizer production, LABSA production, and metal extraction applications. The project demonstrates WSA’s ability to support national sustainability goals without requiring significant infrastructure modifications.

Implementation: a phased and supported transition Replacing or revamping older Claus units with WSA represents a strategically sound option, particularly compared to constructing entirely new Claus capacity. A gradual shift from sulfur to sulfuric acid production enables refineries to build operational experience in acid handling and develop robust offtake partnerships. Over time, increasing the volume of acid gas directed toward WSA improves both environmental and economic performance because a more refined product, such as sulfuric acid, is a lot more valuable than the equivalent elemental sulfur. Transitioning to WSA does not require a full replacement of existing sulfur recovery infrastructure. A phased approach, starting with ageing Claus units, can reduce both capital outlay and operational risk. Support is available covering basic engineering, catalyst supply, construction oversight, and commissioning, while engineers coordinate directly with EPC contractors during implementation. Performance monitoring platforms, such as Topsoe’s ClearView, can also provide operators with maintenance alerts, predictive insights, and optimisation data from startup. Market integration support from the licensor side, such as connections to industrial acid traders, can also help refiners establish offtake arrangements when entering the sulfuric acid market. With over 175 units built worldwide, WSA has a proven track record across a diverse range of refinery configurations, delivering cost savings, emissions reductions, and commercial returns.

Mark Knobloch, Merichem Technologies, discusses how hydrogen sulfide removal in gas streams could play an important role in decarbonising downstream operations.

he downstream refining and petrochemical industries are among the most impacted by the energy transition. While governments and industry leaders have set ambitious decarbonisation targets, including net zero emissions by 2050, global demand for oil and gas remains strong and, in some areas, continues to grow. Even under the most aggressive decarbonisation forecasts, hydrocarbons are expected to continue to play a role in the global energy system for decades to come. Despite the rise of renewables, global consumption of oil, natural gas, and hydrocarbon gas is being driven by population growth, urbanisation, and the need for lightweight, durable industrialised materials, plastics, and fertilizer.1 However, the demand creates tension for asset owners, as facilities designed to operate for decades must now navigate tightening emissions rules while remaining reliable, safe, and profitable.

26 35

For operators, decarbonisation is a complex, long-term process. It requires consideration of asset lifespans, capital cycles, regional policies, and technology maturity. The key challenge is determining how to sequence this transformation for each application.

Pathways over targets Net zero targets and public commitments indicate the industry’s direction but do not provide operators with a clear path forward. Refineries, gas gathering facilities, and related infrastructure are complex and capital-intensive, with many assets designed decades ago still offering significant operational life. Large scale replacements, particularly in the short-term, are rarely practical. A pathway-based approach provides a more practical solution. Rather than focusing solely on achieving net zero, owners are well advised to prioritise steady, incremental emissions reductions over time.2

H2S removal is an enabler to carbon credits The removal of H2S does not, by itself, generate carbon credits, as it is not one of the greenhouse gases tracked in IPCC/GHG protocol frameworks.3 However, H2S removal is a necessary processing step that unlocks a separate,

creditable activity. What generates credits is what happens to the other streams that come along with the H2S clean up. Sour natural gas or syngas often contains both CO2 and H2S, collectively known as ‘acid gas.’ An acid gas removal (AGR) unit uses amine or physical solvents to strip both from the raw gas stream in a single process step. An amine tower removes both CO2 and H2S from natural gas. The H2S then needs to be removed from the CO2 stream using the amine treatment. After the H2S is removed, the CO2 can be vented or compressed and sent to a CO2 pipeline or capture system. Once separated, the H2S stream typically goes to a sulfur recovery unit to produce elemental sulfur or, in some designs, is reinjected underground instead of being flared. The sulfur-free, pipeline-quality CO2 stream can be sent for sequestration or utilisation and qualifies for credits, specifically under the 45Q tax credit for CO2 sequestration.4 Pure CO2 for carbon capture sequestration (CCS) increases storage capacity and maximises carbon credits. Section 45Q is a federal tax credit for captured and stored CO2 tonnage, not a tradable offset credit from a voluntary registry. ‘Acid gas to carbon credits’ refers to 45Q eligibility on the CO2 fraction of the acid gas stream, which operates under IRS rules, not carbon-market MRV protocols. Eligibility under 45Q is not automatic. It has minimum annual capture tonnage thresholds and requires monitoring, reporting, and verification under EPA’s 40 CFR Part 98 Subpart RR5 (or equivalent), plus secure geologic storage or qualifying utilisation (e.g. enhanced oil recovery) to claim the credit.

The Haynesville-to-Gulf Coast supply chain example

Figure 1. Merichem Technologies SULFURTRAP

Lead/Lag Vessel Systems using iron oxide solid adsorbent for H2S removal.

The burgeoning Haynesville Shale in North Louisiana and East Texas, US, holds abundant natural gas resources. The gas from these wells is sent to midstream plants that clean up and condition the gas to meet pipeline specifications. The clean natural gas is sent down pipelines from North Louisiana and East Texas directly to LNG export terminals on the Gulf Coast. Midstream operators gather gas and run it through treating plants to remove acidic gases, meeting strict pipeline quality requirements (typically <2% CO2 and <4 ppm H2S). The H2S must be removed from the CO2 which then allows the CO2 to either be vented or routed to CCS wells for permanent underground storage or be sent to CO2 pipelines. The Haynesville gas is then routed through the Louisiana Energy Gateway (LEG) to reduce emissions and supply premium Gulf Coast LNG export facilities.6

The H2S removal technologies

Figure 2. Merichem Technologies LO-CAT for H2S removal from virtually any gas stream.

LO-CAT® technology has been used to remove H2S from gas streams since the 1970s. With more than 240 licensed units across the globe, the technology can remove over 99.9% of the H2S from most gas streams at ambient to moderate temperature, and low to moderate pressure gas streams. The ‘sweet’ spot of the technology application ranges from 1 tpd up to 20 tpd of sulfur removal. Its role in decarbonisation projects is pretreatment: stripping H2S out of a gas stream so

the remaining CO2-rich stream can then be captured, sequestered, or utilised without sulfur contamination. The process chemistry of this technology is embedded in its name – LO-CAT stands for Liquid Oxidation CATalyst. The overall system oxidation reaction is as follows: H2S (gas) + ½ O2 (gas) → H2O + So This is a well-known oxidation reaction. This overall reaction is sub-divided into two parts: (i) H2S gas absorption, ionisation, and reaction to make solid sulfur in the liquid solution. (ii) The liquid solution is then oxidised using air and regenerated for re-use. In chemistry terms, step (i) is called reduction and step (ii) is called oxidation, therefore, the process is called a redox (reduction-oxidation) reaction process. It capitalises on knowledge Merichem has acquired to optimise the process variables that allow for favourable reaction conditions.

Mexico facility for recovery of CO2

A CO2 producer near Puebla, Mexico, installed a high-pressure LO-CAT system at its plant designed to process a maximum of 5805 Nm3/hr inlet gas, at an operating pressure of about 64 psig, with approximately 950 ppmw H2S to yield 0.35 LTPD of dry elemental sulfur at a removal efficiency of 99.9%. The treated CO2 gas is used for the food and beverage industry in Mexico. This unit was commissioned in 2005, and it has been continuously running since then. The operator is very happy with the H2S removal performance of the system, yielding a treated gas with negligible content of H2S.

On Demand Webinars On Demand Webinars

Treating acid gas with lower sulfur content

COSO Operating Co. LLC operates a geothermal electric generation facility in the community of Coso Junction, California, US. In the electricity generation process, the non-condensable geothermal vapours, which are mainly CO2, cannot be vented to the atmosphere because it contains a small amount of hydrogen sulfide. The first of the three LO-CAT units was installed for H2S removal in 1993. The non-condensable CO2 and H2S are flashed, compressed, and routed to the LO-CAT unit for sulfur removal before being emitted into the atmosphere. The outputs from the LO-CAT unit are the vent gas and the sulfur cake. The sulfur cake is approximately 65% sulfur and 35% moisture. The elemental sulfur produced by this LO-CAT unit is blended with fertilizers and sold as a soil amendment for vineyards.

On Demand Webinars Usage examples The following examples show cases of H2S treatment and removal from streams containing CO2, which provide a strong basis of understanding and evidence for the same use in decarbonisation. The lessons following from a midstream acid-gas treatment project provide insight into H2S management challenges emerging in downstream carbon capture and low-carbon hydrogen developments.

On Demand Webinars On Demand Webinars

Explore our library of Explore free-to-access our library of On Demand Webinars, free-to-access covering Explore library of a range of topics in Onour Demand Webinars, the downstream sector free-to-access covering a range of topics in On Demand Explore ourWebinars, library of free-to-access the downstream sector covering a range of covering topics in On Demand Webinars, a range the downstream of topics in thesector downstream sector Visit: www.hydrocarbonengineering.com/webinars Visit: www.hydrocarbonengineering.com/webinars

Visit: www.hydrocarbonengineering.com/webinars

be captured, sequestered, or utilised without sulfur contamination. The technology is being used in gas processing applications around the world across a multitude of process conditions. Standardised systems for lease or purchase can be rapidly deployed and scaled quickly but can also be bespoke based on specific client needs or requirements.

Conclusion Decarbonising downstream and stream at low pressures and temperatures with no liquid effluents or waste streams. petrochemical operations is one of the most complex challenges facing heavy industry. It cannot be achieved through targets alone or by copying solutions from other sectors. It requires balanced, pragmatic pathways. Rather than a blanket concept, this journey will consist of a portfolio of changes starting with a pathway approach, and then segueing into energy efficiency improvements, a move to low-carbon hydrogen, electrification, and hub-based carbon capture and storage. These approaches will be supported by increased circularity and a changing product mix. Crucially, the most successful asset owners and operators will make deliberate, phased Figure 4. Versatile, skid-mounted Lead-Lag Vessel Systems for H2S decisions rather than respond to external removal, designed for continuous operation with long bed life, pressure at the last minute. non-caking SULFURTRAP adsorbent media. Decarbonisation is not a one-time project. The transition needs to be steady rather than abrupt. Successful operators should not rely on a Adsorbents single technology or strategy. Instead, they should deploy SULFURTRAP® proprietary, iron based adsorbent technology, solutions tailored to their assets that consider wider regional uses optimised solid particulates in fixed bed systems to policy and market demand. remove H2S from gas streams through chemical adsorption. The chemistry is not particularly new, but the evolved materials and methods of synthesis represent a new References 1. ‘IEA sees global oil demand rising until 2050 under current policies’, generation of iron based solid adsorbent media. S&P Global, (November 2025), https://www.spglobal.com/energy/ en/news-research/latest-news/refined-products/111225-iea-seesThe H2S reacts with the SULFURTRAP media to form global-oil-demand-rising-until-2050-under-current-policies innocuous and typically non-hazardous compounds that are 2. ‘Finding the best decarbonization pathways for refineries’, Carnegie Mellon University, College of Engineering, https://engineering.cmu. easily disposed. edu/news-events/news/2025/09/02-decarbonization-refineries.html SULFURTRAP systems are engineered to easily achieve 3. PICARD, D., ‘Fugitive emissions from oil and gas activities’ https:// www.ipcc-nggip.iges.or.jp/public/gp/bgp/2_6_Fugitive_Emissions_ 0 ppm H2S at the outlet and operate by simply passing the from_Oil_and_Natural_Gas.pdf sour gas stream through a packed column (vessel). 4. Carbon Capture Coalition, Primer: 45Q Tax Credit for Carbon Capture Projects, https://carboncapturecoalition.org/wp-content/ It should be clearly understood that where LO-CAT is uploads/2025/09/45Q-primer-Carbon-Capture-Coalition.pdf suited for higher tonnage sulfur removal requirements up to 5. US Environmental Protection Agency, Subpart RR – Geologic Sequestration of Carbon Dioxide, https://www.epa.gov/ghgreporting/ 20 tpd, SULFURTRAP is useful for lower tonnage sulfur subpart-rr-geologic-sequestration-carbon-dioxide applications up to 2 tpd of sulfur removal. 6. ‘Higher Natural Gas Prices Said Needed for Western Haynesville to Meet Gulf Coast Supply Gap’, Natural Gas Intelligence, https:// Like LO-CAT for its decarbonising role, SULFURTRAP also naturalgasintel.com/news/higher-natural-gas-prices-said-needed-forwestern-haynesville-to-meet-gulf-coast-supply-gap/ selectively removes H2S from the gas stream so the CO2 can

Figure 3. The LO-CAT Direct Treatment process removes H2S from virtually any gas

José Miguel González, Tecam, considers the role that electrically heated oxidation systems could play within industrial emissions abatement.

ndustrial decarbonisation is no longer limited to production processes. Across the refining, petrochemical, and chemical industries, companies are increasingly evaluating how auxiliary systems – including emissions abatement technologies – can contribute to reducing overall greenhouse gas emissions while maintaining operational reliability and regulatory compliance. Historically, the main objective of volatile organic compound (VOC) abatement systems has been to ensure environmental compliance by achieving high destruction efficiencies. Today, however, additional criteria are becoming equally important. Energy consumption, carbon footprint, fuel dependency, and integration with broader plant decarbonisation strategies are playing an increasingly significant role in technology selection. This shift is driving growing interest in the electrification of emissions abatement systems.

Decarbonisation extends beyond the production process Many industrial facilities have established ambitious carbon reduction targets that extend beyond their core manufacturing operations. Alongside investments in renewable electricity, process optimisation, and energy efficiency improvements, attention is increasingly being directed towards utilities and supporting

infrastructure. Air pollution control systems, once considered solely as environmental compliance equipment, are now being evaluated through the broader lens of energy management and sustainability. This evolution reflects a wider industrial trend: every significant energy consumer within a facility is being assessed for its contribution to overall emissions performance.

The changing energy landscape Thermal oxidation has long been recognised as one of the most effective technologies for eliminating VOC emissions, particularly in applications involving variable flow rates, complex solvent mixtures, and high destruction efficiency requirements. Traditionally, thermal oxidisers rely on natural gas or other fossil fuels to achieve and maintain oxidation temperatures. However, the rapid expansion of renewable electricity generation, together with increasing pressure to reduce direct carbon emissions, is encouraging industrial operators to explore alternative heating methods where technically and economically appropriate. Electrically heated oxidation systems have emerged as one possible solution, particularly as electricity grids continue to decarbonise. Rather than fundamentally changing the oxidation process itself, electrification replaces the conventional

26 39

Regardless of the energy source employed, industrial operators continue to require high destruction efficiencies, stable operation under variable process conditions, reliable availability, and compliance with increasingly demanding environmental regulations. Consequently, the adoption of electrified technologies does not alter the fundamental engineering requirements associated with VOC treatment. Instead, it introduces new considerations related to electrical infrastructure, system integration, and energy management. Achieving an appropriate balance between environmental performance, operational reliability, and decarbonisation objectives is becoming an important aspect of modern emissions control engineering.

Figure 1. Electric RTO technology installed by Tecam.

Case study: an e-RTO application in a tank terminal at the Port of Rotterdam

combustion-based heat source with electrical heating technologies while maintaining the same treatment principles.

A practical example of the application of electrically-heated oxidation technology can be found in a tank terminal at the Port of Rotterdam, the Netherlands. The system is designed to treat 2500 Nm³/hr of VOC-loaded air generated by the terminal’s operations. An electrically-heated regenerative thermal oxidiser (e-RTO) is used to treat the VOC emissions, replacing the conventional fuel-fired heating principle with electrical heating, while maintaining the thermal oxidation process required for high-efficiency VOC destruction. The application illustrates how electrification can be considered for emissions abatement in tank storage facilities, where VOC treatment requirements need to be combined with the operational and energy characteristics of the site. In this type of installation, the choice between conventional and electrically heated oxidation should be assessed according to factors such as emission characteristics, operating profile, electricity availability, and the facility’s wider decarbonisation strategy.

Evaluating electrification from an engineering perspective The suitability of electrified VOC abatement depends on a range of technical and operational factors: electricity availability, local energy costs, grid reliability, operating schedules, process characteristics, and future energy strategies all influence the feasibility of electrification. For some facilities, conventional fuel-fired systems will continue to represent the most appropriate solution. For others, particularly those pursuing broader electrification initiatives, electrically heated technologies may offer significant long-term advantages. As with any engineering decision, technology selection should be based on a comprehensive evaluation of the entire operating context rather than on a single performance parameter.

Integration with industrial energy strategies One of the principal advantages of electrification lies in its potential integration with wider plant energy systems. As industrial facilities increasingly incorporate renewable electricity, battery storage, smart energy management, and demand-response programmes, electrically powered environmental systems can become part of an integrated energy strategy. This approach enables emissions abatement equipment to align more closely with plant-wide decarbonisation objectives while offering opportunities to optimise electricity consumption according to operational and market conditions. The degree of integration will naturally depend on the characteristics of each facility, but the trend towards greater interaction between process equipment and energy management systems continues to grow.

Reliability remains a fundamental requirement Despite the growing emphasis on sustainability, environmental performance remains the primary function of any VOC abatement system. 40

A technology landscape in transition Industrial emissions abatement is entering a period of technological evolution driven by broader changes in the global energy sector. Electrification is unlikely to replace conventional thermal oxidation technologies in every application. Instead, it is expanding the range of engineering solutions available to industrial operators seeking to balance environmental compliance, operational efficiency, and carbon reduction goals. As energy systems continue to evolve and renewable electricity becomes increasingly available, the role of electrified emissions abatement technologies is expected to grow. For engineering teams planning new installations or upgrading existing facilities, understanding where electrification creates value – and where conventional solutions remain the most appropriate choice – will become an increasingly important part of technology selection. Ultimately, the future of VOC abatement is unlikely to be defined by a single technology, but rather by the ability to apply the most suitable solution to each industrial application while supporting the wider transition towards more sustainable manufacturing.

Domenico Marzocchi, Watlow, explores how process heat is moving closer to the centre of industrial decarbonisation strategies.

ndustrial electrification has moved beyond the conceptual stage. Across the hydrocarbon processing industry, operators are no longer debating whether electrification will play a role in future operations. The conversation has shifted toward implementation, economics, and infrastructure readiness. For years, decarbonisation discussions focused primarily on emissions targets and sustainability commitments.

26 41

Today, engineering teams are facing a more practical challenge: how to electrify large thermal processes without compromising reliability, production continuity, or profitability. This shift reflects a growing recognition that process heat remains one of the largest and most difficult sources of industrial emissions. Applications such as crude oil heating, charge heating, amine regeneration, reboilers, LNG vaporisation, and hydrogen production often require multi‑megawatt thermal duties. Historically, these duties have been supplied through fired heaters, steam systems, or thermal fluid loops. Electrification changes the energy architecture of the facility by transferring a significant portion of thermal demand onto the electrical network. As a result, the real challenge is no longer the heater itself. Modern electric heating technologies have matured considerably and are capable of delivering high power densities, precise temperature control, and reliable operation. The critical question has become whether the facility’s electrical infrastructure can support large scale electrification in a practical and economically sustainable manner. Many organisations begin their electrification journey by evaluating individual process heaters. However, successful projects increasingly reveal that the limiting factor is often electrical infrastructure rather than thermal technology. Grid connections, substations, transformers, switchgear, protection systems, and cable routing frequently determine project feasibility long before equipment selection begins. This reality becomes particularly apparent when power requirements reach the multi‑megawatt range. Low-voltage systems, while suitable for smaller applications, become increasingly complex as power demand grows. Delivering large amounts of power at low voltage requires very high current levels, resulting in extensive cabling, larger electrical rooms, increased heat dissipation requirements, and higher installation costs. For brownfield facilities, these challenges can become substantial. Existing cable trays may lack available capacity, electrical rooms may have limited expansion potential,

and space constraints can make additional transformer installations difficult. In many cases, the infrastructure required to support low-voltage electrification becomes a major project cost driver.

Scaling electrification beyond the heater This is one of the reasons why medium-voltage electrification is attracting increasing attention throughout refining, petrochemical processing, LNG, and emerging hydrogen applications. By increasing supply voltage, current requirements are significantly reduced. The result is a substantial reduction in copper consumption, cable sizes, switchgear requirements, and overall installation complexity. For high-duty thermal applications, medium-voltage architectures can fundamentally alter project economics. Rather than viewing medium voltage as simply another heater option, many operators now recognise it as an enabling technology that makes electrification feasible at scale. The benefits extend beyond installation savings. Reduced electrical complexity can improve reliability, simplify maintenance, and create opportunities for future expansion. As facilities evaluate long-term decarbonisation strategies, the ability to scale electrical infrastructure efficiently becomes increasingly important.

From engineering concept to operating plant

Recent brownfield projects illustrate how these considerations translate into practical engineering decisions. At a refinery in Southeast Asia, a renewable diesel project required an upgrade to a hot-oil system previously heated by a 2 MW gas-fired heat exchanger. The project team evaluated direct electric heating as part of a wider effort to reduce combustion-related emissions while improving process flexibility and control. A medium-voltage electric heating system was selected to heat the reactor feedstock directly. Beyond the emissions objective, the project case centred on process safety, reliability, and the ability to control heat input more precisely. The application also demonstrated an important point for future refinery electrification projects: where significant thermal loads are involved, the electrical architecture and heater design must be considered together rather than as separate packages. A second brownfield project at a European refinery involved the hot-oil circuit used in bitumen logistics. The existing system relied on three high-pressure steam heat exchangers, with steam generated from fossil fuel. These exchangers were replaced by electric heaters providing a combined thermal capacity of 4.8 MW. Project estimates indicated Figure 1. POWERSAFETM is targeted for applications that enable reductions of approximately 13 500 tpy of electrification for larger thermal loads. CO2 and 4900 tpy of natural gas consumption. 42

Accelerate your journey to net zero Carbon capture plays a vital role in achieving global net zero targets. Sulzer is recognized as a leader in advanced separation and pumping solutions that optimize the total ownership. Our proprietary, MellapakCC™ cutting-edge technology has been developed to deliver maximum capture efficiency at the lowest specific pressure drop – resulting in lower energy consumption and offering significant gains in overall performance. With more than 50 years of experience working with supercritical CO2, we have provided injection pumps for the world’s largest CO2 capture plants and developed reinjection pumps for cutting-edge subsea applications. Contact us today to find out more

Figure 2. Refinery. The reduction represented approximately 1% of the refinery’s overall CO2 emissions and around 19% of its planned emissions-reduction programme. Equally important from an engineering perspective was the ability to introduce a high-power electric solution into an existing facility without redesigning the complete process architecture. These examples highlight why selective electrification is becoming an important route for brownfield facilities. Instead of attempting to replace every fired thermal asset simultaneously, operators can identify individual duties where electrical infrastructure, process requirements, and lifecycle economics align. The operational experience gained from these projects can then inform subsequent stages of a wider electrification programme.

Integration determines long-term performance Yet infrastructure is only one component of successful electrification. Another critical lesson emerging from industrial projects is that electrification should not be viewed as a heater replacement exercise. Instead, it should be approached as a complete system transformation. Heating technology, sensing, controls, power management, automation, and maintenance strategies all influence overall performance. A heater operating independently can deliver thermal energy, but a fully integrated thermal system can optimise efficiency, reliability, uptime, and operating costs simultaneously. This integrated approach is becoming increasingly important as operators pursue both sustainability and operational excellence. Electrified systems generate significant quantities of operational data, creating opportunities for process optimisation that are often difficult to achieve with traditional combustion-based systems. Real-time visibility into temperature profiles, electrical load, energy consumption, and equipment condition enables operators to move from reactive maintenance toward predictive maintenance strategies. Rather than responding to failures after they occur, maintenance teams can identify emerging issues before they affect production. 44

This capability is particularly valuable in hydrocarbon processing facilities, where unplanned downtime can carry substantial financial consequences. In many operations, reliability remains a higher priority than energy cost. Any electrification strategy must therefore demonstrate not only emissions reduction potential but also operational robustness. Historically, concerns regarding insulation integrity, moisture ingress, electrical stress, and long-term durability created hesitation around large scale electric process heating. Advances in medium-voltage engineering, insulation design, sealing technologies, monitoring systems, and predictive diagnostics have significantly improved confidence in these systems. As a result, electrification discussions are increasingly focused on where implementation makes the most sense rather than whether the technology is sufficiently mature. Many organisations are adopting phased approaches. Rather than replacing entire furnace systems immediately, operators often begin with targeted applications where electrification offers the strongest combination of environmental and economic benefits. Amine reboilers, hot oil systems, regeneration processes, and selected process heaters are frequently among the first candidates. These projects provide valuable operational experience while delivering measurable reductions in emissions, maintenance requirements, and energy losses. They also help organisations better understand future infrastructure requirements as broader electrification strategies are developed. The pace of adoption varies considerably by region. Europe continues to be heavily influenced by carbon pricing mechanisms and aggressive decarbonisation targets. North America often evaluates electrification through the lens of operational efficiency and lifecycle economics. Meanwhile, Asia and the Middle East are pursuing their own approaches based on energy availability, industrial growth objectives, and infrastructure investment strategies. Despite these regional differences, one trend remains consistent: process heat is moving closer to the centre of industrial decarbonisation strategies. The next decade is likely to be defined less by technology breakthroughs and more by successful execution. Organisations that evaluate infrastructure requirements early, integrate thermal systems effectively, and adopt scalable architectures will be best positioned to realise the benefits of electrification. The future of industrial heating will not be determined solely by the efficiency of the heater. It will depend on the ability to engineer complete thermal ecosystems that integrate power delivery, process control, operational intelligence, and long-term reliability into a unified solution. In that environment, electrical infrastructure may become one of the most strategic assets in the modern process plant. Facilities that understand this shift today will be better prepared for the next generation of industrial operations.

As refiners consider decarbonisation of their assets, the options around fuel gas and disposal are a critical step in moving towards net zero. Michael Stockle and Richard Spires, Wood, look at how refinery fuel gas can become a key lever for decarbonisation and the various options to deal with fuel gas in such scenarios.

any of the processes used in refineries create some fuel gas by-product. These gases are typically aggregated in a refinery wide network and deployed as fuel in the refinery in boilers, thermal incinerators, and fired heaters to provide services, emission control, and heat to the process. However, as refineries switch to alternative sources of heat, fuel-gas demand may fall, generating an excess that requires processing. In addition, as refinery processes continue to improve carbon efficiency, this potentially reduces fuel gas supply by-product, while the introduction of decarbonisation processes may increase energy demand. Across refinery assets, fuel gas combustion typically accounts for between 70 - 97% of Scope 1 refinery emissions, but the fuel gas supply/demand balance is moving, requiring reconsideration of where that balance will sit in future to facilitate refinery decarbonisation.

Fuel gas As a result of its method of generation, fuel gas composition varies from site to site, typically containing hydrocarbons from C1 to C4, some hydrogen, and

26 45

Approaches to decarbonisation

emissions are direct emissions from sources that are owned or controlled by the refinery while Scope 2 emissions are indirect energy emissions from the generation of purchased energy consumed by the refinery. The refinery does not control Scope 2 emissions directly but may have an influence over their acceptable level of carbon intensity and the quantity of energy purchased. Options to decarbonise Scope 1 emissions can be grouped into areas where the approach is common. This article will consider the following approaches and how they impact the production and use of fuel gas: efficiency improvements, post-combustion capture, pre-combustion capture, fuel substitution, electrification, and offset. The components considered in Table 2 each have their own associated emissions which are summarised in the table.

There are a range of techniques and technologies that can be used to decarbonise emissions on a refinery. Scope 1

Efficiency improvements

varying ranges of heavier hydrocarbons. There may also be traces of hydrogen sulfide, ammonia, and inerts (such as CO2 or N2) depending on the crude assay, refinery configuration, the effectiveness of separation, and the intensity of treatment applied to the streams. Table 1 illustrates example fuel gas compositions for refinery complexes. The fuel gas compositions shown in Table 1 represent a single snapshot, but they can vary seasonally and over time with changes in feedstock crudes and where changes in demand influence product slates, meaning decarbonisation strategies must remain flexible to accommodate fluctuations in fuel gas compositions.

Table 1. Example refinery fuel gas composition (vol%)

Refinery A

Hydrogen

24.84

68.8

27.2

48.49

Methane

57.61

14.1

20.1

27.94

Ethane

8.01

6.5

12.6

7.84

2.7

8.1

2.48

4.12

2.4

14.9

6.67

3.3

0.38

N-Butane

1.07

0.7

6.4

1.73

I-Butane

1.86

0.7

Ethylene Propane Propylene

N-Pentane

0.09

0.1

I-Pentane

0.35

0.3

Butene C6+

1.6 0.6

0.15 0.28

0.4 0.07

0.3

H2S (ppm)

1000

0.3

CO2 N2

1.64

O2 and Ar

0.29

0.2

0.21 <30

0.4

0.19

0.6

0.09

5.2

1.93

Table 2. Comparison of carbon emissions from different light hydrocarbons

Component

Emissions per t (t of CO2 from combustion)

Comments

Hydrogen (grey)

9.5 - 10

From production of hydrogen

Hydrogen (blue)

0.5

From production of hydrogen

Hydrogen (green)

Methane

2.75

Ethane

2.93

Ethylene

3.14

Propane

Propylene

3.14

As refineries implement best-available techniques, the demand, composition, and strategic use of fuel gas will change significantly. This section explores how these improvements impact fuel gas utilisation and contributes to or constrains decarbonisation.

Efficient heater operation

Process heaters and boilers account for the majority of fuel gas consumption. Improving heater efficiency directly reduces firing rates and associated CO2 emissions. n Air preheat: preheating combustion air using heat recovery from the flue gas improves thermal efficiency by reducing the energy required for combustion. This lowers fuel gas demand without compromising heater duty. Effective air preheating is now able to achieve cooling flue gas to below acid gas dew point temperatures. With this flue gas cooling, when combined with other fired heater optimisations, heater fuel efficiency of over 92% is achievable. n Convective heating: enhanced convective sections in heater design maximise heat transfer from flue gases to process streams, reducing radiant section load and fuel consumption.

Better approach temperature

Optimising heat exchanger networks to achieve closer approach temperatures minimises heater duty. For example, reducing the temperature gap between hot and cold streams in preheat trains can cut fuel gas requirements on that unit by several percent.

Low-grade heat recovery

Recovering low-grade heat from flue gases or other hot streams for feed preheating or combustion air heating reduces thermal load on heaters. Technologies such as economisers and air preheaters can reclaim energy that would otherwise be lost, reducing overall fuel gas consumption. High temperature heat pumps have achieved demonstration, on an industrial scale, of up to 2 MW, producing process steams up to 150°C, and from waste heat of 90°C. At these temperatures, fuel gas duty is unlikely to be displaced, however, effective redeployment of fuel may

become significant in reducing the additional energy demands of decarbonisation technologies such as post-combustion carbon capture – as will be discussed in this article.

Best use of hydrogen

As illustrated in Table 1, fuel gas is often hydrogen-rich due to less effective separation within hydroprocessing units. Burning hydrogen in heaters is less carbon-intensive than burning hydrocarbons, but as hydrogen generation typically generates around 10 kg CO2 per kg H2, it is not an efficient use of the resource. Instead: n Hydrogen recovery: technologies like pressure swing adsorption (PSA) and membrane separation allow the recovery of hydrogen from fuel gas for reuse in hydrocrackers and hydrotreaters. n Impact on fuel gas composition: as hydrogen is recovered, fuel gas becomes richer in heavier hydrocarbons. While a richer fuel may generate 2.75 - 3.14 t of CO2 per t of fuel burned, the refinery will avoid the generation of up to 10 t of CO2 per t of hydrogen produced. In addition, a transition to a richer fuel may require adjustments in heater burner design and combustion control.

Strategic considerations

Refinery decarbonisation strategies must integrate fuel gas management with energy efficiency improvements such as: n Dynamic fuel gas balancing systems to handle variability in composition. n Advanced combustion control to optimise heater performance with changing fuel characteristics. n Integration with hydrogen management plans to maximise carbon reduction benefits.

Post-combustion capture Refinery fuel gas’ primary application is in combustion. Under post-combustion capture scenarios, these combustion operations are assumed to continue as normal, with no specific reduction in fuel gas consumption. Consequently, the baseline fuel gas demand remains unchanged, however, additional requirements introduced by post-combustion capture can significantly alter the refinery’s energy balance. Post-combustion capture technologies target flue gas streams from existing combustion units, capturing CO2 at emission points without modifying the function of the primary combustion equipment. This approach avoids major redesign of the process but introduces several secondary impacts on fuel gas systems through the implementation of the new emissions management equipment.

Drivers of increased fuel gas demand

n Flue gas conditioning and solvent protection: CO2 capture solvents, particularly amine-based systems, are highly sensitive to contaminants such as H2S. To prevent solvent degradation and maintain capture efficiency, upstream fuel gas clean-up may be required. This adds complexity and may increase capital and operating costs.

n Energy penalty for solvent regeneration: post-combustion capture technologies generate substantial energy demand to overcome additional pressure drop and for solvent regeneration. Net thermal energy requirements are in the range 2 - 4 GJ per t of CO2 captured, arising from:1 § Steam for thermal regeneration of capture solvents translates to new steam generating equipment or higher firing rates in existing boilers, driving up fuel gas consumption. § Electrical power for pumps, blowers, and CO2 compression – which may be resolved through power import or via new generating equipment, further increasing fuel gas consumption. n Flue gas temperature management: capture processes generally require cooling of flue gases to less than 50°C prior to CO2 absorption, however, post-treatment reheating of flue gases may be necessary to meet stack discharge conditions. While this may be achievable through heat recovery integration, further heat demand and potential incremental fuel firing may be necessary. n Flue gas CO2 concentration: all post-combustion capture processes are more efficient and cost less when the CO2 concentration in the flue gas is higher. This therefore interacts with the fuel gas composition, where higher hydrogen content in the fuel gas is detrimental to the techno-economics of applying CO2 capture to the resultant flue gas.

System-wide implications

The combined effect of these factors can paradoxically reduce fuel gas availability (through requirements to remove contaminants) while increasing overall fuel gas demand, even as the refinery seeks to decarbonise. This raises critical questions: n Can the existing refinery fuel gas (RFG) system accommodate the incremental demand across all units? n Will fuel gas capacity become a limiting factor for implementing PCC at scale?

Potential pinch point

Fuel gas availability may emerge as a pinch point for decarbonisation. While post-combustion capture reduces direct CO2 emissions, the associated energy penalty could strain the refinery’s fuel gas network, impacting both economics and feasibility. A comprehensive energy integration study, including pinch analysis and heat recovery strategies, is essential to mitigate these risks.

Pre-combustion capture For pre-combustion capture, operators essentially fire the heaters with blue hydrogen rather than fuel gas. The fuel gas can instead be used as a feed to the hydrogen plant with the carbon produced captured and stored. The efficiency losses in converting fuel gas to hydrogen and then burning it mean that although operators can reduce emissions significantly, they actually need more fuel in total and so there does not tend to be a problem with fuel gas oversupply. This can be compared with the

26 47

additional fuel gas required to generate steam for pre-combustion capture. Existing heaters will typically require some modifications to enable firing of high hydrogen content fuels. These might include material upgrades to withstand a hydrogen flame temperature up to 300°F (150°C), higher than a methane rich fuel, or safety and control system modifications to accommodate hydrogen’s increased flammability range (these modifications may be significant to allow 100% hydrogen firing).

Fuel substitution Fuel substitution is an approach many refineries are already familiar with as facilities have moved away from higher emissions fuel oil to using natural gas. Replacing imported natural gas and refinery fuel gas with hydrogen is the next step in this progression, moving from high carbon to lower carbon to no carbon (at the point of combustion) fuels. Pre-combustion capture that has previously been discussed in this article is a form of substitution with operators generating the hydrogen on site, but they can also consider options where the hydrogen is generated by electrolysis and is considered green hydrogen. If a refinery moves to green hydrogen, this is acceptable whilst this substitution reduces natural gas imports, however once refinery fuel gas is displaced, then a problem is reached as there is nowhere else to send the RFG and the refiner must now start to look at reducing the RFG pool or looking for alternative outlets for the RFG.

Electrification The use of green hydrogen is effectively indirect electrification of the site, but direct electrification can also be considered. The replacement of fired duties with electrical heating is a developing area and different aspects of the replacement are at different levels of technology readiness. How readily a heater can be electrified is driven by the duty required and by the type of material being heated. As for direct substitution, this could drive the pool into excess as more areas are electrified so a clear plan on how excess fuel gas will be managed is needed.

Offset Once all practical steps to reduce and capture CO2 emissions within a refinery have been implemented, operators can consider offsetting residual emissions through external mechanisms. These options typically fall into three categories: n Purchase of verified carbon credits. n Investment in nature-based solutions such as afforestation, reforestation, and soil carbon sequestration. n Participation in compliance or voluntary carbon markets. While not a direct decarbonisation route, fuel gas management, specifically reducing composition variability and thereby limiting emission variability, allows for improved business forecasting of necessary offset investments or costs.

When fuel gas becomes a problem Some production of fuel gas is unavoidable in the refinery, so as a refinery reaches the point when all its remaining unmitigated fired heat comes from fuel gas, what options are there to push closer towards net zero emissions? For those facilities with pre or post-combustion, the simplest answer is to use the fuel gas as fuel and allow the carbon to be captured, although with current best available processes achieving 90 - 95% capture, this will not reduce emissions to zero and some offset may be required to achieve true net zero. Offset is of course an option that would allow fuel gas use to continue, although long-term offset of the entire refinery fuel gas pool is likely to be expensive and hurt the competitiveness of the facility. Where capture and offset are not the solution, the challenge becomes greater. Once any imported fuels are replaced, then any further move to lower carbon options leaves the refinery long on fuel gas. Refiners facing this position need to consider either how to dispose of fuel gas or reduce production. Options to reduce the fuel gas pool include: n Sell fuel gas over the fence to other users. n Recover C3+ materials for sale as LPG and naphtha. n Recover hydrogen for use on the facility. n Recover propylene and ethylene where present. n Recover ethane. n Modify operating conditions to minimise production. n Move to more selective processes and catalysts (less by-product). n Segregation of streams (not actually reduction but put highest carbon stream to capture, etc). Selling fuel gas to another user would allow the emissions to be counted as Scope 3 rather than 1 or 2 but the gas would ultimately still be combusted in the majority of cases. Recovering C3+ materials also allows emissions from these materials to be shifted to Scope 3 rather than Scope 1 or 2. In this case, the materials recovered can be included into existing product (LPG, naphtha, or gasoline) and can offer a revenue benefit as well as a reduction in emissions. That reduction can be partially achieved even if the fuel gas recovered is replaced with natural gas, as methane has a lower emission per t (or per unit of energy) than C3+ hydrocarbons. Determining the best route to reduce or use fuel gas as direct firing reduces can be a complex problem with a number of economic, technical, and environmental trade-offs to consider. Several factors can drive the outcome: it might not just be about emissions reduction, but also the plot space required, or which options are favoured by the local subsidy regime. Finding the optimum solution requires the industry to look at all these options to determine the most cost-effective route to eliminating emissions from fuel gas.

Reference 1.

BRIGMAN, et. al., Energy Procedia, Vol. 63, pp. 6012 - 6022, (2014).

Juan Ruiz and Michelle Wicmandy, KBC (A Yokogawa Company), discuss why industrial energy management is becoming forecast-driven and how this can optimise refinery operations.

hat if the best operating decision right now is not the best decision for what comes next? For decades, refinery energy managers optimised steam, power, and hydrogen systems around relatively predictable operating conditions. Maintaining the preferred operating point often delivered the best result. Today, refiners can adjust operations as current conditions change. But, the best decision also depends on what is expected to happen next. Electricity prices, renewable generation, hydrogen demand, and inventory levels can shift within hours, while sustainability requirements add further constraints to operating decisions. The future is becoming an operational input. According to the International Energy Agency (IEA), global hydrogen demand reached almost 100 million t in

2024, driven primarily by refining and chemical production. Although low-emissions hydrogen production grew by approximately 10% during 2024, it still represented less than 1% of global hydrogen supply, highlighting how early the industry is in its transition.1 Governments and industry continue to invest in industrial decarbonisation through low-emissions hydrogen and renewable power. Electrolyser capacity is expanding, and large scale hydrogen production is moving from demonstration projects to industrial deployment.2 For refiners, the challenge is integrating these new energy sources while managing their effects across the entire refinery energy system. Recent research supports this shift, finding that rolling-horizon optimisation enables industrial energy systems to continuously update forecasts and re-optimise operating decisions as conditions evolve.3

26 49

From asset optimisation to system coordination Historically, refinery utility systems have been managed largely through asset-level optimisation with minimum foresight. Operating conditions and interactions between systems were relatively predictable. Renewable electricity, large scale hydrogen production, inventory management, and participation in electricity markets are creating new dependencies across refinery operations. Hydrogen production illustrates this shift. Operating an electrolyser requires engineers to coordinate decisions across these interconnected systems. A decision that reduces costs within one system may increase costs elsewhere across the refinery, as shown in Figure 1. Engineers must now ask: how will this decision influence the performance of the integrated energy system now and over the next several hours?

Why static optimisation is not enough Traditional operating practices remain essential for maintaining safe and reliable refinery operations. However, maximising economic benefit while satisfying environmental restrictions increasingly requires engineers to evaluate how key variables change across the planning horizon. The challenge is determining how those decisions interact and which combination delivers the greatest value across the refinery. For instance, optimising onsite power generation while only considering current market conditions may reduce electricity purchase costs at the time (e.g. by shutting down a gas turbine) but it may limit opportunities to export electricity during favourable market conditions soon after. Decreasing electrolyser production when renewable power is scarce may lower costs initially but may alter steam balances or utility loading later in the day. Modern refineries already generate enormous quantities of real-time information. Due to an influx of AI/ML technologies,

there is an increasing availability of market price forecasts and predictions of renewable energy generation. The challenge is transforming that information into meaningful operating strategies that minimise cost while supporting production and decarbonisation objectives. Now, engineers must determine which sequence of operating decisions produces the best outcome over time. Time has become part of the optimisation problem. Research into industrial energy management also shows why planning horizon matters. In one industrial study, extending the optimisation horizon improved operating costs and CO2 outcomes by allowing the optimiser to anticipate renewable energy availability and make more informed forward-looking decisions.3 This requires a shift from a hindsight to a foresight approach, where the operating strategy must adapt continuously to changing market conditions, renewable generation, and production requirements. If electricity prices, hydrogen demand, and renewable generation can all change within hours, how should engineers determine the best operating strategy? Rolling-horizon optimisation addresses this challenge by repeatedly updating forecasts and re-optimising over a moving planning window while accounting for multi-period constraints (e.g. minimum downtimes and inventory limits). As new information becomes available, operational decisions adapt accordingly.4

Multi-period optimisation: a critical enabler

Consider a refinery integrating a 100 MW green hydrogen facility as part of its decarbonisation strategy. The investment aims to partially replace conventional hydrogen production and reduce dependence on fossil-based energy sources. But solving one problem creates another: when should the electrolyser run? The economics make that question consequential. Electricity can account for more than 64% of the levelised cost of hydrogen, making the timing of production economically significant.4 Electrolysers can adjust power consumption and hydrogen production as electricity availability and market conditions change. That flexibility has engineering limits. Operating range, ramp rates, start-up conditions, and efficiency influence how quickly and how far electrolyser loading can change. For refinery energy managers, the challenge is coordinating this flexibility with hydrogen demand as well as utilities and electricity-market Figure 1. Integrated refinery energy systems connect electricity, hydrogen production, conditions. Engineers need utilities, power generation, and process operations. a way to evaluate how 50

those decisions will perform as conditions change over the planning horizon. Multi-period optimisation addresses this challenge by allowing engineers to evaluate alternative operating pathways before implementing them. At the refinery, the multi-period energy optimiser continuously evaluates energy-market forecasts, hydrogen demand, utility requirements, and Guarantees of Origin (GoO) inventories over a rolling planning horizon. Using these forecasts, it generates 24-hour operating schedules and optimal setpoints for hydrogen production, utilities, power generation, and electricity imports and exports. For example, consider what can happen in a single day at the refinery. Overnight electricity prices may fall while renewable generation increases, making hydrogen production through the electrolyser economically attractive. Later in the day, electricity demand and prices may rise, making stored hydrogen a lower-cost option while reducing electrolyser loading. The most economical decision depends on current conditions and what is expected to happen next. By using a multi-period optimisation approach to anticipate these changes, engineers can select the operating strategy that delivers the greatest value across the planning horizon. Decarbonisation can therefore add both complexity and flexibility to refinery energy systems. Renewable electricity introduces variability, while electrolysers, hydrogen inventory, onsite power generation, and electricity trading create additional operating choices. The engineering opportunity lies in coordinating those choices rather than managing each asset independently.

Operating the refinery as one forecast-driven energy system The refinery implementation demonstrates an important principle that extends beyond a single facility. Within the optimisation environment, engineers coordinate decisions across six interconnected operational domains: n Electric network. n 100 MW electrolyser. n Hydrogen production unit. n Chemical plant. n Refinery power plant. n Process units. Within this integrated model, current operating conditions have become one of several inputs shaping the optimal pathway across the planning horizon. Forecasts of key variables must also be considered. For example, Figure 2 shows forecasted solar irradiation along with predicted power generation in solar panels. Forecasts become operational inputs rather than background information. If electricity prices are expected to fall later in the day, immediate hydrogen production may not be the most economical choice. Conversely, periods of abundant renewable electricity may justify increasing electrolyser production and building hydrogen inventory for later refinery demand. Figure 3 shows that the optimisation problem therefore shifts from selecting the best operating point to selecting the best operating pathway. In this case, the electrolyser produces green hydrogen when power costs are low, between 6 am and 10 am, and when solar irradiation is high, between 1 pm and 3 pm. Magnus Killingland, DNV, examines the growth of the European market and the new challenges producers and governments face.

he global hydrogen market is one that has the potential to scale significantly from where it stands today, even with lower earlier forecast predictions. As an energy carrier, hydrogen will not compete on cost with electrification where electricity is feasible, but it still remains one of the few viable solutions for decarbonising hard to electrify sectors such as steel, chemicals, shipping, and aviation. DNV’s ‘Energy Transition Outlook 2026: Hydrogen to 2060’ report, predicts that overall hydrogen volumes will grow by 170% and see cumulative investments of US$3.2 trillion through to 2060. This is despite a significant downward revision in the demand and uptake of hydrogen from the previous research conducted in 2022. Analysis points to China leading that expansion, and accounting for 35% of new hydrogen production and use over the forecast period. Looking to Europe, a sizeable growth in demand is also anticipated, with demand from European countries for hydrogen trebling by 2060, reaching 35 million t. Despite being poised for growth, the hydrogen market is still in a fragile position. The current and future clean hydrogen capacity will largely be driven by policies and implementation of legislation, meaning projects are proceeding only where credible, policy-backed demand exists.

Tobias Moss, Dräger, Germany, describes how Tobias Moss, Dräger, Germany, describes how safety enables profitable hydrogen scale-up. safety enables profitable hydrogen scale-up.

H H

ydrogen is becoming an increasingly important energy source – isworldwide, particularly important in Europe, energy which ydrogen becomingbut an increasingly is poor –inworldwide, natural resources. In a timeinofEurope, global energy source but particularly which transition and ongoing raw material it is aenergy crucial is poor in natural resources. In a timecrisis, of global factor in ensuring theand security of supply for critical infrastructure. transition ongoing raw material crisis, it is a crucial That isinwhy, for example, the German Federal Government’s factor ensuring the security of supply for critical infrastructure. National Hydrogen Strategy to expand the technology That is why, for example, theaims German Federal Government’s massivelyHydrogen by 2030 and to achieve atexpand least 10the GWtechnology of electrolysis National Strategy aims to 1,2 But every gigawatt of new capacity capacity inby Germany. massively 2030 and to achieve at least 10 GW of electrolysis multiplies the number of connections, valves, and storage vessels capacity in Germany.1,2 But every gigawatt of new capacity through which hydrogen escape. Whether thatstorage growthvessels stays multiplies the number of can connections, valves, and safe depends on how reliablyWhether this extremely flammable, through whichentirely hydrogen can escape. that growth stays and highly explosive, substance detectedflammable, in case safe therefore depends entirely on how reliably this is extremely of a leak. and therefore highly explosive, substance is detected in case the volume of hydrogen produced and used each year of As a leak. increases, so too does the complexity operators must As the volume of hydrogen produced and used eachmanage. year Plants thatso combine electrolysers withoperators solar arrays, wind turbines, increases, too does the complexity must manage. and legacy process systems now have to monitor, coordinate, and Plants that combine electrolysers with solar arrays, wind turbines, interoperate acrosssystems equipment different vendors, each and legacy process nowfrom havemany to monitor, coordinate, and with its own conventions. Greenfrom hydrogen, producedvendors, emission-free interoperate across equipment many different each via electrolysis using offshore wind power, isproduced another growing with its own conventions. Green hydrogen, emission-free sector. On offshore platforms, however, all components via electrolysis usingconverter offshore wind power, is another growing (electrolyser, compressor, and buffer) are usually housed together sector. On offshore converter platforms, however, all components in a single, compact, enclosed buildingare within a very confined (electrolyser, compressor, and buffer) usually housed together space. Thiscompact, significantly increases the potential the event of a in a single, enclosed building within arisk veryinconfined gas leak. Layered on topincreases of this operational complexity is aevent physical space. This significantly the potential risk in the of a one:leak. hydrogen itself number ofcomplexity dangerous is physical and gas Layered on possesses top of this aoperational a physical chemical properties that make aerrors andof delays far lessphysical forgiving one: hydrogen itself possesses number dangerous and than in most other process industries. chemical properties that make errors and delays far less forgiving than in most other process industries.

A source of hope with potential dangers Hydrogen (H ) isof thehope lightest and smallest of all molecules. It A source with potential dangers

Anton Korobeynikov, Integrated Global Services (IGS), Czech Republic, presents case studies outlining strategies for the improvement of existing steam methane reformer assets.

diffuses rapidly, materialsofand escapes more Hydrogen (H2) ispenetrates the lightestmany and smallest all molecules. It easily than mostpenetrates other gases. Evenmaterials seemingly airtight containers diffuses rapidly, many and escapes more and allow hydrogen to escape over time. easilyseals thancan most other gases. Even seemingly airtight containers Furthermore, it ishydrogen invisible, odourless and tasteless, and seals can allow to escape over time. and therefore offers no warning signs. Leaks cannot therefore Furthermore, it issensory invisible, odourless and tasteless, and be detected by humans – unlike natural gas, which is usually mixed therefore offers no sensory warning signs. Leaks cannot therefore with an odourant. be detected by humans – unlike natural gas, which is usually mixed Hydrogen forms explosive mixtures with air at concentrations with an odourant. ranging fromforms around 4% by volume, the lower explosive limit (LEL), Hydrogen explosive mixtures with air at concentrations to 77% by volume, the4% upper explosive (UEL). This range is ranging from around by volume, thelimit lower explosive limit (LEL), considerably wider than that of methane (LEL 4.4%, UEL 17%) to 77% by volume, the upper explosive limit (UEL). This range is or propane (LEL 1.7%, UEL 10.8%), meaning dangerous considerably wider than that of methane (LELthat 4.4%, UEL 17%) concentrations be UEL reached verymeaning quickly. that dangerous or propane (LELcan 1.7%, 10.8%), As little as 0.02 sufficientvery to ignite hydrogen – significantly concentrations canmJbeisreached quickly. lessAsthan petrol vapour. Static electricity, small littlefor as methane 0.02 mJ isorsufficient to ignite hydrogen – significantly sparks and high temperatures are sufficient to cause ignition. less than for methane or petrol vapour. Static electricity, small Hydrogen ignites at temperatures of around 560˚C.ignition. This is the sparks and high temperatures are sufficient to cause same as methane, lower than forofmany other industrial Hydrogen ignitesbut at temperatures around 560˚C. This isgases. the Furthermore, hydrogen is approximately times lighter gases. same as methane, but lower than for many 14 other industrial than air, meaninghydrogen that leaked hydrogen gas rises rapidly and Furthermore, is approximately 14 times lighter accumulates under ceilings orhydrogen in poorly gas ventilated rooms. than air, meaning that leaked rises rapidly and The substance burns withorainpale blueventilated flame that is almost accumulates under ceilings poorly rooms. invisible, particularly in daylight. Combined with its is tendency The substance burns with a pale blue flame that almost to give off very little radiant heat whilst burning, this makes invisible, particularly in daylight. Combined with its tendencyit difficult to very detect fires and increases theburning, risk of injury to staffit at to give off little radiant heat whilst this makes industrialtosites. There no increases carbon in the the risk molecular structure difficult detect firesisand of injury to staff at of hydrogen. Conventional detect industrial sites. There is no infrared carbon ingas thedetectors, molecularwhich structure

lobal hydrogen demand reached almost 100 million t in 2024, yet more than 99% is still produced using fossil fuels, primarily through steam methane reforming (SMR). Improving the efficiency of existing hydrogen, ammonia, or methanol production assets, therefore, remains one of the fastest and lowest-capital opportunities to reduce operating costs and carbon emissions.

Priyan Mistry, Honeywell Technologies, details how ammonia is the key to unlocking hydrogen transportation to support the global hydrogen economy.

he global low-carbon hydrogen economy is approaching an important moment. Over the past decade, governments, developers and technology providers have concentrated on scaling production. National hydrogen strategies have been published across Europe, Asia, and the Middle East, investment has flowed

into low-carbon hydrogen projects, and significant advances have been made in electrolysis, carbon capture, and process technologies. Together, these developments have laid the foundations for a global hydrogen market. As the industry moves from ambition to implementation, however, the focus needs to move from production

of hydrogen. Conventional infrared gas detectors, which detect

31 31

Jens Conrad, Everfuel A/S, Denmark, discusses large scale green hydrogen production in Denmark and pipeline export to Germany.

Katsuyuki Takano, Ebara Elliott Energy, analyses how return gas blowers can be designed to safely manage liquid hydrogen during storage and transfer.

urope’s green hydrogen market is at a crossroads. The hype of recent years is apparently over and reconsolidation is well underway. Significant projects have proven that the production of renewable hydrogen via electrolysis is viable. The next steps are, however, more challenging. Can large scale hydrogen production operate reliably, flexibly, and economically enough to serve industrial customers through cross-border infrastructure? Is the demand side ready to receive large quantities of hydrogen? How can the necessary infrastructure be put in place? The HySynergy project in Fredericia, Denmark, and the planned Frigg project in Vejen illustrate this transition from site-level demonstration to large scale hydrogen export. Germany is central to this story. Its hydrogen import strategy expects national demand for hydrogen and hydrogen derivatives to reach 95 - 130 TWh/yr by 2030, with 50 - 70% of this demand expected to be covered by imports. By 2045, hydrogen demand alone is projected to reach 360 - 500 TWh/yr, in addition to around 200 TWh of hydrogen derivatives. The government expects the share of imports to increase further after 2030.1 Denmark is explicitly among the expected supplier countries, alongside Norway and the UK. For German steel, refining, chemicals, e-fuels, and heavy transport, imported renewable hydrogen is not a niche topic; it is one of the enabling conditions for decarbonisation. Denmark’s role is equally strategic. Western Denmark has strong wind resources, grid interconnections, potential hydrogen storage, and proximity to northern German demand centres. The emerging Danish Hydrogen Backbone is intended to connect renewable power-based hydrogen production in Jutland with domestic demand and export routes to Germany.

The Autumn issue of Global Hydrogen Review is out now

Read the issue here Subscribe for free:

www.globalhydrogenreview.com

s the global momentum toward decarbonisation accelerates, countries are increasingly shaping their energy strategies around available regional resources and economic budgets. For nations with limited local renewable energy but robust financial means, importing large quantities of hydrogen is expected to significantly drive up demand for vital applications in power generation, mobility fuels, and steelmaking. Liquid hydrogen (LH2) stands out as a highly promising carrier for transporting these massive volumes across the global supply chain. However, successfully transferring and storing LH2 at loading and receiving ports presents distinct infrastructure challenges, particularly regarding tank pressure management. Much like conventional LNG operations, a specialised blower, known as a return gas blower (RGB), is vital to handle boiled-off hydrogen gas, ensuring that tank pressure balance is maintained safely and effectively during the transfer process. In order to maintain the pressure balance in LNG carrier tanks when receiving LNG at receiving terminals, a return gas blower is required to return boiled-off natural gas

Daniel Patrick, Atlas Copco Gas and Process, explores the compressor and expander technologies that can support the liquid hydrogen value chain.

generated in onshore storage tanks to tanks onboard LNG carriers (Figure 1). For LNG, the temperature of the gas is about -162°C, which is higher than the boiling point of nitrogen (-196°C); nitrogen itself is an inert gas, so it could be used to seal the blower. The temperature of LNG is also higher than the boiling point of oxygen, eliminating concerns regarding the generation of liquefied oxygen on the outer casing surface. On the other hand, unlike conventional LNG, liquefied hydrogen has a lower temperature of -253°C. If a comparable unloading process is applied to liquefied hydrogen, even the boil-off gas from onshore tanks is expected to be approximately -253°C. If this gas is returned to the carrier like LNG, the -253°C flow will cool the blower’s metal parts, potentially liquefying the surrounding oxygen and nitrogen. When air is liquefied, a large amount of liquid oxygen is produced, causing a risk of explosion. Therefore, in order to safely operate a blower at extremely low temperatures under normal operating conditions, a vacuum insulation structure must be installed on the casing blower body to prevent liquefied oxygen from being generated, and the outer surface of the blower must be -183°C or higher.

s global hydrogen trade takes shape, liquid hydrogen (LH2) is emerging as one of the most practical ways to move large volumes over long distances. A 2024 study by the European Commission’s Joint Research Centre found that LH2 shipped beyond 2500 km carries a lower environmental impact than chemical carriers like ammonia or liquid organic hydrogen carriers (LOHCs), largely because LH2 avoids the energy-intensive step of unpacking the hydrogen at the destination.¹ But between the production plant and the final customer, there is a complex chain of infrastructure: liquefiers, storage tanks, loading terminals, carriers, and import terminals. Every step in that chain depends on rotating equipment, and every step presents its own operating conditions and machinery requirements. This article examines each stage of the LH2 value chain, from plant to port, and looks at the compressors and expanders that make each step possible. See Figure 1 for an overview of the hydrogen value chain and the specific liquid hydrogen subsection this article will focus on. In every part of the value chain, the equipment must be designed around hydrogen’s unique properties. With a molecular weight of just 2 g/mol and a boiling point of -253°C, hydrogen presents unique challenges for machinery designers. Fortunately, decades of experience from LNG and hydrogen-rich petrochemical services provide a strong foundation to build from.

Production: the first compression step Before hydrogen can be liquefied, it must be produced and compressed. Electrolysers typically deliver hydrogen

Erwan Bruneau, Air Products, investigates how refuelling stations can be designed to scale hydrogen deployment across Europe’s transport and industrial sectors.

urope’s hydrogen economy is entering a critical phase. The strategic rationale for hydrogen is well established in sectors where direct electrification is constrained, particularly in heavy-duty transport and selected energy-intensive industrial processes. Hydrogen also remains essential as a process gas or feedstock in a range of industrial applications. The key question is no longer whether hydrogen has a role to play, but how sustainable hydrogen supply chains can be integrated to support new applications at commercial scale. This transition is proving more complex than early expectations suggested. Across Europe, hydrogen markets are evolving along different pathways, shaped by varying regulatory environments, end-use requirements, and infrastructure constraints. Transport, industry, maritime, and even aviation are advancing technologies that use renewable and low-carbon hydrogen, while regulatory

at relatively low pressures, while downstream steps like liquefier feed, pipeline injection, and buffer storage require higher pressure. This first compression step looks different from the rest of the chain. Flow rates at a single production site are still modest by turbomachinery standards, and hydrogen’s low molecular weight limits the pressure ratio a centrifugal stage can deliver. As a result, positive displacement machines carry the production workload today. The two most common positive displacement compressors in hydrogen production plants are reciprocating and screw. Reciprocating compressors handle high pressure ratios efficiently and remain the workhorse for hydrogen compression. Screw compressors provide steady flow with fewer pulsations and lower maintenance demands but at moderate pressure ratios. Hybrid arrangements, such as a screw machine boosting the suction of a reciprocating unit, combine the strengths of both. The right selection depends on flow, pressure, and duty cycle, and quite often the best answer is a combination. Renewable-powered production adds another design consideration, since intermittent electrolyser operation favours machines that tolerate frequent starts, wide turndown, and variable suction conditions. As production scales toward world scale facilities, centrifugal compression will eventually enter the conversation for feed and pipeline service. For now, positive displacement machines remain the practical choice for production compression, and the centrifugal story begins at the liquefier. Figure 2 summarises the main compressor and expander applications covered in the following sections.

environments continue to evolve and have yet to fully keep pace with deployment. At the same time, infrastructure must be designed with safety and scalability at its core, enabling it to support growing demand and accommodate both gaseous and liquid hydrogen. This is where the focus shifts from ambition to implementation. Supply alone does not create markets; what matters is how effectively hydrogen is delivered from production to end use, suited to its application, and with robust certification in place. The next phase of deployment will be defined by the quality and reliability of these systems.

Hydrogen markets are forming – but not uniformly

Policy is beginning to create demand signals across multiple sectors. Yet these signals do not produce a uniform market. Instead, hydrogen is increasingly differentiated by classification, certification status, and application. Its use

Figure 2. Multi-period optimisation relies on renewable energy forecasts as inputs to the model.

Figure 3. Coordinated optimisation improves more than operating economics. By aligning hydrogen production with periods of lower-carbon electricity, operators can reduce the carbon intensity of hydrogen production while maintaining reliable supply.

The future of industrial energy management Expanding renewable energy standards and reporting requirements are introducing new constraints into refinery optimisation. Renewable energy availability and certification inventories must therefore be considered alongside cost and operational requirements when determining the optimal operating strategy.5 As industrial decarbonisation reshapes refinery energy systems by adding new assets, a higher level of integration between units and more complex certification structures, engineers must coordinate decisions not only across assets but also across time. Expected market conditions, renewable generation, and operational constraints should now be considered to determine the best operating pathway. What will happen in the future is becoming an important part of how the refinery should operate today. This requires enhancing the traditional energy management tools that refineries have available. Multi-period optimisation, 52

which considers not only the current condition of the plant but also future conditions as well as complex monthly or even yearly contracts, is becoming the key tool to tackle these challenges.

References 1.

2. 3.

4. 5.

‘Global Hydrogen Review 2025: Executive Summary’, (2025), International Energy Agency (IEA), https://www. iea.org/reports/global-hydrogen-review-2025/executivesummary CARRARA, N., RUIZ, J., and RUIZ, C., ‘Green hydrogen at scale’, EnviroTech: a supplement to Hydrocarbon Engineering, pp. 43 - 48, (2025). KYRIAKIDIS, L., KANSARA, R., and ROLDÁN SERRANO, M. I., ‘Energy management of industrial energy systems via rolling horizon and hybrid optimization: A real-plant application in Germany’, Energies, 18 (15), 3977, https://doi.org/10.3390/en18153977 AMINAHO, AMINAHO, and AMINAHO, ‘Techno-economic assessments of electrolyzers for hydrogen production,’ Applied Energy, Vol. 399, (2025), Article 126515. RUIZ, C., CARRARA, N., and WICMANDY, M. ‘From emissions reporting to operational governance’, Hydrocarbon Engineering, pp. 65 - 70 (March 2026).

Nikolaj Fischer, Burckhardt Compression, looks at how the reliability and efficiency of essential assets, such as compressors, influence the sustainability of hydrocarbon operations.

s industries around the world accelerate their sustainability agendas, the hydrocarbon sector faces a dual challenge. On the one hand, it must continue to ensure reliable energy supply and contribute to energy security, as hydrocarbons remain a central part of today’s economy. On the other hand, the sector is undergoing a structural transition towards lower‑carbon energy systems, driven by climate targets, regulatory pressure, and stakeholder expectations. Refineries, petrochemical complexes, LNG terminals, gas processing plants, and industrial gas facilities must therefore not only maintain reliable operation, but also reduce emissions, minimise resource consumption, and improve operational efficiency as part of this transition. For operators, sustainability is no longer a stand-alone initiative, it has become a core business requirement. Every major asset is expected to contribute to environmental performance, whether through reducing energy consumption, lowering greenhouse gas emissions, extending equipment life, or supporting circular economy principles. In this environment, compressors have emerged as a critical focus area. Reciprocating gas compressors are critical assets in many industrial operations. They run continuously, often

26 53

for decades, handling enormous volumes of gas and consuming significant amounts of energy throughout their lifecycle. Their impact extends well beyond production performance, influencing energy consumption, emissions, and overall operational efficiency. Key benchmarks of sustainability include measurements of an operation’s greenhouse gas footprint. Direct emissions, such as fuel burned by boilers and manufacturing processes are classified as Scope 1. Indirect emissions from the generation of energy used on site are categorised as Scope 2, while other value chain emissions are typically captured under Scope 3. Therefore, a compressor’s efficiency directly influences Scope 2 emissions where electrically driven, while leakage and venting contribute to Scope 1 emissions. Equipment lifespan, maintenance practices, lubrication requirements, and spare parts replacement play a key role in determining both efficiency and leakage, while also affecting overall resource utilisation. Given their long operating life, continuous runtime, and substantial energy throughput, compressors represent a significant and often underutilised opportunity for operators seeking meaningful sustainability improvements. Through advanced compressor solutions, lifecycle support, digital technologies, emissions management programmes, and refurbishment strategies, manufacturers and service providers can support operators improving performance while also advancing their sustainability objectives.

Finding sustainability potential For many industrial operators, sustainability initiatives often focus on new investments. However, some of the most significant opportunities for reducing emissions and

conserving resources can be found within existing equipment fleets. Across the hydrocarbon industry, thousands of compressors continue to operate long after their original design life, with many working for several decades, in some cases exceeding 50 - 60 years when properly maintained. Many are obsolete, with manufacturers no longer in the market, while others face limited OEM support or suffer from declining reliability and efficiency. One common response, particularly for older equipment where original manufacturer support is no longer available, is to replace rotating equipment. While replacement can be necessary in certain cases, it also requires significant capital investment, consumes substantial resources during manufacturing and transportation, and often involves long lead times that can extend beyond 12 months. It is important to recognise that sustainability is not only about installing new technology. It is equally about maximising the value, efficiency, and lifespan of existing assets. Through advanced engineering, modernisation programmes, and comprehensive service solutions, leading manufacturers can help operators transform ageing compressors into high-performing assets with improved environmental performance. The result is a powerful combination of environmental and economic benefits: lower emissions, reduced energy consumption, improved reliability, extended equipment life, and avoidance of unnecessary manufacturing impacts.

Reliability and sustainability: hand-in-hand

In industrial operations, sustainability is difficult to achieve without reliability. Unplanned compressor downtime can interrupt production, create safety risks, and generate significant financial losses. By improving reliability, operators can simultaneously reduce waste, lower resource consumption, and improve environmental performance. Delivering these improvements in practice requires more than local presence; it depends on a multidisciplinary service capability that combines deep compressor expertise with advanced diagnostics and digital tools, helping customers to identify root causes, optimise performance, and implement long-term solutions rather than Figure 1. Gas compressors offer a strong opportunity to reduce Scope 2 emissions. temporary fixes. 54

From issues to solutions An example comes from South Africa, where a major gas supplier operates two dry-running hydrogen compressors. For years, the compressors experienced severe performance challenges. Monthly replacement of wear parts had become routine; internal leakages were high; energy efficiency suffered. Most significantly, product losses reached up to 20%, creating both economic and environmental consequences. As specialists in dry-running compression technology, Burckhardt Compression conducted a comprehensive root-cause analysis and identified several underlying issues affecting performance. The solution involved redesigning the second-stage packing case assemblies, developing a new piston ring set, refurbishing piston rods, and renewing cylinder liners. The results exceeded expectations. Production losses dropped from 20% to 2%. Internal leakage was effectively eliminated. Energy consumption per cubic metre of compressed gas decreased by 25%. Wear part life increased substantially, reducing maintenance interventions and associated costs. Most importantly, the compressors operated for 22 months without incident. The sustainability impact was equally significant. Reduced leakage lowered process gas emissions, while improved efficiency decreased energy consumption and associated indirect emissions. Extended component life also reduced material consumption and maintenance-related resource use. The operator was impressed with the results and the project illustrates how engineering expertise can simultaneously improve profitability, reliability, and environmental performance.

Rejuvenating existing assets One of the most powerful sustainability strategies available to industry is extending the life of existing assets. Another example comes from Europe, where a leading oil and gas operator needed to reduce compressor gas flow by more than 50% to meet new process specifications. Following a comprehensive engineering study and detailed inspection, Burckhardt Compression delivered a complete compressor revamp, including new, smaller-diameter cylinders and a full overhaul of key components. The upgraded compressor now operates efficiently at the required lower flow rate without relying on an energy-intensive bypass system. By matching compressor performance to the new operating conditions, the customer is saving approximately 1800 MWh/yr of energy, reducing both operating costs and associated carbon emissions. At the same time, the project extended the life of the existing asset, avoiding the environmental impact and cost of replacing the compressor. The project demonstrates how strategic equipment modernisation can help industrial operators improve efficiency, maximise the value of existing assets, and make measurable progress towards their sustainability goals.

Figure 2. Advanced engineering and modernisation programmes can transform ageing compressors into high-performing, sustainable assets.

Figure 3. Sustainability is about maximising the value, efficiency, and lifespan of existing assets.

Benefits far beyond cost savings By reusing an existing asset instead of manufacturing and transporting a new compressor, the project avoided approximately 20 t of CO2 emissions. It also significantly reduced project lead times while supporting the customer’s sustainability objectives and circular economy strategy. The project demonstrates how sustainability and business performance can reinforce one another. Through creative engineering and lifecycle expertise, existing equipment can often deliver value while avoiding unnecessary environmental impacts.

Eliminating waste Another critical sustainability challenge for compressor operators involves lubrication management and process contamination. An Indian oil corporation encountered this issue with a Laby compressor operating in a propylene application. Over time, deficiencies within the lubrication system had led to increased oil consumption, wear-part degradation, and reduced reliability. The consequences were significant. Frequent maintenance interventions disrupted operations and increased costs, while excessive lubricant consumption created additional environmental burdens. Burckhardt Compression conducted a detailed assessment and identified opportunities to improve sealing performance through a specially engineered rod packing system designed specifically for propylene service.

26 55

Figure 4. Even obsolete assets can be revamped and optimised using reverse engineering.

For operators seeking even greater environmental performance, it is possible to tailor gas recovery systems. Passive recovery systems redirect leaked gas back to the compressor suction side in lower-pressure applications. Active recovery systems re-pressurise and reintegrate gas into higher-pressure circuits. Rather than venting or flaring valuable product, operators can recover and reuse gas within the process, reducing emissions while improving profitability. The result is a practical pathway towards low emission operations, improved energy efficiency, and reduced regulatory compliance risk.

Digitalisation and sustainability The upgraded solution delivered measurable improvements across multiple performance indicators. Lubricating oil replacement frequency decreased from once every three months to just once a year. Oil carryover was eliminated, ensuring cleaner process gas. Wear-part life increased significantly, supporting maintenance strategies and reducing resource consumption. Most importantly, compressor reliability improved substantially, helping to eliminate recurring operational challenges. This example highlights a fundamental principle of sustainable industrial operations: reducing waste often begins with solving technical problems. Better sealing performance not only improves reliability but also reduces lubricant consumption, minimises emissions, and lowers lifecycle costs. Sustainability extends beyond equipment upgrades. It also depends on maintaining assets correctly throughout their operational life.

Sustainable compressor operation increasingly relies on improved data availability and analytics. Digital technologies are transforming how operators manage equipment performance, maintenance schedules, and emissions control. As digital service solutions become more widely adopted, customers can gain deeper visibility into compressor health and operational efficiency. By identifying performance deviations early and enabling predictive maintenance strategies, digital tools help prevent failures, reduce unnecessary interventions, and optimise energy consumption. This capability is becoming increasingly important as operators seek to balance reliability, sustainability, and cost control. Digitalisation enables more informed decision-making, supporting both operational efficiency and long-term environmental performance.

Tackling fugitive emissions

Engineering the future of industrial sustainability

While energy efficiency remains a key sustainability metric, compressor-related emissions management is becoming equally important. Gas leaks negatively affect operational efficiency, profitability, environmental performance, and workplace safety. As regulatory requirements become more stringent and net zero commitments gain momentum, operators are increasingly focused on identifying, measuring, and mitigating fugitive emissions. Addressing these challenges requires a systematic approach that combines measurement, analysis, and targeted engineering improvements. Assessment and optimisation programmes, such as Burckhardt Compression’s BC ACTIVATE, illustrate how this approach can be implemented in practice, combining on-site leak detection and flow measurements to identify and quantify emission sources.

Customised solutions Once leaks are identified, engineers work closely with customers to develop customised mitigation strategies. Solutions include advanced cylinder designs, optimised valve covers, and modern packing systems incorporating purge and buffer technologies. These upgrades can significantly reduce leakage while improving safety, efficiency, and equipment longevity.

The transition towards a lower-carbon industrial future will not be achieved through a single technology or a single investment. It will require continuous improvement across every asset, process, and operation. Compressors represent an often-underestimated opportunity for achieving significant gains in efficiency, emissions reduction, and resource conservation. Operators can unlock this potential by addressing fugitive emissions, improving energy efficiency, extending equipment life, implementing digital solutions, and refurbishing legacy assets. Sustainability and performance are not competing priorities. In fact, they are increasingly inseparable. Combining leading compressor technology with lifecycle expertise, emissions management capabilities, and innovative service solutions enables customers across the hydrocarbon industry to operate more reliably, more efficiently, and more sustainably. In an era where every asset must contribute to environmental progress, significant potential can be unlocked by making existing equipment perform better, last longer, and consume fewer resources. That is not just good engineering, it is good business – and a vital step toward a more sustainable industrial future.

Recent improvements in isolation, control, and pressure relief valves can reduce emissions and cost of ownership, while improving performance and longevity. Jean Paul Boyer, Oznur Celikkol, Jacqueline Onditi, and Sergio Zaghen, all from Emerson, explain.

cross Europe’s chemical industry, increasingly stringent environmental regulations are driving reductions in fugitive volatile organic compound (VOC) emissions, improvements in energy efficiency, and stronger operational safety practices. Updated best available techniques (BAT) reference documents (BREFs) emphasise pollution prevention at the source across major process sectors, reinforcing compliance expectations under the EU’s Industrial Emissions Directive. EU chemical safety legislation administered by the European Chemicals Agency (ECHA) – such as Registration, Evaluation, Authorisation, and Restriction of Chemicals (REACH) and Classification, Labelling, and Packaging (CLP) – supports safer handling and use of

chemicals, strengthening requirements for emissions control and equipment integrity throughout the value chain. These regulatory pressures align with the EU Chemicals Industry Action Plan, which prioritises decarbonisation, energy‑efficient modernisation, and innovation across the sector. Standards such as EN 17628 further formalise how diffuse VOC emissions should be detected and quantified, underscoring the need for reliable, low‑leakage valve technologies in modern plants. Within this regulatory context, all types of valves must comply with a wide range of performance, safety, and documentation requirements. Fortunately, a host of recent design improvements in isolation valves,

26 57

industry expectations for traceability and long-term operational safety. High-performance butterfly valves (Figure 1) meet these requirements through several design features aligned with NE167. They are certified to ISO 15848-1 tightness class BH and endurance class CO3, supporting TA-Luft–applicable low emissions service. Their interference fit PTFE/RTFE seat provides EN 12266 1 Rate A bi directional shutoff Figure 1. Advanced isolation valves designs (Keyston K-LOK® Series 38 High Performance without requiring pressure Butterfly Valve from Emerson shown) provide bubble tight isolation, meet NAMUR assistance, and the seat remains NE167 requirements, and comply with ISO 15848-1 BH CO3 standards for seal leakage. fully functional in vacuum conditions down to 1.354 × 10-3 millibar, ensuring reliable isolation even with low pressure and/or particulate laden media. NE167 highlights the importance of face‑to‑face standardisation, specifying preferred rows per DIN EN 558. Modern designs comply with these requirements, offering both Series 20 and Series 25 face‑to‑face options for interchangeability within plant piping systems. Their materials – EN 1.0619 carbon steel and EN 1.4408 stainless steel – adhere to NE167’s metallurgical and traceability expectations, and their designs incorporate anti‑static continuity, blow‑out‑resistant shafts, permanent marking, and ISO 5211 direct‑mount interfaces, fulfilling both safety and automation‑readiness criteria. Together, these capabilities demonstrate how advanced isolation valves support Europe’s environmental‑performance, Figure 2. Moderately priced control valves are energy‑efficiency, and safety objectives by combining available that offer high performance, extended life, emissions‑certified sealing, NE167‑aligned construction, and and low emission packing, but buyers should beware robust mechanical and dimensional compliance. of low price, low performance alternative designs. This bolted bonnet FisherTM GX valve from Emerson carries an ISO 15848-1 BH rating and can withstand up to a million cycles.

control valves, and pressure relief valves (PRVs), as well as in the relevant valve actuators, offer significant improvements in performance, while reducing emissions, extending service life, and increasing profitability.

Isolation valve designs Automated and manual isolation valves perform a critical role in the chemical and hydrocarbon industries. Obviously, these valves must be capable of isolating the process with essentially zero leakage, but there are additional, less obvious design features that impact valve and plant performance. The NAMUR NE167 standard defines common delivery conditions for valves and accessories, referencing DIN EN 16668 for shell strength, DIN EN 12266-1/2 for pressure and leakage testing, DIN EN 558 for face-to-face dimensions, EN ISO 5211 for actuator interfaces, and ISO 15848-1 for fugitive emissions testing. It also covers material requirements, positive material identification, electrostatic discharge protection, and marking obligations – including heat numbers, flow direction, and actuator interface designation – all of which reflect chemical 58

Control valve design alternatives European chemical producers operate in an environment where efficiency, regulatory compliance, and safety are inseparable. As plants modernise to remain competitive in a global market marked by rising energy costs and stricter environmental targets, equipment reliability plays a decisive role in safeguarding both profitability and operational continuity. High performance control valves (Figure 2) have been developed specifically with these challenges in mind, often by expanding upon proven platforms with a design engineered for service with aggressive process media, demanding service conditions, and cost-efficient lifecycle performance. Some control valves include compact bolted‑bonnet construction, which delivers improved containment capability for demanding chemical services. In applications handling aggressive media such as sulfuric, hydrochloric, or nitric acid, this reinforced sealing architecture helps ensure high integrity of the process envelope, supporting strict safety and environmental expectations. Beyond safety, the right control valve directly contributes to lowering maintenance costs – a growing priority for

European operators striving to mitigate inflationary pressure on operating expenses. The bolted bonnet design enables technicians to service or rotate the actuator without removing the bonnet or disturbing the process seal, thereby significantly reducing downtime. According to internal testing by one valve manufacturer, this design improvement can yield up to 25% reduction in maintenance time. The simplified architecture – with optimised actuator selection, reduced parts count, and high component commonality – further decreases inventory complexity and lifecycle cost. Safety compliance is reinforced through the availability of advanced packing systems, including graphite ULF and ISO-Seal double PTFE, both of which meet stringent fugitive emission requirements such as ISO 15848-1. These solutions improve stem sealing performance and offer suitability for temperatures up to 371°C in demanding chemical processes. Advanced designs can accommodate the broad application diversity typical of chemical complexes. Multiple body materials – including stainless steels, duplex grades, Alloy 20, and Hastelloy – address corrosion challenges across acids, solvents, and polymerising fluids. Compatibility with EN and ASME standards, combined with flexible end connections (RF, SWE, BWE, NPT), ensure integration into European brownfield and greenfield installations. By combining European‑driven engineering, enhanced containment performance, and measurable cost savings, advanced designs deliver a modern answer to the evolving needs of the continent’s chemical sector. These designs provide operators with a reliable, compliant, and

Figure 3. The Bettis RTS electric actuator from Emerson delivers high torque with low power consumption and features an integral fail safe spring. This quarter turn unit incorporates an advanced controller with embedded PID and programmable stroke capabilities, and versions designed for linear valve applications are also available. economically sound valve solution – supporting the long‑term competitiveness of Europe’s chemical manufacturing base.

The premier source of technical and analytical information for the renewable energy industry Register for free at www.energyglobal.com

and may keep it from lifting at all. n A leaking bellows also allows PRV discharge header gas to escape to the environment, which can create significant flammable or lethal gas hazards, depending on the application. Bellows damage is not uncommon, and a recent study of 30 000 PRVs in different industries and from various valve manufacturers discovered bellows failure rates of 2 - 6%. Some sites try to detect failed PRVs by using a manual sniffer near Figure 4. New balanced PRV designs replace the failure prone bellows with an the bonnet to detect leaking gases, elastomeric diaphragm (left), while another design keeps the bellows but adds a piston that maintains PRV functionality even if the bellows should fail (right). but this method is unreliable, not quantifiable, and creates personnel hazards. Valve actuator advancements Several new PRV designs have been introduced to In remote locations where an air supply is unavailable, an address these problems. One design (Figure 4, left) eliminates electric valve actuator can be a good option. The limitation the bellows all together, while the second design (Figure 4, of these actuators has been the inability to guarantee a right) keeps the bellows but adds an internal piston that failsafe position on loss of electricity. While capacitors or allows the PRV to ignore backpressure, while minimising the other energy storage devices can be employed to drive a flow of fugitive emissions to the environment. valve to a failsafe state, such designs are prone to undetected The non-bellows design is well suited for applications failure that only becomes apparent when the valve fails to that cycle frequently, since bellows tend to fail quickly reach its safe position upon loss of power. under those conditions. The latter design is well suited for Bettis RTS electric actuators from Emerson deliver some aggressive applications where a metal bellows could high torque with low power consumption and feature an still be preferred, but the modified piston and adapter are integral failsafe spring (Figure 3). This quarter turn unit needed to maintain PRV functionality despite a bellows incorporates an advanced controller with embedded failure. That particular design can be fitted with a local proportional-integral-derivative (PID) control and pressure transmitter that immediately detects a failed programmable stroke capabilities, and versions designed for bellows and can calculate the rate of leakage to determine linear valve applications are also available. the extent of damage. Such real-time information can be These designs also incorporate a broad range of invaluable as it enables the operating staff to fully embedded diagnostics that detect changes in valve stroke understand the situation and decide if immediate action performance. The most advanced models even have an is warranted. option for implementing local control schemes at the valve that include PID control and programmable valve stroke profiles. Such capabilities can save significant capital in Conclusion applications where air actuation is not an option and local Chemical and hydrocarbon facilities continue to face control is required. difficult markets where efficient production, improved energy utilisation, and minimal fugitive emissions are paramount for profitable operation. In this environment, PRV design improvements advanced technological designs in isolation, control, and The chemical and hydrocarbon industries are awash in relief valves – and actuators – provide significant applications where multiple PRVs discharge into a header improvements in plant performance, while reducing leading to a flare or scrubber system. In these situations, a operating and maintenance costs. bellows style PRV must be used because it allows the PRV to The first step to take advantage of these designs usually lift at setpoint despite any variable backpressure it might starts with a discussion with a valve automation partner that encounter from the header. can explain the options and provide a well-planned strategic Bellows PRVs work well initially, but the metal bellows path to upgrade existing equipment. This approach will must be inherently flexible to allow the PRV to lift without empower end users to begin capturing the financial and interference during a pressure event. The thin, corrugated environmental benefits that these advanced designs bellows tend to develop cracks and pinhole leaks over time, provide. Such a partner can help determine a roadmap that creating significant issues, including: matches the schedule and budget of the facility, while also n A cracked or leaking bellows exposes the PRV disc to providing design and life cycle support into the future. variable backpressure, which elevates the PRV setpoint 60

Hydrogen and CCUS projects are exposing materials limitations in conventional downstream facilities. Kerry Drake and Philippe Allienne, Greene Tweed, discuss how organisations can use new developments in materials science to ensure longevity for future projects.

he energy transition from traditional fossil fuels towards renewable or sustainable energy (hydrogen and/or carbon capture) is forcing engineers to confront a reality that has remained largely hidden within conventional hydrocarbon operations. Many of the materials, sealing technologies, and equipment designs that have served the refining, gas processing, and petrochemical industries reliably for decades were never developed with pure hydrogen or high-concentration carbon dioxide service in mind. For years, hydrogen was present within refineries as part of process streams, hydrocracking operations, and desulfurisation units, while carbon dioxide was familiar through enhanced oil recovery projects and selected processing applications. What is changing is concentration, scale, and operating conditions. Equipment that once handled mixed gas streams is now being asked to operate with pure hydrogen, dense-phase CO2, supercritical CO2, and at significantly higher pressures for extended periods. Design pressure of natural gas pipelines is usually between 100 - 150 bar (1450 - 2200 psi). In CO2 pipelines, design pressure is much higher, typically 150 - 250 bar (2200 - 3600 psi). For the Northern Lights project, the world’s first cross-border CO2 transport

and storage facility, design pressure was defined at 310 bar (4500 psi). The recently published IEA ‘Global Hydrogen Review 2026’ highlights the scale of this transition, noting that global hydrogen demand exceeded 100 million tpy in 2025 for the first time. That milestone signals that hydrogen is no longer a niche technology or future opportunity. It is becoming an industrial reality. As deployment accelerates, the industry is discovering that assumptions about material compatibility developed for conventional service are often insufficient when applied to hydrogen and carbon capture infrastructure. At the same time, several hydrogen projects linked to carbon capture, utilisation, and storage (CCUS) developments continue to face delays associated with infrastructure readiness and economic viability like the H2Teesside Blue hydrogen project in the UK. While these challenges are often discussed in terms of transport networks, storage facilities, and permitting, they also reinforce the importance of equipment reliability, sealing performance, and long-term material behaviour. Materials capable of maintaining integrity over decades of operation are becoming just as critical as the infrastructure itself.

26 61

Beyond compatibility tables One of the most common misconceptions surrounding hydrogen and CCUS projects is that material selection can be reduced to simple compatibility charts. Compatibility represents only the starting point. Engineers now recognise that successful operation depends on understanding how materials behave under the combined effects of pressure, temperature, contaminants, permeation, stress, and time. A material that appears chemically compatible with hydrogen may still experience excessive creep under sustained loading. An elastomer that performs well with conventional hydrocarbons may suffer swelling, softening, or rapid gas decompression when exposed to high-pressure hydrogen. Similarly, materials that demonstrate acceptable performance in laboratory conditions may behave differently when subjected to decades of field operation. The challenge becomes even more pronounced when retrofitting existing assets. Across the energy sector, operators are exploring opportunities to repurpose pipelines, compressors, and processing equipment originally designed for natural gas or conventional hydrocarbon service.

While some infrastructure can be adapted successfully, others reveal unexpected vulnerabilities. These may include leakage through sealing systems as hydrogen permeates polymers, cracking in susceptible metallic components caused by hydrogen embrittlement, and blistering or cracking of elastomer seals during rapid gas decompression. Hydrogen’s exceptionally small molecular size means it can permeate materials more readily than many traditional hydrocarbon gases, creating performance issues that were never considered during the original design phase. In polymer seals, permeation can drive higher leakage rates and loss of containment. In susceptible metallic infrastructure, including pipelines, pressure vessels, and other pressure-containing components, absorbed hydrogen can also promote embrittlement and cracking under stress. These risks require engineers to reassess assumptions that have remained largely unchallenged throughout decades of conventional hydrocarbon operation. Compatibility data remains valuable, but it rarely captures the combined influence of pressure, temperature cycling, contaminants, and long-term mechanical loading that define hydrogen and CCUS service. This is driving the development of materials engineered specifically to address these conditions. Cross-linked PEEK, such as Arlon 3000XT®, represents one example of how materials science is evolving beyond simple chemical compatibility. By combining chemical cross-linking with maintained crystallinity, these materials achieve enhanced resistance to permeation and swelling alongside improved thermal stability, properties that compatibility tables simply cannot capture. The question is no longer whether a material can survive exposure to hydrogen or CO2, but whether it can maintain performance, containment, and reliability over decades of operation in environments that often push equipment well beyond its original design envelope.

The hydrogen challenge

Figure 1. Carbon dioxide presents critical challenges including corrosion, chemical interaction, and rapid gas decompression.

Figure 2. Hydrogen’s small molecular size allows it to permeate materials more readily than hydrocarbon gases.

Hydrogen presents a unique combination of material challenges that distinguish it from conventional hydrocarbon service. Its small molecular size creates new permeation consideration requirements throughout current processing, transport, and storage systems. Under high pressure, hydrogen can diffuse into polymers and elastomers, altering their mechanical properties and affecting long-term performance. The higher the pressure, the greater the potential for gas absorption and solubility, and the more significant the resulting material changes can become. While engineers have long understood hydrogen embrittlement in metallic systems, more attention is now being paid to how hydrogen interacts with polymers, elastomers, and composite materials throughout the value chain. Hydrogen also introduces the risk of rapid gas decompression in elastomer seals. Under pressure, hydrogen can dissolve within the sealing material. If pressure is released faster than the gas can escape, it expands internally, causing blistering, cracking, and, in severe cases, catastrophic seal failure. In conventional hydrocarbon service, these effects may be limited or manageable. Under high-pressure hydrogen conditions they become a primary design consideration, particularly for valves, compressors, pumps, and other critical flow-control equipment.

For high-pressure applications, the challenge extends beyond chemical compatibility. Engineers must also account for creep behaviour, deformation resistance, and long-term dimensional stability. Valve seats, seals, and compressor components operating in hydrogen service frequently experience significantly higher sealing forces than Figure 3. Hydrogen and CCUS projects are revealing the limitations of the existing materials, sealing technologies, and equipment design in comparable hydrocarbon applications. hydrocarbon operations. Hydrogen’s ability to migrate through microscopic pathways means that maintaining containment often requires increased contact pressures. Over time, this can accelerate creep and deformation in conventional materials, leading to leakage, reduced efficiency, and shortened service life. This is where engineered thermoplastics can prove their value. Arlon 3160XT, the glass-filled grade of Greene Tweed’s cross-linked PEEK platform, was specifically developed to Figure 4. In hydrogen systems, rapid gas decompression can cause seals to address the creep demands of blister, crack, or fail catastrophically. high-pressure hydrogen service. Compared to standard glass-filled PEEK, it delivers up to 200 times greater creep resistance under broadly similar risks overlooking the distinct degradation compressive loads, making it a technically sound choice for mechanisms that can affect equipment reliability and valve seats, backup rings, and reciprocating compressor long-term performance. components, where deformation under sustained load is a The most demanding conditions often occur when CO2 is well-documented failure mechanism. transported or processed in dense-phase or supercritical The challenge is particularly evident in compressor states. Under these conditions, carbon dioxide exhibits technology. Conventional hydrogen compressors operating properties that differ significantly from those encountered at within refineries have historically handled mixed gas streams lower pressures. Supercritical CO2 can behave as an effective containing varying concentrations of hydrogen and other solvent, altering its interaction with polymers, elastomers, and process gases. The emerging hydrogen economy requires the sealing materials. Components that appear stable under compression of much purer hydrogen streams, often at conventional operating conditions may experience substantially higher pressures. This combination of elevated unexpected softening, swelling, or loss of mechanical pressure, increased temperature, and lubricant-free operation performance when exposed to supercritical environments. is exposing limitations in piston rings, rider bands, valve In some cases, failure mechanisms can shift entirely, moving components, and sealing systems. from wear-related degradation to deformation-driven Operators are discovering that materials capable of leakage as material properties change under exposure. performing adequately for a few thousand operating hours Impurities further complicate material selection. Water, may struggle to meet emerging industry expectations for brine, and other contaminants present within captured service intervals approaching a year or more of continuous carbon streams can combine with CO2 to form carbonic acid, operation. Reliability targets are becoming a driver of material creating highly corrosive operating conditions. The precise innovation, particularly as operators seek to reduce composition of these streams varies significantly depending maintenance requirements and improve equipment on the source of emissions, meaning that each project may availability across large scale hydrogen infrastructure. present unique material challenges. Carbon dioxide captured from a power generation facility may have a very different impurity profile from carbon dioxide captured from a refinery A different set of CO2 problems or petrochemical operation. As a result, engineers are finding While hydrogen and CCUS projects are frequently grouped that generic material selection approaches are insufficient for together within decarbonisation strategies, the material many CCUS projects and that application-specific evaluation challenges associated with carbon dioxide service are is required to understand long-term behaviour. fundamentally different. Hydrogen is characterised primarily by permeation, leakage, and embrittlement concerns, albeit with some rapid gas decompression concerns with certain Failure mechanisms emerging material as well. Carbon dioxide introduces challenges As hydrogen and CCUS projects mature, several recurring associated with corrosion, chemical interaction, along with failure mechanisms are becoming apparent. Rapid gas rapid gas decompression. Treating the two environments as decompression remains one of the most significant concerns

26 63

for elastomeric sealing systems, while permeation continues to challenge both operational efficiency and containment integrity. The combination of high pressures gas solubility and resultant enhanced gas permeation can create conditions where conventional sealing materials experience severe internal damage during depressurisation events. For hydrogen systems, this affects both performance and safety. For carbon capture systems, it directly influences the economic and environmental effectiveness of the project. Creep is emerging as another critical consideration. Components operating under sustained load for extended periods may gradually deform, reducing sealing effectiveness and compromising long-term reliability. At the same time, engineers are encountering wear mechanisms associated with low-lubricity environments. Supercritical CO2 possesses poor lubricating characteristics compared with many conventional process fluids, increasing the risk of galling, seizing, and accelerated wear in pumps, compressors, and flow-control equipment. Small changes in component geometry or clearances can have a disproportionate impact on efficiency and equipment performance. These degradation mechanisms rarely occur in isolation. A component experiencing chemical softening may become more susceptible to creep. Increased creep may reduce sealing force, leading to leakage and further performance degradation. Understanding these interactions is becoming more important as operators seek to predict long-term reliability and avoid failure mechanisms that may not become apparent until years into service.

Testing for the unknown A significant challenge facing the industry is the limited operational history available for many hydrogen and CCUS applications. Conventional hydrocarbon infrastructure benefits from decades of field experience. Engineers can draw upon extensive operational data when selecting materials, designing equipment, and predicting service life. Equivalent datasets do not yet exist for many hydrogen and carbon capture applications, leaving organisations to make critical design decisions without the benefit of proven long-term operational evidence. This lack of historical data is one reason why testing, validation, and accelerated ageing programmes are assuming such a prominent role in project development. As a result, testing strategies are evolving rapidly. Rather than relying solely on conventional qualification methods, organisations are combining materials science, coupon testing, component evaluation, and system-level validation to build confidence in long-term performance. The objective is not simply to demonstrate that a material survives exposure to hydrogen or carbon dioxide, but to understand how it behaves over years of operation under realistic combinations of pressure, temperature, contamination, and mechanical loading. Accelerated ageing protocols are becoming particularly important because they allow engineers to investigate degradation mechanisms and identify potential failure modes long before equivalent field data becomes available. Digital modelling and simulation continue to play an important role, particularly in understanding mechanical 64

behaviour and system interactions. However, many engineers recognise that modelling alone is not enough. Hydrogen and CCUS applications involve complex interactions between chemistry, materials science, and operating conditions that can be difficult to predict accurately using simulation alone. As a result, the most successful development programmes often combine modelling with progressive experimental validation, moving from material-level testing to component-level evaluation and ultimately full-scale operational trials.

Designing for decades Perhaps the most important lesson emerging from hydrogen and CCUS projects is that long-term reliability must be considered from the earliest stages of design. Unlike many conventional process upgrades, carbon capture and hydrogen infrastructure are expected to operate for decades while maintaining exceptionally high levels of containment and performance. In geological carbon storage applications, operators must have confidence that critical systems will continue performing reliably over extremely long timescales. In hydrogen systems, maintaining containment, efficiency, and safety over years of continuous operation is equally important. This requirement is driving greater attention toward lifecycle performance rather than simply upfront capital cost. The debate between commodity materials and higher-performance engineered materials is assuming greater importance. While advanced materials may increase initial project costs, they can also reduce maintenance requirements, improve reliability, and minimise operational disruption over the lifetime of the asset. Material selection is now viewed as a strategic engineering decision with implications for reliability, efficiency, regulatory compliance, and overall project economics rather than simply a procurement exercise. Hydrogen and CCUS projects are revealing that the energy transition is not simply about new processes or new infrastructure. They are exposing fundamental questions about how materials behave in environments they were never originally designed to endure. Engineers are learning that traditional compatibility assessments, while still important, are no longer sufficient on their own. Long-term performance depends upon understanding the interaction between chemistry, pressure, temperature, mechanical loading, contamination, and time. As deployment continues to accelerate, organisations that successfully integrate materials science, process engineering, and operational experience will be best positioned to overcome these challenges. The limits being exposed today are not barriers to progress. They are providing the knowledge needed to build more reliable, efficient, and durable energy systems capable of supporting industrial decarbonisation for decades to come. In that sense, hydrogen and CCUS projects are doing more than reducing emissions. They are creating a deeper understanding of material performance that will influence the design and reliability of critical process equipment throughout the refining, gas processing, and petrochemical industries for years to come.

Rhys Jenkins, Servomex, discusses how gas analysis can drive performance and decarbonisation efforts in downstream operations.

as analysis is no longer just a compliance requirement. For refiners and petrochemical operators, it has become an important source of operational insight. While organisations working in downstream production must still meet the highest levels of safety, they are using continuous gas measurement to support wider business goals. This includes protecting assets, improving efficiency, and strengthening operational performance. Beyond helping meet emissions targets, gas analysis is also supporting the development of alternative fuels and new low-carbon feedstocks. This is helping many operators decarbonise in one of the world’s hardest-to-abate sectors. Ultimately, data is doing what it always does: supporting better decision-making. For many, this starts with effective process control.

Prioritising process control Efficiency and sustainability are closely linked. Optimising processes reduces energy consumption. And lower energy consumption helps to reduce emissions. Better process control also minimises waste, maximises the utilisation of assets, and delivers environmental and financial benefits. Safety is also a factor. By detecting hazardous gases early on, incidents can be prevented before they escalate, protecting workers, assets, and production. Through continuous monitoring, companies can strengthen safety performance while achieving compliance and reducing operational risk. Whether the priority is reducing emissions, improving process efficiency, maintaining compliance, or keeping people and assets safe, success depends on accurate, real-time visibility into process conditions. While these goals are individually accountable, they can all be tracked and achieved through reliable process data from accurate, continuous gas measurement.

26 65

Safety as a critical measure While producers face mounting pressure to meet demanding standards, safety is non-negotiable. In petrochemical and refining environments, cutting corners can have catastrophic consequences. These are complex, high-risk operations handling combustible, toxic, and asphyxiant gases, where even minor process deviations can lead to hazardous leaks, releases, or process shutdowns. As regulatory scrutiny intensifies, the cost of an incident extends beyond fines into operational downtime, reputational damage, and asset loss. One of the key challenges is that many gas-related hazards are invisible. Leaks often cannot be detected by operators alone, while small releases can rapidly escalate into fires, explosions, environmental incidents, or worker exposure. Continuous gas monitoring provides the visibility to identify issues early and respond before they become critical. Real-time insight into process conditions means operators can move from reactive safety management to a more proactive approach, detecting emerging risks, launching timely investigations, and taking swift corrective action. This means operations are safer, disruption is reduced, and productivity is restored faster.

Putting safety at the heart of the process Safety works hand in hand with compliance. Continuous monitoring provides evidence that processes are continually aligned with environmental and safety regulations, while fulfilling reporting, auditing, and verification requirements. By embedding safety into day-to-day operations, producers can reduce the likelihood of regulatory breaches and the penalties that will follow. The real business benefit of gas analysis today is operational protection. For personnel, this minimises exposure to hazardous gases and helps to create safer working environments. For assets, advanced measurement protects critical infrastructure and reduces risk of costly damage or shutdowns. And operationally, it enables production continuity, limits unplanned downtime, and strengthens resilience through constant process verification, control, and the earliest possible intervention. Safety may be a regulatory requirement but building it in from the start is key to ongoing operational success. The earlier risks can be spotted, the better prepared the industry is to protect the workforce, safeguard valuable assets, and keep production moving.

Better processes, boosted productivity Operators can only improve what they can measure. Continuous gas analysis provides the visibility to understand, control, and then optimise process performance. But having measurement tools in place is not enough. Decisions require confidence in the quality of the data. Inaccurate or inconsistent measurements can lead to inefficient operation, increased energy consumption, and avoidable emissions, limiting both productivity and sustainability progress. Combustion is a clear example. Effective combustion means maintaining the correct air-to-fuel ratio. Too much oxygen means excess air is heated and exhausted, wasting fuel and increasing costs. Too little oxygen means incomplete 66

Case study: how gas analysis supports hydrogen production Hydrogen is becoming key to decarbonising heavy industry. It can clean up refinery sulfur processes and provide the intense energy needed for steel and cement production. The world produced 1 million t of low-emission hydrogen in 2025, according to the International Energy Agency (IEA). But production still needs to increase roughly six-fold to meet net zero targets by 2050. CPH2 is one company helping close that gap, and continuous gas analysis is critical to its approach. CPH2 has developed a membrane-free electrolyser. Faster to manufacture, more durable, and free from expensive precious metals such as platinum, these electrolysers help reduce the cost of hydrogen production. Paired with solar and wind power, CPH2 systems have already replaced diesel backup systems. They are also powering buses and airport ground support equipment.

Protecting hydrogen purity through continuous measurement To support its membrane-free electrolyser technology, CPH2 needed a robust, highly accurate way to detect oxygen impurities in hydrogen. CPH2 selected the SERVOTOUGH OxyExact 220 gas analyser to provide continuous oxygen measurement throughout the process. Designed for oxygen-in-hydrogen applications, the analyser supports highly accurate oxygen monitoring, including in enriched oxygen environments (>21%) within hazardous areas. The analyser provides ongoing verification of oxygen levels within the electrolyser process. This helps CPH2 prove hydrogen purity, monitor system performance, and support safe operation. As hydrogen production scales, accurate oxygen measurement gives the company confidence in its membrane-free technology and supports deployment across industrial, transport, and energy applications. combustion, reducing efficiency while increasing risk of carbon monoxide formation, combustible carryover, and unsafe operating conditions. Precise oxygen measurement helps operators to continually optimise combustion conditions, maximising energy efficiency while ensuring safe, reliable operation. The benefits go beyond fuel savings. Efficient combustion needs less fuel to reach the same result, which directly reduces carbon dioxide emissions. Better process control can also help reduce waste, improve throughput, and make progress towards sustainability goals without risking productivity. Continuous monitoring helps operators to spot and correct process drift before it affects performance, reducing the likelihood of unplanned maintenance, emergency shutdowns, and production losses. This lowers operating costs, makes production more predictable, and gives operators more confidence.

Industrial-grade gas analysis Achieving these efficiencies requires analytical technology capable of accurate, trusted measurements in some of the industry’s most punishing environments. The SERVOTOUGH FluegasExact 2700 is built for combustion applications, using Servomex’s patented zirconia and thick-film technologies to simultaneously measure oxygen and combustibles. Designed for operating temperatures of up to 1750°C, its close-coupled low-flow extractive sampling system protects sensors from heavy dust and particulates, protecting the readings and the analyser. In utility boilers, process heaters, thermal crackers, furnaces, and incinerators, the analyser delivers the stable measurements required to optimise combustion, maintain safety, and reduce fuel consumption. Improved burner efficiency can reduce fuel costs by up to 4% while delivering lower NOX and SOX emissions and reducing maintenance requirements. For applications that require fast, in-situ measurement, the compact SERVOTOUGH Laser 3 Plus uses advanced tunable diode laser (TDL) technology to provide continuous monitoring of oxygen, carbon monoxide, methane, and ammonia. Its cross-stack design measures across the entire heater rather than at a single point, giving a more accurate view of process conditions for tighter process control. Its fast response times help operators quickly identify changing conditions, detect hazardous gas build-up, and optimise heater performance before inefficiencies take hold. By understanding exactly what is happening inside the process in real time, operators can optimise with confidence.

Accurate gas analysis provides the visibility to reduce emissions, lower costs, and maintain reliable, productive operations in the face of ever-shifting targets and expectations.

Decarbonisation depends on data A key driver behind many of the challenges facing refiners and petrochemical operators is the push towards decarbonisation. But this can only be achieved with a clear understanding of where emissions are coming from, characterising pollutants, knowing how processes are performing, and pinpointing improvements. Without accurate measurement, decarbonisation remains an ambition rather than an actionable strategy. The pressure to reduce emissions comes from multiple directions. Regulators are introducing stricter reporting requirements, investors are increasingly evaluating sustainability performance, customers are demanding cleaner, more transparent supply chains, and organisations are setting their own ambitious ESG and net zero targets. The challenge is to demonstrate measurable progress against these goals. For petrochemical and refining plants, this is easier said than done. These sites have multiple emissions sources, complex gas streams, and harsh operating environments that can make accurate measurement difficult. Variations in fuel composition, changing process conditions, and extreme operating temperatures can all affect measurement quality. As a result, producing reliable emissions data requires analytical solutions capable of accurate and consistent results under

Hydrocarbon Engineering On Hydrocarbon Engineering Online Hydrocarbon Engineering Online ydrocarbon Engineering Online ngineering Online Hydrocarbon Engineering Online Hydrocarbon Engineering Online

The for home The home the for the Thehome home forthe the The for e for the The home for the latest hydrocarbon latest hydrocarbon latest hydrocarbon The home for the latest hydrocarbon ocarbon latest hydrocarbon processing news, processing news, latest hydrocarbon processing news, ng news, processing news, processing news, analysis, comment analysis, comment analysis, comment processing news, analysis, comment omment analysis, comment and events and events and events analysis, comment and events d events and events and events Visit our website Visittoday: our website today: Visit website today: Visit ourour website today: ur website today:

Visit our website today: www.hydrocarbonengineering.com www.hydrocarbonengineering.com www.hydrocarbonengineering.com www.hydrocarbonengineering.com engineering.com www.hydrocarbonengineering.com Visit our website today: www.hydrocarbonengineering.com

ambitions into credible, measurable objectives, delivering value for the plant and for the environment.

demanding conditions. This is where advanced gas analysis has a critical role. Reliable measurement provides the data operators need to quantify emissions, establish achievable performance baselines, and confirm the impact of improvement initiatives. Using this real-time insight, operators can confidently monitor, report, and validate emissions while confirming compliance with environmental regulations and sustainability measures.

Advancing downstream efficiency

Turning emissions insights into action With greater visibility into process performance, operators can confirm opportunities to reduce fuel consumption, optimise combustion processes, improve energy efficiency, and minimise waste. Rather than relying on assumptions, broad reduction targets, or projections, producers can implement targeted, evidence-based initiatives for measurable benefits. Many emissions reductions are achieved by improving operational efficiency. Optimised combustion, more efficient energy use, and tighter process control can reduce both fuel consumption and greenhouse gas emissions while keeping productivity at its peak. Continuous monitoring means operators can keep track of the impact of improvements in real time, ensuring progress is measurable, verified, and continuous. And improving efficiency helps to lower operating costs, strengthen process reliability, and safeguard long-term competitiveness. By providing the real-time insight needed to understand emissions and optimise process performance, advanced gas analysis helps organisations turn broad decarbonisation

For refiners and petrochemical operators, the challenges of decarbonisation, process efficiency, compliance, and safety are often addressed separately. But they all rely on a common foundation – accurate, reliable, actionable process data. Advanced gas analysis gives operators the visibility to understand emissions at their facility, streamline performance, protect industrial assets, and maintain safe operations. The business value of advanced gas analysis is the flexibility to apply the right measurement solution to the right process challenge. Whether using zirconia, TDL, paramagnetic, thermal conductivity, or mass spectrometry technologies, these integrated analytical solutions provide the granular detail plants need to make informed, timely decisions. As the downstream industry continues to balance the demands of performance with sustainability, advanced gas analysis will play a vital role in helping organisations to achieve safer, lower carbon, and more efficient operations while tackling ambitious goals with greater confidence. We may be some time off 2050, but with the right analyser in place, industry can confidently move towards safer, low-carbon, and more efficient operations. Backed by trusted data, plant operators are ready to make informed decisions that turn ambition into measurable progress – and targets into results.

37 & 67 | Hydrocarbon Engineering IBC | Hydrocarbon Engineering Podcast 21 | Shell Catalysts & Technologies 43 & OBC | Sulzer

51 | Global Hydrogen Review

19 | VEGA

33 | Global Hydrogen Review Conference

09 | Wood Mackenzie

A podcast series for professionals in the downstream refining, petrochemical, and gas processing industries

LISTEN NOW

CCS: from concept to reality

Algert Prifti, CCUS Solutions Portfolio Manager at Black & Veatch, offers his thoughts on a wide range of topics, from the rise of gas-fired power to support the growth of data centres – and what this means for carbon capture and storage – to some of the challenges holding back broader CCS adoption, and how these can be overcome.

Drone security: protecting critical infrastructure

A discussion with AFPM’s Matthew Fuller about the growing security concerns surrounding unauthorised drone operations near critical infrastructure.

Laying the foundations for industrial AI

Simon Rogers, Chief Technology Officer at KBC (A Yokogawa Company), considers how physics-based models, AI, and contextualised enterprise data are converging to improve performance and decision making in the downstream sector.

Combating corrosion in oil, gas and energy assets: from design to maintenance

Logan Ballard, Key Account Manager, Energy, Sherwin-Williams Protective & Marine, explores how asset owners can take a proactive approach to corrosion prevention throughout the entire asset lifecycle.

Hydrocarbon Engineering Envirotech_2026