LNGNEWS
UK
02 – 05 February 2026
21st International Conference & Exhibition on Liquefied Natural Gas (LNG2026)
Ar-Rayyan, Qatar
https://lng2026.com
09 – 10 March 2026
LNGCON 2026
Barcelona, Spain
https://lngcongress.com
10 – 11 March 2026
StocExpo
Rotterdam, the Netherlands
www.stocexpo.com
18 March 2026
World Pipelines CCS Forum 2026
London, UK
www.worldpipelines.com/events/ world-pipelines-ccs-forum--london-2026
18 – 21 May 2026
Asia Turbomachinery and Pump Symposia (ATPS) 2026
Kuala Lumpur, Malaysia
https://atps.tamu.edu
01 – 05 June 2026
Posidonia 2026
Athens, Greece
https://posidonia-events.com
09 – 11 June 2026
Global Energy Show Canada 2026
Calgary, Canada
www.globalenergyshow.com
Gasrec opens new UK bio-LNG station
Gasrec has opened its second large scale, open access biomethane refuelling facility. The site at Hams Hall is now supporting fleet operators in making the switch to low-carbon fuels.
Hams Hall currently provides capacity for up to 300 trucks to refuel on bio-LNG every day, with that set to be expanded to accommodate up to 1000 trucks daily over the next few years.
Honduras
Centrica Energy and Exodus sign LNG agreement
Centrica Energy has announced the signing of a long-term sale and purchase agreement (SPA) to supply LNG to Exodus for Honduras, marking a new milestone in the country’s energy development.
Under the terms of the agreement, Centrica will deliver approximately six LNG cargoes per year to Exodus through a ship-to-ship operation into the FSU Bilbao Knutsen, located in Puerto Cortes. The 15-year contract is expected to commence in 2026.
The LNG will be transported to the Brassavola Combined Cycle Power Plant, an operating 150 MW thermal facility with its combined cycle under construction and set to reach 240 MW of power capacity, marking the first-ever import of natural gas for power generation in Honduras. Once operational, the FSU will serve as the backbone of LNG storage at a new terminal currently under construction on Honduras’ Caribbean coast.
Lebanon
IFC invests in Lebanon’s energy
The International Finance Corp. (IFC), a member of the World Bank Group (WBG), has announced five new investments and engagements to expand access to finance and energy, support the growth of the manufacturing sector, and create jobs across Lebanon.
The new initiatives were announced in the presence of the Lebanese Prime Minister, Nawaf Salam, on the sidelines of the Beirut One investor conference. They are part of the WBG's broader strategy to support the country’s reconstruction and recovery and are fully aligned with the government’s new economic vision.
More specifically, the initiatives will aim to achieve objectives including expanding access to reliable energy. In close co-ordination with the WBG’s International Bank for Reconstruction and Development, IFC will serve as the lead transaction advisor to the government of Lebanon, working closely with the High Council for Privatization and PPPs and the Ministry of Energy and Water to promote efficient power generation by structuring and implementing a gas-to-power project under a public-private partnership model.
The agreement supports the development of an FSRU to import, store, and convert LNG into fuel; and the modernisation of the 465 MW Deir Ammar I power plant into a cleaner, more efficient, higher-capacity independent power producer. It also includes the construction of a new 825 MW combined-cycle gas turbine plant, Deir Ammar II, to boost generation capacity.
Once completed, the projects will expand access to reliable electricity, support the country’s shift to more renewable energy, improve the efficiency of Lebanon’s electricity sector, reduce its reliance on diesel, and cut down the cost of electricity generation.
“Fight while wounded”: How pipelines can stay resilient amid cyber threats
Featuring Ross Brewer, Vice President and Managing Director of EMEA at Graylog. A conversation about how the energy and pipeline sectors can build cyber resilience in an era of growing complexity and connection.
We cover:
• The unique cyber risk for pipelines.
• The risk multipliers: modernisation and connectivity.
• Regulation and responsibility.
• Cloud resilience and sovereignty.
• The power of preparation.
• The evolving threat landscape.
Listen and
Ross Brewer
Elizabeth Corner
Go Katayama, Kpler LNG Insight, explores why China’s LNG demand retreated in 2025 and what lies ahead for 2026.
The first eight months of 2025 were defined by structural recalibration across Asia’s gas markets. China, the world’s largest LNG importer, recorded a sharp 9 million t y/y drop in LNG receipts, accounting for the bulk of an approximately 10 million t decline in total Asian imports, which fell to 174 million t. This contraction, however, was not driven by a collapse in demand. Instead, it reflected a fundamental reshaping of China’s gas supply mix, one that increasingly favours cheaper pipeline imports and expanding domestic production over higher-priced spot LNG. Regionally, a historically mild winter and well-stocked inventories suppressed incremental demand. Japan and South Korea were able to lean on stock drawdowns,
while India turned to alternative fuels in its industrial sector to manage costs. Yet it was China that delivered the most meaningful signal to global gas markets with a structural and non-cyclical LNG pullback. Understanding this shift is essential to framing expectations for 2026 and beyond.
Unpacking China’s decline: It is about supply, not demand
The contraction in Chinese LNG imports cannot be attributed to a contraction in demand. In fact, total gas demand in China rose by approximately 8 billion m3 y/y, although this represented a slower growth compared
to 2024. The decline in LNG receipts stemmed instead from a decisive pivot in supply sourcing.
Domestic production ramped up substantially, especially in resource-rich provinces such as Shaanxi and Sichuan, where output targets under the 14 th Five-Year Plan were achieved ahead of schedule. Although production briefly dipped during the Lunar New Year holiday, output quickly rebounded in March 2025 and sustained high levels through 2Q25.
Pipeline imports also expanded. Russian flows via the Power of Siberia (PoS) pipeline approached their design capacity by the end of 1Q25, while volumes from Central Asia rose in tandem, supported by mild weather that kept regional heating needs in check. This pipeline surge effectively reduced China’s reliance on LNG, particularly as spot prices remained elevated through the winter.
At the same time, China experienced the mildest winter on record, which both limited heating needs and left storage inventories mostly untapped.
Demand side stagnation but not collapse
On the demand side, industrial gas consumption was subdued. Activity across energy-intensive, gas-consuming sectors such as cement, steel, and chemicals slowed due to macroeconomic pressures linked to imposed tariffs and weak margins.
Residential and commercial gas demand also took a hit from the mild winter and spring. Heating requirements fell well below seasonal norms, further reducing the call on LNG. In parallel, continued renewable energy capacity additions – particularly in coastal provinces like Jiangsu and Guangdong – continued to suppress gas-fired generation. The power sector leaned more heavily on wind and solar during shoulder months, eroding LNG’s competitiveness in the generation mix.
Storage and inventory dynamics: The hidden bearish driver
Storage dynamics emerged as a major, if under-discussed, driver of bearish pressure on Asian LNG prices in 1H25. With minimal drawdowns required during the mild winter, China’s LNG inventories hit all-time highs, reaching 90% full in February 2025 based on Kpler Insight estimates. By July 2025, storage was still estimated at 70% full, and such elevated storage removed the urgency to procure incremental spot cargoes. This, combined with weak industrial gas burn, significantly reduced demand-side pull and sent a strong bearish signal to the broader Asian LNG market.
Beihai Terminal and Arctic LNG 2: A new dynamic in Chinese imports
Amid a broader import slowdown, Beihai terminal in Guangxi has emerged as a key exception – becoming the main gateway for Russian Arctic LNG 2 cargoes. Since 1 August 2025, six shipments have discharged at the 6 million tpy facility, most of which loaded directly from the Arctic plant, with smaller volumes rerouted via the Kamchatka and Murmansk FSUs. The delivery pace, six cargoes in under a month, including during the 2025 Russia – US Alaska summit, points to Beijing’s quiet yet deliberate support in absorbing sanctioned Russian LNG.
While Arctic LNG 2 volumes remain modest, their strategic value lies in pricing flexibility and geopolitical leverage. These flows are transacted outside traditional Asian spot LNG benchmarks, reinforcing China’s diversified procurement strategy amid realignments in global trade. Beihai’s role, alongside volumes via the PoS 1 pipeline, highlights a further pivot towards Russian gas – underscoring Beijing’s willingness to deepen energy ties with Moscow despite sanctions.
Looking ahead to 2026: What could change?
Pipeline supply growth likely capped
Pipeline gas imports, a major source of LNG displacement in 2025,
Figure 1. Asian LNG imports by country (million t) (January – August 2024 vs January – August 2025). Source: Kpler.
Figure 2. China’s total gas supply mix (billion m3): LNG vs pipeline vs domestic (January 2024 – August 2024 vs January 2025 – August 2025). Source: China Customs, National Bureau of Statistics, and Kpler Insight.
Table 1. Arctic LNG 2 cargoes delivered to China (August – September 2025). Source: Kpler
are likely approaching their ceiling for the time being. Russia’s PoS 1 pipeline is already running near capacity, with no expansions expected in 2026 ahead of possible upgrades in 2027. Despite recent CNPC – Gazprom co-operation announcements, additional Russian pipeline volumes are unlikely to materially affect China’s LNG demand in 2026. By 2025, PoS 1 flows are expected to average slightly above 38 billion m3/y, with compressor upgrades to lift capacity to 44 billion m3 not expected to begin before late 2026. PoS 2 and the Far Eastern Route remain long-term projects, with timelines extending into the late 2030s. Meanwhile, Central Asian flows could remain volatile, shaped by local heating needs and infrastructure constraints. With limited upside in pipeline capacity, LNG will again be required to meet China’s incremental gas needs.
Source: National Energy Administration, National Bureau of Statistics, China Electric Council, and Kpler.
Domestic
production holds firm, with shale set to lead in 2026
China’s domestic natural gas output is expected to reach 262 billion m3 in 2025, with most provinces meeting production targets ahead of winter, prompting a seasonal slowdown in 4Q25. Despite this, annual growth remains strong, supporting overall market balance. Looking into 2026, output is set to maintain a similar trajectory, with steady gains expected from conventional gas hubs such as Inner Mongolia, Xinjiang, and Guangdong, while Sichuan is likely to see accelerated growth driven by a renewed focus on shale gas expansion.
Industrial
demand set to rebound
Industrial gas demand is also poised for a turnaround. Improving margins, slowing renewable penetration in some power-intensive provinces, and more favourable LNG pricing are expected to support demand recovery throughout 2026. This is especially true in second-tier markets and among LNG truck users, where responsiveness to price signals is higher.
Winter heating and LNG trucking to rise
Residential and commercial demand is expected to rebound with assuming normal winter weather in 2025 – 2026. Lower spot LNG prices should also promote higher trucked LNG volumes, particularly in inland regions. Kpler Insight’s analysis suggests that LNG trucking will be a key early signal of resurgent Chinese demand.
Lower LNG prices reopen the door
Global spot prices are expected to ease into 2026 as new supply, particularly from North America, comes online. Price-sensitive Chinese buyers are likely to return opportunistically, taking advantage of softer market conditions. Although imports in 2H25 are projected to decline by 2 million t y/y to 37 million t, demand recovery is anticipated in 2026. Kpler currently forecasts China’s full-year LNG imports at 77 million t in 2026, supported by lower prices, demand normalisation, and capped pipeline flows.
Conclusion
China’s LNG imports are expected to rebound in 2026 – not because of weakening pipeline flows, but because the structural drivers of 2025’s import decline are already reaching their limits. Spot LNG will become increasingly competitive, and industrial gas demand is set to recover. With PoS 1 flows maxed out and Central Asian supply constrained, LNG will be needed to meet marginal demand.
Storage and weather will again play a decisive role. In 2025, both acted as headwinds for LNG. In 2026, they may become tailwinds if seasonal heating needs and drawdowns return to normal. Meanwhile, the role of Beihai and Arctic LNG 2 introduces a new layer of complexity to global supply balances.
2025 marked a strategic rebalancing of China’s gas supply system. However, the pendulum is unlikely to stay still. With pipeline imports capped, LNG prices softening, and demand poised to recover, China’s LNG buying behaviour is set to evolve again in 2026. The question for market participants is not whether China will return – but when, how much, and at what price?
Figure 3. Power generation mix (TWh): Gas vs renewables vs coal (January – August 2024 vs January – August 2025).
Figure 4. China’s gas demand by sector forecast into 2026 (billion m3). Source: National Development Reform Committee and Kpler Insight.
Figure 5. China LNG imports (million t): Actuals and forecast (2022 – 2026). Source: Kpler.
Bernt Øhrn, Managing Director, Maritime Protection, identifies how inert gas technology is evolving into a platform for innovation across both LNG vessels and terminals.
The LNG industry is navigating a pivotal moment in its development. Global demand continues to rise, confirming LNG’s position as a transitional fuel for the decades ahead, yet the pressures surrounding it are intensifying. Decarbonisation targets are tightening, emissions requirements in ports and terminals are becoming more stringent, and the technical complexities of operating dual-fuel and cryogenic systems are mounting. What was once considered a relatively straightforward bridge between conventional heavy fuel oil and the fuels of the future is now being shaped by regulations, customer expectations, and an increasing emphasis on operational resilience.
The market itself illustrates this complexity. While global LNG trade is forecast to grow by approximately 6% in 2025, the LNG carrier fleet is expanding even faster, by around 9%. Spot charter rates have already softened, as additional tonnage has entered the market, and the rate of vessel demolition is higher than at any point in recent history. A significant portion of the global fleet still consists of steam turbine-driven vessels, many of which are more than 20 years old and are increasingly uncompetitive, both in terms of fuel efficiency and compliance with current environmental regulations.
Against this backdrop, dual-fuel propulsion systems have emerged as the new standard, with LNG engines now representing over one-third of the global orderbook and expected to account for half of all newbuilds within three years. This transition underscores LNG’s role as the dominant bridge fuel, while also reinforcing the central importance of safety systems, particularly inert gas technology,
to ensure that the handling and transfer of cryogenic fuels remains safe across increasingly complex fleets.
Inert gas systems form the backbone of LNG safety. Their function is to reduce the oxygen concentration in tanks and pipelines, preventing the formation of explosive mixtures. For LNG-fuelled vessels, relatively small nitrogen-based systems can be sufficient to maintain safe conditions in fuel tanks. In contrast, for LNG carriers and FSUs, much larger capacity systems are required.
Over the past two years, a significant increase in customer demand for inert gas technology has been observed, reflecting both the rise in LNG-fuelled newbuilds and the steady stream of retrofits designed to convert existing fleets to dual-fuel capability. This growth, however, is not uniform across all fuels. Ammonia is increasingly discussed as a longer-term candidate; however, its toxicity presents significant safety management challenges and will require much larger fuel tanks than those required for LNG. Hydrogen, although attractive in principle, introduces entirely different inerting difficulties. High hydrogen mixing rates create volatile atmospheres, and the extremely low temperatures of liquid hydrogen mean that nitrogen may not always be a suitable inerting gas. These technical hurdles underscore the importance of inert gas adaptability.
Figure 1. This software is applicable for all inert gas generator systems or nitrogen systems with an operator panel delivered since 2013. Installation is completed by the crew without the need for OEM service personnel, and any hardware needed is sent by mail package.
Figure 2. Improve fix-on-first-visit ratio through smart diagnosis; e.g. remote troubleshooting is used to identify/diagnose faults while system tuning ability focuses on regular tune-ups to reduce fuel consumption and maintain system stability, enabling live remote crew training.
Safety at sea is not only about hardware, however. Crew capacity and resilience remain constant concerns. LNG operations, especially during cargo loading and unloading, demand constant attention and create conditions where fatigue becomes a significant risk factor. At the same time, shipowners have identified another challenge: the growing complexity of digital solutions supplied by different original equipment manufacturers (OEMs). Many LNG carriers and dual-fuel vessels may carry equipment from 40 or more different OEMs, each with its own monitoring system, software updates, and licensing requirements. Integrating these disparate systems is not only resource-intensive, but also raises concerns about cyber resilience. Operators are understandably cautious about taking on additional IT burdens, particularly when previous experiences have left them locked into long-term maintenance or upgrade cycles that are costly and inflexible.
Remote solutions
One response to these pain points has been the development of remote monitoring and control for inert gas systems. Originally accelerated during the COVID-19 pandemic, when commissioning engineers could not easily travel to shipyards or vessels, remote solutions have now matured into a robust and valuable tool. They enable shore-based specialists to monitor and adjust inerting operations in real time, reducing the immediate demand placed on crews and helping to ensure correct system performance without the need for constant on-site intervention. This capability has clear operational benefits: service work can be completed more
accurately and efficiently, downtime can be reduced, and crews can focus on core shipboard responsibilities rather than system troubleshooting.
The way these systems are delivered has also changed. Rather than requiring operators to purchase and manage them outright, new models allow remote monitoring systems to be leased, with the supplier retaining responsibility for updates, integration, and lifecycle support. This reduces the risk for shipowners wary of adding yet another IT platform to their already complex onboard ecosystem. Adoption rates of these models have been high, suggesting that the combination of operational relief for crews and reduced IT burden for owners resonates strongly across the LNG sector.
While shipboard operations attract much of the attention, terminals are increasingly becoming the focus of emissions and regulatory pressure. Terminals are often situated near urban areas, where concerns over air quality are particularly high. As a result, emissions standards for terminals are often stricter than those applied offshore, and local policymakers are pressing for cleaner operations. A significant portion of portside emissions comes from vessels running their auxiliary engines while alongside, producing carbon dioxide, nitrogen oxides, and particulate matter.
To address this, new approaches are being developed that shift the supply of inert gas from shipborne systems to land-based systems. One such approach is the Greenhaven concept, which positions inert gas generation at the terminal itself, powered by renewable energy sources such as wind, solar, or hydropower. From a technical standpoint, the solution is delivered through containerised, modular units that can be scaled to match the throughput of different terminals. The effect is emissions from ships at berth are significantly reduced.
The benefits extend beyond compliance. Terminals that implement renewable-powered inert gas generation can position themselves as leaders in green infrastructure, differentiating themselves in a competitive market while also addressing the concerns of regulators and surrounding communities. For ship operators, the attraction is equally clear. It simplifies operations, while the ability to shut down
auxiliary engines during cargo transfer lowers fuel consumption and reduces the crew workload associated with maintaining those engines at berth. In this way, the Greenhaven model demonstrates how terminal infrastructure can play an active role in reducing both emissions and operational pain points.
Ensuring that these technical systems are used effectively requires investment not only in equipment but also in people. LNG vessels frequently operate with rotating crews, and consistency of competence remains a challenge. Structured e-learning and digital training modules have been introduced to provide systematic instruction on the operation, maintenance, and troubleshooting of inert gas systems. These tools accelerate familiarisation for new personnel and create a consistent baseline of knowledge across crews. When combined with remote monitoring, training ensures that both onboard staff and shore-based experts work within the same framework, thereby improving safety and reducing the likelihood of miscommunication or error.
Conclusion
Looking forward, the LNG industry faces a decade of both opportunity and obligation. Fleet renewal will accelerate as older vessels are phased out and replaced by newbuilds that are dual-fuel capable and designed to meet increasingly stringent environmental standards. LNG will remain the dominant transitional fuel, but other candidates, particularly ammonia and hydrogen, will no doubt increase their presence. Terminals will no longer be assessed solely on their ability to provide efficient loading and unloading, but also on their capacity to support vessels in meeting emissions targets at berth. Digitalisation will continue to deepen, with remote monitoring and service-as-a-subscription models becoming the standard, further shifting the balance of responsibility between ship operators and suppliers.
Figure 3. For this solution, installation does not require any changes to safety systems and a key switch is included so the crew can enable and disable remote access as required. This key switch will also serve as a solid firewall and there is no IT hardware. IT hardware is leased, so there are no traditional owner risks.
The LNG sector has always operated at the intersection of energy, geopolitics, and technology. Today, that intersection is becoming sharper as the industry adapts to a world of stricter regulation and higher public expectations. The key customer pain points, such as crew fatigue, IT system complexity, emissions compliance, and logistical inefficiencies, are unlikely to disappear in the near term. What is changing, however, is the set of tools available to address them. Inert gas technology, once considered a straightforward safety measure, is now evolving into a platform for innovation across both vessels and terminals. For shipowners, this evolution provides opportunities to reduce operational burdens while enhancing safety. For ports, it offers the opportunity to differentiate themselves as green leaders by providing renewable-powered support systems that enhance the environmental performance of visiting vessels. Lastly, for the LNG industry as a whole, it represents a pathway towards reconciling growth with responsibility, ensuring that LNG remains not only viable as a transitional fuel, but also resilient in a world of shifting expectations.
Nick Cowley, Cathelco, considers biofouling management as an overlooked strategy that drives real emissions reductions.
The shipping industry is under unprecedented scrutiny to reduce its greenhouse gas emissions (GHG). Regulators, charterers, and the public are increasingly demanding measurable progress towards decarbonisation, putting pressure on operators to adopt every available efficiency measure. While much of the focus has been on alternative fuels, energy-efficient designs, and operational measures, biofouling remains an overlooked factor with a direct impact on emissions.
The International Maritime Organization’s (IMO) MEPC 83 meeting reignited long-overdue discussions around biofouling management and marked a potential turning point for one of
shipping’s most persistent and underestimated environmental challenges. For the first time, the IMO has agreed to develop a legally-binding convention to control and manage ships’ biofouling, aiming to minimise the transfer of invasive aquatic species. Moreover, in the wake of the pausing of the IMO’s proposed Net Zero Framework in October 2025 – agreed at MEPC 83 but now postponed for at least 12 months – the significant potential of biofouling management as a carbon reduction measure also takes on an even greater significance.
LNG has a well-established status as a lower-carbon marine fuel in its own right, and the LNG shipping segment has a central role to play. Through better
biofouling management, owners and operators of LNG vessels can ensure that the hull of their vessels also play their part in delivering more sustainable, lower emissions voyages.
A slow but significant policy shift
The roadmap from the IMO foresees a two-year development period for the new biofouling convention beginning in 2026, with a draft convention expected by 2029, followed by ratification before entering into force. While the timeline is long, the signal is clear: biofouling is finally being recognised not only as a biodiversity issue, but as an important lever for energy efficiency, emissions reduction, and operational performance.
Despite its impact, biofouling has long been overlooked in maritime environmental policy. A hull fouled with marine growth can increase fuel consumption by up to 20 – 40%, driving up both operating costs and GHG emissions. However, biofouling management remains a fragmented, inconsistently enforced area of regulation. The global landscape is a patchwork of regional and local laws, for example, California, Australia, and New Zealand all maintain strict controls to prevent invasive species via hull fouling, creating compliance challenges for shipowners and operators.
By reframing biofouling management as a key component of the IMO’s decarbonisation strategy, the industry can unlock immediate and cost-effective emissions reductions. Aligning antifouling and cleaning measures with frameworks such as the Carbon Intensity Indicator (CII) and Energy Efficiency Existing Ship Index (EEXI) would help shipowners demonstrate measurable efficiency gains using technologies that are already proven and commercially available.
Better hull maintenance is not only environmentally beneficial, but also commercially advantageous. Clean hulls reduce fuel bills, improve time-charter performance, and extend drydock intervals, offering a rare combination of ecological and financial returns.
Integrating biofouling into the global sustainability agenda
However, to date, the industry has failed to integrate biofouling within the broader decarbonisation roadmap. This oversight
has fragmented progress and slowed innovation. What is needed now is a global framework that sets clear expectations, benchmarks performance, and enables enforcement, supported by cross-sector collaboration among governments, academia, and industry.
Projects such as the GloFouling Partnership Project have shown what is possible through shared data and science-based approaches, but the lack of co-ordination has left the sector reactive rather than proactive. Treating biofouling as an standalone environmental issue misses the point: it is a natural ally to GHG reduction efforts, improving efficiency, compliance, and competitiveness.
How shipowners view the issue
For many shipowners, biofouling is still perceived primarily as a maintenance issue rather than an environmental one, a matter of protecting marine habitats and maintaining vessel performance. In some ways, this reflects the slow rollout of previous regulations such as ballast water management, where progress was delayed by unclear guidance and uneven technology readiness.
Voluntary compliance has achieved little. Most owners now recognise that mandatory frameworks may be necessary for consistent global action on biofouling, though these should also reward early adopters and incentivise best practice.
As the IMO moves towards a binding convention, perceptions must shift. Shipowners should view biofouling management not merely as routine upkeep, but as a strategic investment in decarbonisation, and one that supports compliance for other carbon reduction regulations such as FuelEU Maritime and the IMO’s mid-term climate goals.
Smaller technologies, bigger impact
The slow pace of progress towards a global agreement on shipping’s decarbonisation, further delayed after the IMO’s Net Zero Framework discussions in October 2025, has underlined the role that technology has to play in driving progress. The pioneers behind the latest generation of energy-saving technologies (ESTs) offer shipowners and operators a wide array of solutions that can be used in tandem to drive up the operational performance of their vessels and lower their carbon footprint. Further progress in emissions reduction will depend on finding the optimal blend of ESTs for each vessel that, together, deliver meaningful operational change.
Biofouling management is an integral part of this solution and this is where companies like Cathelco can play a key role. By providing proven, practical antifouling solutions, Cathelco contributes directly to measurable fuel and emissions savings while helping shipowners meet evolving regulatory and sustainability demands. These are the kinds of technologies that bridge the gap between today’s operational realities and tomorrow’s decarbonisation targets.
Looking ahead
Biofouling management should no longer sit on the edge of maritime policy. It is one of the few immediate, scalable, and cost-effective tools the industry has to reduce emissions today, without waiting for future fuels or infrastructure. By embedding biofouling into the global sustainability narrative, the industry can turn an often-overlooked maintenance task into a strategic lever for efficiency, compliance, and environmental stewardship.
Figure 1. Cathelco’s USP DragGoneTM keeps critical underwater surfaces free from marine growth.
Hans-Philipp Walther, Everllence, Germany, details advances in methane emissions catalyst technology and engine internal measures and the effects they may have.
With the 2023 International Maritime Organization (IMO) Greenhouse Gas (GHG) Strategy, a further considerable step was made towards a climate-neutral future. Methane emissions have always been a topic in gas-engine development. Originally, reducing methane emissions was rather a side-effect of increasing combustion efficiency. The worldwide focus on global warming supported by monetary mechanisms like FuelEU Maritime opens the door for more sophisticated solutions. With the perspective of replacing fossil-based LNG with bio or electricity-based fuels containing methane in the future, the emission of unburnt fuel will become a major climate impact of such fuels and therefore needs to be reduced
to a minimum. Everllence is taking several steps to further reduce the methane emissions of its engines.
Fundamentals
The global warming potential (GWP) of an emission is normally measured in comparison to carbon dioxide (CO 2 ). As the lifetime of the chemical species is also relevant to assess the overall impact on the global climate, a common reference needs to be defined. The Intergovernmental Panel on Climate Change (IPCC) provides an extensive overview over relevant emission species and their climate impact, assessed on a 100-year time horizon. The latest factor for methane (CH 4 ) is 29.8, which is also used for the calculations shown in this article (Table 1).
In an effort to reduce the climate impact of combustion engines, the overall GHG emissions need to be reduced. There are various examples of this which have also become part of international regulations, e.g. the IMO GHG reduction strategy or the FuelEU Maritime Regulation.
Typically, CO 2 , CH 4 , and nitrous oxide (N 2 O) are regarded as most relevant for engine emissions in general. This article focuses on CH 4 reduction, yet also uses CO 2 -e values to give a better overview over the overall engine-emission behaviour.
Overview of methane emissionreduction
measures
High-pressure fuel injection is regarded as the most effective strategy towards reduction of methane emissions. Everllence’s two-stroke ME-GI engine types offer such a combustion setup but, unfortunately, the application of such engines is not feasible in all market segments. Otto-cycle engines with port fuel injection still dominate, especially the four-stroke engine market.
For those engines, a further reduction of methane emissions is still required and feasible. The different approaches can be separated into engine internal measures and external treatment.
Engine internal measures
z Combustion chamber design.
z Crevice volume reduction.
z Combustion process.
Control strategies
z Skip firing.
z Cylinder pressure-based control.
After-treatment solutions
z Selective catalytic reaction (SCR), as compensation for using the nitrogen oxide (NOX ) – CH 4 trade off.
z Methane oxidation catalysts.
z Regenerative thermal oxidiser.
z Plasma.
Most aftertreatment solutions have still not reached a sufficient technology readiness level for use in shipping, and there are serious doubts that they will ever be competitive.
Engine optimisation
When the reduction of methane emissions is a major focus, further aspects should be considered. From test data, it can clearly be shown that the operating mode of the engine has a considerable impact on engine emissions.
Engine load plays a significant role. This can be used especially when operating several engines on a vessel. More and more ships also rely on more complex power systems including batteries.
Optimising the engine operation and shifting towards higher loads will not only lower the overall fuel consumption, but also the methane emissions. If the focus is on lowering methane emissions at lower loads, engine operation with variable engine speed should be considered.
Due to the reduced air mass flow, the air-fuel ratio becomes richer, which leads to a more complete combustion. Everllence’s 49/60DF engine is available for applications with variable speed and, even for dual fuel diesel electric (DFDE) applications, it can be applied using DFE+.
Methane oxidation catalyst development
Methane oxidation catalysts are an appealing solution to reduce the climate impact of engines run on methane-based fuels. As there are no commercial solutions available, Everllence decided to develop such a system together with dedicated partners in the framework of the funded project, IMOKAT II. Continued technology monitoring with various suppliers is also part of the activities to make sure the most effective technical solution is available for the end customer.
In addition to other measures, the company continues the development of a platinum group metals (PGM)-free MOC based on the results of the funded projects IMOKAT I and IMOKAT II. The catalyst needs temperatures above 500˚C for relevant conversion rates. Furthermore, it has been found that it is not only temperature which has a significant influence; the optimal catalyst performance can only be achieved when optimising further influence parameters like pressure and other emission species.
Table 1. Global warming potential (GWP) factor of the most relevant emission species for combustion engines relative to CO2
Figure 1. The Everllence 49/60DF engine.
With the full scale engine test, it could be demonstrated that the catalyst system achieved stable reduction rates over more than 250 operating hours under harsh operating conditions. The achieved methane reduction rates were around 45%, while total reduction rates together with further engine optimisation measures of up to 70% were reached.
When analysing the catalyst samples after the test, it was found that certain areas of the catalyst material were damaged. The characterisation of these severed zones is still ongoing. The current working hypothesis includes local overheating due to the oxidising of very high methane peaks in certain operating conditions. Especially at the early phase of engine testing, the dynamic operation of the engine was not yet adequately calibrated. During that period, several methane peaks exceeding 10 000 ppm were recorded. Catalyst material that was only installed at the last phase of testing did not show any obvious damages or reduced oxidation performance at later laboratory tests.
To better understand the damage and wear mechanisms of the catalyst materials in general, the company has set up a new testing device. This burner test rig is specifically designed to mix dedicated exhaust-gas compositions and apply those at defined temperature levels. The overall goal is to find the key mechanisms and be able to test catalyst materials in accelerated testing schemes.
Laboratory analyses
The in-house catalyst testing centre allows for a further characterisation of the catalyst and its deactivation mechanisms. With different rapid-ageing methods, the long-time stability and critical operation conditions for each exhaust gas aftertreatment system can be identified.
Conclusion
A vast range of measures is available to reduce the methane emissions of Otto-cycle combustion engines. While it is possible to combine several measures, some of them interact in such a way that it does not seem reasonable to apply all of them on the same engine type. For example, this is relevant when optimising the combustion set up and hitting operational limits like the knocking limit or the peak-pressure limit.
Some engine internal measures lead to increased engine emissions of other emission species. Typically, the trade-off between CH 4 and NOX emissions can be used as SCR provides a robust and well-proven technology to reduce the latter.
A further step for engine internal optimisation can be the switch to a diesel-cycle combustion with direct high-pressure fuel injection. For certain market segments this is already applied. The solution is especially attractive when the fuel is available in liquid form –typically LNG – and the additional cost is compensated by the operational advantages of the combustion concept.
Dedicated aftertreatment solutions for methane have been in discussion for many years now. Several approaches are documented based on PGM-based oxidation catalysts. The major obstacles for large scale application are the high cost and the limited stability in typical engine exhaust conditions. While hydrothermal ageing already harms many catalyst materials, the sulfur content in the exhaust resulting from fuel and lube oil seems to be the major obstacle. Approaches with sulfur-trap installations have so far also only been realised in research applications.
Overall, it can be stated that different measures for CH 4 emission reduction have different maturity levels. With engine internal measures, CH 4 emissions below 1.5% of the gaseous fuel consumption are achievable in the relevant load range and even below 1% for the best operating points. Many of the measures are also applicable in retrofit. For an even further reduction, the development of new technologies gets more and more challenging. Everllence is thoroughly investigating different measures and these need to undergo profound validation schemes before they will be released to the market.
Figure 3. The IMOKAT II oxidation-catalyst project (pictured here during testing at Everllence’s Frederikshavn facility in Denmark) aims for 70% reduction in methane emissions.
Figure 2. Engine operation optimisation: Harvesting further potentials.
Jani Arala, Commercial Manager, Maritime, Gasum, looks at FuelEU Maritime emissions regulations and highlights how the use of bio-LNG and pooling can bring benefits to shipowners and the environment.
FuelEU Maritime pooling leverages LNG and bio-LNG use for emission reductions across the whole European maritime sector. It allows for shipowners to adapt to the regulation in an environment of scarce availability of alternative fuels.
The EU’s FuelEU Maritime regulation has been in force since the beginning of 2025. The aim of the regulation is to cut European maritime greenhouse gas (GHG) emissions by encouraging renewable and low-carbon fuel use.
The regulation applies to all ships of 5000 gross t and over calling at EU ports, regardless of their flag. At the end
of 2025, shipowners must show that the carbon intensity of the fuel used during the year has reduced by 2%. In time, the required reduction will increase incrementally until it reaches 80% by 2050. Non-compliance results in fines based on GHG emissions.
The good news for gas-powered shipowners is that running ships on LNG mostly covers the emission cuts needed during the first years of the regulation. This is because LNG’s lifecycle carbon dioxide emissions are 20% lower than traditional maritime fuels such as marine gas oil (MGO). However, many other shipowners face concerns about fleet lifespan and compatibility, as well as the availability of alternative fuels as supplies and bunker locations remain limited.
Luckily, the FuelEU Maritime regulation allows shipping companies to voluntarily pool emissions between vessels to support compliance efforts. In this framework, vessels with surplus compliance can offset the GHG intensity requirements of other vessels by sharing compliance.
Emissions may be pooled among two or more ships verified by the same body, including ships managed by
different companies, provided certain conditions are met. One requirement is that the total pooled compliance must remain positive; pooling cannot result in a greater deficit after emissions are combined.
To sum up, pooling enables shipowners who have the ability to reduce emissions to also lower emissions on behalf of those who are unable. This benefits everyone – including compliance generators and off-takers as well as the climate.
Bio-LNG use enables generous emission reductions
Pooling can also be offered as a service. This means that the pool of vessels is managed by a third party that ensures that the pool is in balance and all ships within the pool are allocated the right amount of emission reductions required by the regulation at the end of the year. For instance, Nordic energy company, Gasum, offers pooling as a service to all ships calling at EU ports. In Gasum’s pool, designated vessels run on bio-LNG in order to generate compliance on behalf of under-compliant vessels.
Gasum has partnered with shipping companies such as Viking Line and Wallenius Sol to use their LNG-powered vessels as compliance generators in Gasum’s pool by switching the vessels to using bio-LNG.
The company provides the necessary bio-LNG to all compliance generator vessels from its own extensive bio-LNG portfolio. In addition to its own production in a Nordic network of 19 biogas plants, Gasum also sources biogas from European certified producers.
Bio-LNG is a fully renewable fuel, with lifecycle GHG emissions that are, on average, 90% lower compared to traditional fossil fuels, such as MGO. For LNG-powered ships, bio-LNG is a drop-in alternative as it has the same composition as LNG, which means that engines can switch to it directly without any need for technical modifications. It can also be blended with LNG at any ratio.
All bio-LNG produced and acquired by Gasum is made from different types of biodegradable waste and side streams unsuitable for human consumption. In fact, if the bio-LNG is produced using manure, the emissions can even be negative, as emissions from traditional manure treatment are avoided. Therefore, bio-LNG use generates relatively generous amounts of regulation surplus when used on regular routes such as those run by Viking Line on the Baltic Sea.
Transport sector eyeing limited renewable fuel resources
The FuelEU Maritime package is not the only regulatory development shaking up the maritime sector in the coming years. Although decisions were postponed in October 2025, the International Maritime Organization (IMO) still has its own strategy and ambitious targets for reducing maritime emissions globally,
Figure 2. Gasum’s chartered carrier vessel, Coral Energy, on a bunkering mission in Reykjavik, Iceland. Gasum’s bunkering network extends throughout North-Western Europe with new locations added continuously.
Figure 1. Gasum bunkers Viking Lines ro-ro vessel, Viking Glory, in the Port of Turku, Finland. Viking Line sails between Finland and Sweden on bio-LNG to produce emission reduction surplus for Gasum’s FuelEU Maritime pooling service.
with a horizon towards 2028 for the first cuts and a net-zero emission target in 2050.
With continuously tightening regulations, as well as increasing demand for low-emission transports from end customers, demand for biofuels is set to increase dramatically in the maritime sector in coming years. In addition, aviation and land transport are also vying for globally limited renewable fuel resources.
Combining all these factors together, experts estimate that there might be a significant shortage of biofuels and other alternative fuels from 2030 onwards. Faced with this challenge, Gasum has been developing a comprehensive biogas value chain and LNG infrastructure to meet the needs of customers going forward.
In addition to investments made into biogas production, Gasum is chartering a new and state-of-the art bunker vessel, set to start bunkering LNG and bio-LNG to customers in 2027. The company is also expanding its ship-to-ship bunkering network to increase accessibility throughout North-Western Europe.
Peace of mind with secured bio-LNG availability
Although biofuel availability might limit the capacity and scalability of commercial FuelEU Maritime pools, once a shipowner has signed on to a third-party’s pool, measures can be put in place to guarantee peace of mind. For example, Gasum ensures that customers are always compliant at the end of the verification period – even if this means paying a penalty on behalf of the customer.
Gasum’s is a closed pool where the company itself is the only contractual counterparty to both compliance generators and offtakers respectively and assumes responsibility as well as liability as the pool manager. Additionally, the company guarantees the availability of bio-LNG to the pool. For shipowners, it also makes sense to slightly overestimate emission reduction needs because excess compliance can be banked and allocated for the following year.
Gasum’s pool is further verified by leading classification society and advisor, DNV. This means that, at the end of 2025, DNV will verify the balance of the pool for EU reporting purposes. Despite the novelty of the regulation, DNV has an advantage in its long experience in similar verification processes. DNV’s role brings an additional layer of reliability and credibility to the pooling service, in addition to the guaranteed availability of bio-LNG.
With FuelEU Maritime now in force, the long journey to decarbonising the maritime industry has begun, with regulation steadily driving the change forward. LNG and bio-LNG have a central role in the implementation of required emission reductions today, as the industry follows what other technologies and low-carbon fuels might mature in the near future.
For now, pooling is the right answer for shipping companies wanting an easy and reliable way to fulfil the requirements of the regulation. However, during the course of the next 20 years, as the regulation tightens, shipowners need to think about what their strategy will be to tackle the 80% reduction in emissions demanded by 2050.
Jirko Lehmann, Product Manager at Endress+Hauser SICK, discusses recent advancements in ultrasonic flow meter technology, which form a precise, reliable, and low maintenance solution for LNG measurement.
LNG has decided to stay.
Despite uncertain financing and regulatory conditions, LNG trade has grown by 1% from 401 million t of LNG in 2023 to 406 million t in 20241 and is forecasted to continue to grow to up to 700 million t by 2040.2 While overall market conditions remain uncertain, the technology behind global LNG trade continues to evolve, driven by multiple innovations that improve the efficiency, reliability, and safety behind the scenes of liquefaction, distribution, and regasification facilities along the LNG value chain.
The custody transfer quantity measurement of LNG is becoming increasingly important as the growing use of LNG as a
fuel for energy supply and mobility simultaneously increases the number of LNG transfer points and the need for accurate and reliable measurements at each transfer point.
What are the challenges when it comes to accurate and reliable measurement?
LNG changes hands several times along the value chain, whether in internal company sales, between two companies, or even between countries. Considering the latest Q-Max class LNG carriers, with a capacity of up to 266 000 m³ of LNG, the financial value of an LNG load is approximately €50 million per carrier
(based on average values for density, calorific value, and average future prices for LNG traded at EEX European Energy Exchange in 2026). This LNG needs to be measured in matters of energy being transferred from seller to buyer. An uncertainty of 0.1% in this measurement corresponds to roughly €50 000 worth of LNG per carrier during loading or unloading. These uncertainties cannot be fully eliminated, but they can be minimised. Since the large scale transfer of LNG takes place on a global level between large companies, there are no local or global regulations that sellers and buyers are required to follow. Instead of using globally binding standards, current measurement methodology has been derived from other hydrocarbon products like oil, LPG, or others and is included in best practice guides such as the GIIGNL Custody Transfer Handbook.3 State-of-the-art measurement takes into account:
1. LNG quantity measurement (volume/mass) via level, temperature, and density (LTD) measurement on LNG carriers with achievable uncertainties of 0.2 – 0.55% (k=2) for LNG volume and additional uncertainties for density and temperature.
2. LNG quality measurement (heating value) via gas chromatographs (GCs) and vaporiser systems4 (with achievable uncertainties of 0.04% – 0.07% [k = 2]).
The overall uncertainty of the transferred LNG energy is stated in the handbook as 0.5 – 0.7% (k=2). This figure corresponds to a financial uncertainty of approximately +/- €250 000 – €350 000 per large transaction.
For both measurands (quantity and quality), technology is available which can lead to sufficient results under good measurement conditions. However, LNG poses some additional challenges, which can make it hard to achieve good measurement conditions under all circumstances.
The following points (amongst others) need to be specially considered and corrected to achieve an accurate quantity or volume reading on the LNG carrier:
z Ship individual tank geometries (tank tables), which transfer level to volume readings and correct for tank internals and temperature induced geometry changes.
z LNG tank movement due to ship movement (list/trim) or due to convection current inside the tank.
Figure 1. Instrumentation of an LNG import transaction in a regasification plant (mirrored also applicable for LNG export transaction in a liquefaction plant). The scheme shows potential future clear instrumentation ownership between seller and buyer.
z Boiling LNG inside the tank, blurring the phase border between liquid and gas.
z Dead volumes between tanks on the LNG carrier and the tanks in the terminal.
z Proper calibration and sealing of all involved instruments and the check by a surveyor that all of these are valid and in place.
z Sufficient tank settling time before and after loading to allow stable readings, while on the other hand there is a need to reduce berth occupancy charges with fast LNG-transfer.
For quality measurement in the liquefaction or regasification terminal:
z Representative LNG vaporisation and sampling with minimum time lag.
Typically, the instrumentation for quantity measurement belongs to the shipping company or vessel owner, while the instrumentation for quality measurement belongs to the plant (liquefaction/regasification), which may introduce additional complexity in case of disputes.
When it comes to measurement of tank level, temperature, pressure, flow/LNG-bunkering, and fluid composition, Endress+Hauser has helped to reduce uncertainties in measurement and control of process parameters for decades. With the strategic partnership between Endress+Hauser and SICK, the offering for LNG facilities has been enriched by measurement solutions for ultrasonic flowmeters (UFM) for flare, feed, sent-out, and boil-off gas (BOG), continuous emission monitoring systems (CEMS), and meters for liquid LNG. The latest development from this partnership is the FLOWSIC900 –a UFM for custody transfer and process LNG metering.
How does ultrasonic technology solve these challenges?
UFMs and Coriolis mass flow meters (MFM) both belong to dynamic in-line measurement methods in comparison with static measurement methods like tank gauging or weighing (via weigh bridges). Basic concepts, advantages, and challenges of static and dynamic LNG quantity measurement are shown in Table 1.
With changing from a static to a dynamic measurement method, the following challenges are resolved:
z Individual tank geometries: Movement of the ship or fluid movement inside the tank does not add application uncertainty anymore.
z No dead volumes or fluid flows (LNG/BOG) inside the LNG-carrier (e.g. fuel gas) or plant (e.g. compressors) need to be considered any more. Upstream of the custody transfer point belongs to the seller, downstream belongs to the buyer.
z The number of instruments which may need to be checked by a surveyor for proper calibration and sealing is reduced dramatically and the instruments are located close to each other.
z Instrumentation (quantity and quality) can be owned by one party completely, theoretically a master/duty configuration of whole setup possible (one skid on the ship, one skid on the jetty of the plant).
In addition to this, UFM offer the following advantages specifically for LNG metering of large scale quantities:
z Available in large line sizes up to 36 in. or larger.
z No pressure loss (which could lead to BOG/cavitation).
z Additional process diagnostics (e.g. speed of sound) for LNG quality monitoring.
z Being nearly maintenance and drift-free.
z Custody transfer approved UFM available (e.g. OIML R117).
The FLOWSIC900 flow meter has been designed from scratch for LNG measurement and utilises many years of experience from Endress+Hauser and SICK in natural gas measurement. It is custody transfer approved according to the latest OIML R117:2019 standard for the highest accuracy class 0.3 for use in “dynamic measuring system for liquids other than water.” Considering a conservative approach, this measurement with UFM only achieves a system uncertainty of 0.3% acc. OIML R117 standard, which would still reflect a uncertainty improvement of 0.25% on volume (0.55% reduced to 0.3%) or approximately €125 000 reduced financial uncertainty per LNG carrier (un)loading. Although the accuracy advantage supports the use of UFM, concerns regarding their suitability remain common. These concerns are briefly addressed in the following section.
Valid concerns on using UFM?
Transferability of calibration from laboratory to field
During the metrological type approval process according to the latest OIML R117:2019, Endress+Hauser – together with approval body, NMi – took special care to test the reliability and measurement uncertainty of the meter under cryogenic LNG conditions.5 This includes special transducer testing for stable and accurate readings under cryogenic conditions on a tailor-made developed cryogenic test stand, as well as the transferability from a calibration fluid (e.g. water or liquid hydrocarbons) to the target fluid LNG (with low viscosity and therewith high Reynolds number) proven on the VSL LNG test bench in Rotterdam, which is traceable to SI units.6 Calibration results illustrating the media transferability as well as meter linearity and extrapolation towards a higher Reynolds number are shown in Figure 4, which indicates that this method can be applied to LNG meters.
Not yet industry standard
Basic concept Measurement before and after transaction (tank level/volume/weight)
Clear and self-explaining definition of before/after, insensitive to ramp-up/down specifics
Permanent real-time in-line measurement during transaction and integration of flow values (volume/mass)
Direct and clear definition of custody transfer point
Advantages
Current industry standard
Multiple use for inventory management, safety and custody transfer
Challenges
For a detailed description, see the section titled ‘What are the challenges when it comes to accurate and reliable measurement?’
Diagnostics able to indicate process or instrument changes
Only few instruments involved in measurement
Proof of transferability of factory calibrations to field conditions
Proving/recalibration
BOG may affect measurement
Not yet industry standard
In the past and for various reasons, the LNG or oil and gas industry has not typically utilised this new technology quickly.
Traditionally, the steps to make technology an industry standard were as follows: first the technology gets available, then global, local, and company standards develop, and then the technology gets used and becomes an industry standard.
While this is the traditional and safest way to utilise new technology, it is hindering innovations slightly. On the
Figure 2. Basic instrument scheme of a custody transfer skid for large LNG quantities based on liquid (LNG) and boil-off gas (BOG) dynamic metering.
Table 1. Basic concepts, advantages, and challenges of static and dynamic LNG quantity measurement
other hand – there is no rule which states that it is mandatory for LNG transactions to follow these typical steps. Endress+Hauser invites operators and EPCs to find out which technology fits most to current and future LNG plants.
Proving and recalibration
UFM technology in general can be considered as drift-free and Endress+Hauser sees no technical need for regular recalibration of its LNG meter during normal operation. So, it is more a question of trust in the meter in field and how to prove that these measurement results remain trustworthy. At the time of publishing, LNG provers with capacities of up to 4500 m³/h are available, which may cover flow rates of up to 24 in. (un)loading lines or – considering extrapolation of proving – even larger.7 Proving however is associated with practical hurdles such as transport of proving system to the meter (e.g. on a jetty), establishing metrological stability and establishing proper process connections for the prover system. Recalibration in water or oil is generally possible but is associated with pulling the meter out of a (probably) insulated pipeline. From the manufacturer’s perspective, the most appropriate method is to re-use approaches, which are standard in natural gas and oil measurement today. This approach involves using two UFMs with different designs (possibly also from different vendors) in a master/duty configuration, where the duty meter is regularly compared to the master meter and the master meter could be sent to recalibration without stopping the complete LNG line. In other words, operators can consider initial factory calibration as still valid – as long as the master and duty meter show the same readings.
BOG effects
UFMs – like MFMs – work ideally under one-phase measurement conditions. These conditions are achievable with proper operator precautions, e.g. as pre-cooling the metering line and reliable thermal insulation along the complete metering line. FLOWSIC900’s design minimises potential heat ingress into the measurement section and enables fast cool-down of the meter. In two-phase flow tests at the HZDR in Germany, it has been determined that measurement availability is given up to 5% gas volume fraction (GVF).
Outlook
Challenges and concerns which have hindered the common use of UFM in LNG custody transfers have largely been overcome – the technology is ready. In the near future, UFMs are expected to be seen more and more in LNG plants. Firstly, they will be used as process meters on (un)loading lines for LNG pump monitoring or for LNG rundown measurement, and secondly as check meters as reference to level metering before they finally may get industry standard for LNG custody transfer. Global standards will continue to develop and ease usage of UFM or Coriolis-based LNG metering systems for LNG transactions from small to large scale. Ultimately, measurement uncertainties will
further decrease, allowing LNG operators to focus on the economic and political uncertainties which will probably remain.
References
1. ‘GIIGNL Annual Report 2025’, International Group of Liquefied Natural Gas Importers (GIIGNL), (2025), www.giignl.org/annual-report
2. ‘Shell LNG Outlook 2025’, Shell, (2025), www.shell.com/whatwe-do/oil-and-natural-gas/liquefied-natural-gas-lng/lngoutlook-2025.html
3. ‘Custody Transfer Handbook’, GIIGNL, (2021), 6th edn.
4. ‘Liquefied Natural Gas – LNG’, DVGW, www.dvgw.de/themen/ gas/gase-und-gasbeschaffenheit/liquefied-natural-gas-lng
5. WINKLER, T., BODENDORFER, K., KLUPSCH, M., RACKOW, S., KADE, A., FRIEDRICH, S., WESER, R., and EHRLICH, A., ‘113 A Cryogenic Test Setup for Characterization of Ultrasonic Flow Measurement’, 17th Cryogenics 2023 IIR Conference and Exhibition, Germany, (24 April 2023).
6. GUGOLE, F., SCHAKEL, M. D., DRUZHKOV, A., and BRUGMAN, M., ‘Assessment of alternative fluid calibration to estimate traceable liquefied hydrogen flow measurement uncertainty’, International Journal of Hydrogen Energy, (21 June 2024).
7. ‘Cryogenic Meter Provers for LNG Service’, Flow Management Devices, https://flowmd.com/applicationspecific-meter-provers/cryogenic-meter-provers-forlng-service
Figure 3. Endress+Hauser FLOWSIC900 custody transfer ultrasonic LNG meter.
Meter (4 path, 2X2) - Volume Flow
Figure 4. Measuring results acc. OIML R117:2019 requirements (error over Reynolds number) –capable for highest accuracy class 0.3.
Daniel Patrick, Market Segment Manager – LNG & Hydrogen, Atlas Copco Gas and Process, highlights the various challenges that boil-off gas compressors face in LNG operations and explores how integrally geared compressors help to tackle them.
As LNG infrastructure expands to meet global energy demands, managing boil-off gas (BOG) remains a critical operational requirement across the value chain. Whether in liquefaction plants, LNG carriers, or receiving terminals, BOG forms naturally due to heat ingress during storage and handling.
Left unmanaged, BOG can lead to over-pressurisation, product loss, and emissions. However, with the right compression strategy, this cryogenic vapour can be changed from a liability to a valuable resource. This article explores two main applications of centrifugal BOG compressors –low pressure and high pressure – and highlights how integrally geared compressors (IGCs), like those engineered by Atlas Copco Gas and Process, can offer performance and space-saving benefits.
From waste to value: Productive use of BOG
In earlier generations of LNG infrastructure, BOG was often vented or flared. While this controlled tank pressure, it came at the cost of lost product and added emissions. As environmental regulations tightened and energy efficiency became a financial driver, plant operators began investing in systems to capture and reuse BOG productively.
As shown in Figure 1, BOG is routinely used or recycled in three primary ways across the LNG value chain:
1. Fuel gas for onsite power: In liquefaction and regasification terminals, BOG is compressed and routed to gas turbines or reciprocating engines. This process offsets the use of pipeline natural gas and enhances energy efficiency.
2. Reliquefaction: In facilities equipped with reliquefaction units, BOG is recompressed, cooled, and reliquefied to be returned to the cryogenic storage tanks.
3. Pipeline export: High-pressure BOG can be compressed and injected into natural gas pipelines for distribution or blending with send-out gas, reducing the need for flaring and maximising product recovery.
These approaches transform BOG from an operational nuisance into a strategic energy asset, improving plant economics and reducing emissions intensity.
Types of BOG compressors
LNG is generally stored at relatively low pressures, so any vapour formation is also generally at low pressure (near atmospheric). With that understanding, BOG compressors can be categorised into two main types: low pressure and high pressure. While both services typically have similar inlet pressures, it is the required pressure ratio that varies, making the high-pressure application require a much higher outlet pressure.
Low-pressure BOG compression
Low-pressure BOG compressors (typically operating at 2 – 4 bara outlet pressure) serve the front line of vapour management. Their primary function is to capture vapour displaced from storage tanks, ship loading/unloading, or natural heat leak. In most facilities, they compress the vapour to a level suitable for fuel gas systems or reliquefaction loops.
Design priorities for low-pressure BOG compressors include:
z Cryogenic gas handling: BOG is often near 160˚C at suction. Materials and seals must tolerate these temperatures without degradation or leakage.
z Oil-free operation: To avoid hydrocarbon contamination, most systems use dry gas seals or magnetic bearing technology.
z High reliability and turndown: In some terminals, flow rates can vary dramatically. Compressors must respond to transient conditions and handle partial-load operation without stalling or surging.
z Low maintenance: Given their continuous operation, maintenance intervals and accessibility are key considerations.
Due to the moderate pressure ratios and single-stage nature of most low-pressure BOG applications, IGCs are a common and effective choice. A single-stage IGC offers a compact, efficient, and simple configuration, which makes them well suited for these low-pressure BOG duties.
In addition to managing tank boil-off, low-pressure IGCs are also commonly used for end flash gas compression. This flash gas, generated during the final expansion of the
Feature Inline compressor IGC
Layout Horizontally aligned impellers on a single shaft
Overhung impellers on separate pinions
Footprint Longer and heavier, typically Can allow for more compact and centralised arrangement
Efficiency All impellers run at same speed
Maintenance Major overhauls require full disassembly
Customisation Less flexible for mixed duties
Each pinion runs at optimal speed
Individual stage access simplifies servicing
Modular configuration for varying flow/pressure needs
feed gas during liquefaction, is typically nitrogen-rich and must be captured to avoid venting or flaring. Compressing this vapour allows it to be routed to fuel gas systems or nitrogen rejection units, enhancing overall plant efficiency.
High-pressure BOG compression
In contrast, high-pressure BOG compressors typically operate in the 40 – 60 bara outlet pressure range and are tasked with taking vaporised LNG and boosting it to pipeline or gas-turbine supply pressure. Their key roles include:
z Supplying fuel gas to high-pressure engines or gas turbines: At regasification or liquefaction terminals, compressed BOG is used as fuel for gas turbines driving vaporiser systems, power generation units, or compression trains, reducing reliance on external fuel supplies.
z Pipeline injection: BOG can be compressed to match pipeline delivery pressure and reinjected into the gas export stream, maximising product recovery and minimising flaring.
These high-pressure BOG machines handle higher pressure ratios and must be engineered for multistage compression, often in compact footprints.
Inline vs integrally geared compressors
In high-pressure BOG applications, two compressor architectures dominate: traditional inline (barrel-type) compressors and IGCs. While both can be engineered to meet pressure and flow requirements, they differ significantly in design philosophy and performance as summarised in Table 1. Multi-stage IGCs can be configured to efficiently meet the higher-pressure ratios required for high-pressure BOG service. In this arrangement, each impeller is mounted on its own pinion shaft, with multiple pinions driven by a central bull gear. This design allows each stage to operate at its optimal speed, enabling maximum aerodynamic efficiency while maintaining a compact overall footprint. In addition, the modular design of IGCs allows for easier customisation across projects with different gas compositions, pressures, and flow rates, yielding more attractive CAPEX for EPCs and end-users compared to inline machines.
Offshore considerations: IGCs in floating LNG and space-constrained projects
IGCs can offer advantages in certain offshore LNG applications, such as floating LNG (FLNG) facilities and FSRUs. In these environments, space and weight are important design factors and optimising equipment layout can help reduce structural steel requirements, buoyancy needs, and installation complexity. Potential benefits of IGCs in these settings include:
z Compact footprint and lower weight: The radial arrangement of impellers
Figure 1. Schematic of the LNG supply chain, showing the flow of boil-off gas (BOG) from storage tanks to low and high-pressure compressors for utilisation as fuel, pipeline injection, or reliquefaction.
Table 1. Comparison of inline and integrally geared compressors (IGCs) for BOG service
can allow for a more compact layout compared to some inline designs.
z Modular skids: Compressor trains can be pre-assembled and tested onshore, supporting streamlined installation and commissioning.
z Efficient operation: The ability to run each stage at an optimised speed can help improve overall energy efficiency, which is even more important where electrical power is limited, such as in offshore settings.
z Serviceability: Individual stage access can simplify maintenance activities, which is valuable when maintenance windows are limited.
While equipment selection depends on project-specific requirements, IGCs can be a strong option for offshore projects where compact design, maintainability, and energy efficiency are important considerations.
Design features of IGCs for LNG BOG compression
While IGCs are widely used across process industries, LNG BOG presents unique challenges that require specific design enhancements. When handling BOG – particularly in cryogenic or variable-load environments – several key features are essential.
Cryogenic insulation
Inlet temperatures can approach -160˚C on these BOG compressors. A composite heat barrier is used between the compressor casing and gearbox on cold-end stages to minimise heat transfer and protect warm components.
Tailored materials by stage
IGCs allow engineers to select cold-tolerant alloys for early stages while using more cost-effective materials on later, warmer stages. Inline machines lack this material flexibility because all impellers share a common shaft and body.
Seal flexibility
While carbon ring or single dry gas seals are standard, IGCs can be designed with tandem dry gas seals to meet specific project requirements.
Optimised pinion speeds
Each impeller pair in an IGC operates at a speed tailored to its stage duty, which is especially valuable in multi-stage, high-pressure BOG service. This aerodynamic tuning maximises efficiency across the entire machine.
Compact skid integration
Many LNG applications (especially FLNGs or FSRUs) benefit from IGC skids that integrate driver(s), lube, and seal systems into a single, transportable unit.
Operating flexibility
LNG terminals often experience fluctuating BOG flow due to ship loading/unloading cycles. IGCs can be engineered with inlet guide vanes (IGVs) or variable speed drives to enable wide operating ranges across varying loads.
These features make IGCs a highly versatile and reliable choice for both low-pressure and high-pressure BOG service, whether installed onshore or offshore.
Conclusion
As LNG plays an expanded role in the global energy mix, the need for reliable, efficient BOG handling is more important than ever. Whether at a large onshore terminal, a floating production vessel, or a bunkering station, BOG can no longer be seen as waste. Instead, BOG is an asset that, when properly managed, contributes to plant efficiency, emissions reduction, and operational resilience.
Low-pressure BOG compressors ensure safe tank management and support fuel gas or re-liquefaction loops. High-pressure BOG compressors enable LNG to serve power generation or pipeline export. When it comes to delivering efficient, compact, and maintainable compression, IGCs can offer clear advantages over traditional designs.
As projects grow in complexity and global LNG trade continues to diversify, investing in the right compression technology can deliver long-term performance, flexibility, and peace of mind.
Figure 2. A single-stage integrally-geared compressor for low-pressure BOG.
Figure 3. A six-stage integrally-geared compressor handling high-pressure BOG.
A conversation with Alec Cusick, Owens Corning®, showcases passive safety strategies that help mitigate the risk of cascading events in LNG facilities.
Impoundment basins within LNG facilities exist as a last resort safety measure to contain an unexpected spill of material. If these basins become full of LNG, they begin to give off invisible, flammable natural gas vapours as they warm up to ambient temperatures. If these vapours drift enough to come into contact with an ignition source, the results can pose significant risks to the facility and surroundings – potentially damaging critical infrastructure and putting lives at risk.
Cryogenic spills may be rare in the LNG industry, but their impact is anything but small. In any LNG spill, three key priorities need attention and preparation. These include reducing the vaporisation of liquid hydrocarbons, minimising radiant heat should a fire occur, and protecting against thermal shock to the concrete and rebar of a basin.
In a recent LNG Industry webinar, Alec Cusick, Technical Lead, Owens Corning, discussed how full scale testing recently completed at Texas A&M University is providing insights to support passive fire safety at LNG processing facilities.1 In this interview with Andrew Eyring, Product Manager at Owens Corning, Alec considers systems that can be put in place to defend against a cascading event.
Why are the three key priorities during a cryogenic spill so important?
Alec: In the event of a spill or release of LNG, there are invisible vapours that may drift from a spill or containment pool. If they come in contact with an ignition source, there is the recipe for a large scale incident. If these vapours can be reduced, we can
minimise the potential for a pool fire and the chance that these vapours will drift off site and ignite.
If a fire does ignite, it becomes the primary source of heat that accelerates the vaporisation of the liquid hydrocarbons, thereby fuelling the fire. It is a self-propagating reaction that can escalate a situation and lead to a cascading event. Reducing the size of a potential fire will result in less radiant heat, thus reducing the likelihood of a cascading event.
Lastly, we want to help protect the rebar and concrete in the basin. LNG is cooled to a temperature of -162˚C (-260˚F). Those cold temperatures can alter the structural integrity of the basin, causing micro-fracturing in the concrete and embrittlement in the steel. Carbon steel can start to become embrittled at temperatures as high as -29˚C (-20˚F), potentially reducing the structural strength of key elements.
What exactly are cascading events?
Alec: Cascading events refer to a scenario where a single incident leads to complications that can compound into a larger disaster. In the case of an LNG pool fire, a cascading event could occur if the heat from said fire compromised nearby storage tanks, structural steel, or other critical parts of the facility. In essence, protecting against cascading events means designing a system in a way that one problem will not lead to multiple, greater problems.
There are several approaches to help protect against cascading events. This includes moving the impoundment basin away from tanks and piping, increasing basin depth to reduce surface area, or installing a high-expansion foam system to reduce
and
thermal radiation. However, some of these methods may not be practical for certain facilities depending on land availability and proximity of nearby equipment.
Owens Corning has developed two passive fire protection systems to help the LNG industry reduce the dangers of pool fires in new or existing facilities, one called the FOAMGLAS® PFSTM (Pool Fire Suppression) System – Generation 2, and the other called the FOAMGLAS® Cryo SpillTM System.
The FOAMGLAS Cryo Spill System provides thermal shock protection for the basin’s concrete and steel rebar while simultaneously reducing LNG vaporisation.
The FOAMGLAS PFS System – Generation 2 provides reduction of LNG vaporisation during a spill, as well as a reduction in radiant heat during a pool fire event.
While each system is designed to operate independently, using them together enhances overall performance and safety. When integrated, they provide a robust and comprehensive solution for managing cryogenic spills and fire suppression, offering layered protection across multiple risk scenarios.
How do the Owens Corning systems address the three key priorities in the event of a cryogenic spill?
Alec: Both systems leverage Owens Corning FOAMGLAS cellular glass insulation.
It can withstand direct exposure to cryogenic liquids such as LNG. Due to its buoyancy, FOAMGLAS cellular glass insulation floats in water and LNG.
FOAMGLAS cellular glass insulation is a lightweight, rigid material composed of millions of completely sealed glass cells. It is impermeable and non-absorbent, corrosion-resistant and non-combustible, and has high-compressive strength.
FOAMGLAS cellular glass insulation serves three functions: to help protect the concrete basin itself, to reduce vaporisation of liquid hydrocarbons, and to reduce radiant heat during fires.
These properties make it an attractive insulation material for facilities that process cryogenic liquids.
So, how do the systems work? Can you run us through what they look like?
Figure 2. In the event of an LNG spill, the FOAMGLAS Cryo Spill System insulates basin walls and floors to protect against thermal shock and to slow vaporisation. Paired with the FOAMGLAS PFS System, which floats to form an insulating cap on the liquid surface, the combined solution helps suppress flames, reduce vapour cloud hazards, and mitigate heat from solar radiation – all without requiring new infrastructure.
Alec: Understanding how the systems are applied can provide insights into how they function. The FOAMGLAS PFS System –Generation 2 is constructed at the bottom of a basin. The system uses FOAMGLAS cellular glass insulation modules clad with stainless steel. These modules are installed on top of a grating system to keep the modules above the floor, allowing for drainage. When LNG enters the basin, the buoyant modules float on top of the liquid and rise with the level of LNG. This action provides an insulating cap on top of the liquid, which decreases the rate of vaporisation. In the case of ignition, the FOAMGLAS PFS System will insulate the cryogenic liquid from the radiant heat of the pool fire above. This significantly reduces the rate of vaporisation during a fire event, leading to significantly smaller flame length and radiant heat generated.
The FOAMGLAS Cryo Spill System uses FOAMGLAS cellular glass insulation to insulate the walls and bottom of a spill basin,
Figure 1. FOAMGLAS® Cryo SpillTM System
FOAMGLAS® PFSTM System overview.
Subscribe online at: www.tanksterminals.com/magazine/ tanks-terminals/subscribe
protecting the basin’s structure against the thermal shock of cryogenic liquids. It slows vaporisation along the walls and liquid surface, reducing the fuel available to a fire, which can help reduce the risk of a cascading event.
The FOAMGLAS Cryo Spill System and FOAMGLAS PFS System – Generation 2 can be combined to further mitigate the hazards associated with a potential pool fire. A vapour cloud that originates from an LNG spill can be quite large. Still, when the two systems are utilised, that vapour cloud can become more manageable.
Again, in the case of ignition, the FOAMGLAS PFS System insulates the cryogenic liquid from the radiant heat of the pool fire above which reduces the rate of vaporisation, leading to smaller flame length and reduced radiant heat generation.
These systems can be placed in existing basins without the need for new mechanical, electrical, or plumbing installs. They can be used to complement existing mitigation systems that are currently in place.
What sort of testing was conducted, aimed at reducing the dangers of pool fires?
Alec: Part of proving the functionality of these systems is to test their performance in realistic spill conditions. Earlier in 2025, Owens Corning worked with the Texas A&M Engineering Extension Service (TEEX) to further test the FOAMGLAS PFS System –Generation 2. This allowed us to measure exactly how the system performed in reducing LNG burn rate and flame length. We set up two LNG burns, one with the FOAMGLAS PFS System – Generation 2 and one without (unmitigated burn). The results showed an approximate 87% reduction in flame length and an 86% reduction in LNG burn rate for the test using the FOAMGLAS PFS System – Generation 2.2
One of the surprising aspects of the test was how unwieldy an LNG fire can be. For the unmitigated LNG burn test, over 2000 lbs of dry chem material was used in an effort to extinguish the fire, but the concrete and steel surfaces immediately outside of the pit remained hot enough to continuously reignite the escaping gas vapours. Eventually, the decision was made to let the fire continue until the LNG fully consumed itself. In contrast, the test using the FOAMGLAS PFS System – Generation 2 was easily extinguished using dry chem.
Does the FOAMGLAS PFS System –
Generation
2 need to be used in combination with high-expansion foam?
Alec: A key thing to understand about the system is that, even though the FOAMGLAS PFS System – Generation 2 is a standalone system, it is a passive system. It can be used in conjunction with other systems as a layered defence mechanism, tailored to the specific needs of the operation. It does not need to be used with high-ex foam; however, together they can create both a passive and an active system that may be better suited to a specific site’s requirements.
Will the systems work in basins with obstructions or basins with unique dimensions?
Alec: We have designed both systems to be used in a wide array of geometries for impoundment basins. Whether working with a rectangular, square, or circular basin, we can customise the system to fit any configuration.
The FOAMGLAS Cryo Spill System can be applied using traditional blocks of FOAMGLAS cellular glass insulation and compatible accessory products. These components are assembled onto the basin surfaces in the field, meaning traditional field-application techniques can be used to apply the system to the specific contours of the basin walls and floor.
Successful application of the FOAMGLAS PFS System –Generation 2 begins with receiving detailed drawings of the basin in question. Once we know the dimensions of the various walls and equipment present, we select the right sizes of modules to ensure that they align perfectly with the walls without any obstructions. We also leave strategic vacancies around entryway ladders, drains, or wall-mounted piping to allow for system flotation without obstruction, while staying hands-on to ensure maximum surface coverage.
Can
the FOAMGLAS
Cryo Spill System and FOAMGLAS PFS
System – Generation 2 be installed within impoundment basins that accommodate other liquids?
Alec: LNG is one of the most common applications we see these types of impoundment basins used for, but FOAMGLAS cellular glass insulation as a base material is chemically inert and compatible with most materials including other hydrocarbons. Our system could function to suppress pool fires in a similar manner with other hazardous liquids. Our FOAMGLAS Technical Service team members at Owens Corning are available to address specific questions.
What about the weather? How do these systems hold up against rain, seawater, snow, or high humidity?
Alec: These systems are very stable in outdoor environments. The FOAMGLAS Cryo Spill System consists of our base FOAMGLAS insulation with a compatible coating applied for weather resistance, while the FOAMGLAS PFS System – Generation 2 modules are coated in a silicone sealant on all sides and then cladded in stainless steel. This allows the systems to remain stable in a variety of climates, from hot and humid tropical sites to northern climates with ice and snow.
Additionally, the base FOAMGLAS material of both systems is strong enough to support typical foot traffic from workers that may be in the pit. This allows typical maintenance activities in the basin to be carried out regardless of if our system is present.
Conclusion
For LNG spills, there is a clear need to both contain the incident and stop it from spiralling into something much worse. Defending against a cascading event means thinking beyond immediate clean up and addressing the chain reactions that can threaten people, infrastructure, and operations. The right systems in place can mean the difference between a controlled event and a costly, dangerous escalation.
References
1. ‘A Passive Approach to Pool Fire Suppression & Cryogenic Liquid Spill Protection’, LNG Industry and Owens Corning, (2025), www.lngindustry.com/webinars/owens-corning/poolfire-suppression-cryogenic-liquid-spill-protection
2. CUSICK, A., et al., ‘Experimentation on the Effectiveness of Pool Fire Suppressant for LNG Pool Fires’, Owens Corning, (2025).
In the first part of a two-part article, Wim Moyson and Tom Ralston, Kranji Solutions Pte Ltd, outline phase separation issues in LNG pre-treatment and main liquefaction units.
Drawing upon over two decades of global experience, Kranji Solutions Pte Ltd has undertaken evaluations of proposed separator equipment designs for newbuild LNG plants and executed many projects to diagnose the causes of process issues on operating LNG facilities. The company has assisted established operators of the first wave of global LNG production and, over the last decade, the newly-emerging operators. Both long-established and
recently emerged operators face persistent issues with phase separation equipment. Despite some advances in process configurations and operational practices, these recurring challenges continue to impact the efficiency and reliability of LNG production processes.
This article picks up on the closing paragraphs of Ralston and Hicks article in the March 2023 issue of LNG Industry, 1 where the general application of computational fluid dynamics (CFD) modelling,
to diagnose and resolve issues in LNG phase separation, was introduced. Whilst MySep’s article was focused on the application of simulation digital twins to optimise the process, this article expands on the detailed modelling aspects and presents a selection of three industry cases
that highlight some of the most prevalent issues Kranji Solutions has observed in LNG phase separation systems. Kranji Solutions’ experience spans all key stages of LNG production processes, including:
z LNG process gas pre-treatment.
z Main liquefaction cycle.
z Natural gas liquids (NGL) processing and LNG downstream handling.
The examples shared relate to pre-processing and the main liquefaction stages of the process.
The company’s structured diagnostic methodology includes detailed evaluations of client process data, physical surveys of vessel internals and associated pipework geometry, preliminary performance assessments using MySep software, and CFD simulations. Both single-phase and multi-phase flow modelling are undertaken as required. This integrated analytical framework, underpinned by decades of industry insight, enables the company to identify and address the root causes of separation malperformance. Coupling these analyses with the specialist experience of its process team provides the company’s clients with practical recommendations that can be directly executed in house, or through appropriate service providers.
Case 1: Separator in pre-conditioning – dehydration feed service
A leading international LNG operator experienced rapid degradation of molecular sieves within the dehydration system of their pre-conditioning unit. This issue led to excessive operational downtime and frequent replacement of costly bed materials. Kranji Solutions was engaged to perform an independent root-cause analysis and recommend effective mitigation measures.
A detailed investigation of the dehydration feed separator was undertaken using a combination of multi-phase, time-transient CFD simulations and analytical assessments performed with MySep Studio software. The CFD model incorporated the upstream piping geometry, including two out-of-plane bends and a vertical-riser section located immediately upstream of the separator inlet nozzle. The analysis confirmed that excessive liquid carryover from the dehydration inlet separators was the principal cause of the molecular sieve degradation. The observed malperformance was attributed to a combination of interacting factors arising
Figure 1. Slugging inlet flow in dehydration feed separator.
Figure 2. Swirling flow at inlet section (left) and counter-rotating flow vortices in the vessel at inlet plane (right).
Figure 3. Gas flow maldistribution in gravity section and at demisting device.
Figure 4. Refrigeration loop process flow diagram from a C3 MR process simulation.
from inlet piping flow behaviour and separator internal characteristics.
The MySep Studio analysis identified a stratified wavy flow regime would be prevalent were the horizontal section of the inlet piping of sufficient length. This would be relatively favourable for liquid-gas separation. However, the CFD simulation demonstrated that the upstream piping configuration caused liquid accumulation at the bottom of the vertical-riser segment, leading to intermittent slug flow at separator inlet (Figure 1).
CFD analysis also revealed significant gas and liquid swirl at the separator inlet, caused by the combination of asymmetric out-of-plane bends and an undesirable configuration of inlet device. The diverter plate device directed incoming fluids to the vessel inner shell, establishing strong counter-rotating flow vortices within the separator (Figure 2).
Upon impingement with the inlet deflector, the entering fluids will experience an abrupt change in flow direction, generating intense shear forces and associated turbulence. Using the droplet breakup correlation of Hinze 1995, it is possible to evaluate the impact of small scale turbulent eddies, as manifest by the turbulent energy dissipation rate, and their interaction with liquid droplets. 2 High energy dissipation rates promote droplet breakup which can be directly predicted by the correlation. This analysis demonstrated that the shear generated by the inlet deflector produced an increase in the concentration of smaller droplets than that present at the equilibrium conditions within the upstream piping. This elevated population of smaller droplets increased the liquid load approaching the demisting device.
In addition, the CFD simulation revealed severe gas and liquid maldistribution within both the gravity separation and demisting sections, leading to localised overloading of the wire mesh demisting device and further diminishing its separation efficiency. This is observed as the red areas on velocity contour at the plane immediately upstream of the demisting device, as shown on the right of Figure 3.
Based on these findings, Kranji Solutions proposed a series of modifications to address the identified causes of malperformance. A vane type inlet device, combined with an upstream anti-swirl element, was recommended to minimise shear generation and promote uniform gas flow distribution within the vessel and towards the demisting section. In addition, the existing mesh pad was replaced with a thicker, higher-efficiency knitted wire mesh to further enhance separation performance. Follow-up CFD simulations verified that the proposed modifications improved internal flow distribution and reduced liquid shearing and droplet break-up – thereby mitigating the root causes of the molecular sieve degradation.
Case 2: Main liquefaction cycle compressor suction knock out drum
An LNG operator constructing a natural gas liquefaction facility in Australia using the C3-MR process engaged Kranji Solutions to conduct an independent design verification of a key separator. This focused on the LP MR Compressor Suction KO Drum (LP_MR_Suction_Scrubber
Figure 5. 3D geometric representation of computational fluid dynamics model of KO Drum.
Figure 6. MySep Studio software analysis of inlet piping behaviour.
Figure 7. Gas velocity streamlines (left) and gas velocity contours at mid plane of inlet device (right).
in Figure 4) within the main mixed refrigerant loop of the process. The three stages of compression here are essential to provide refrigeration to the main process liquefaction exchanger. The objective of the study was to assess the adequacy of the separator and its internals design for specified process conditions.
The evaluated KO Drum configuration comprised a vane type inlet device followed by a two-bank gas-box arrangement, combining mesh and vane demisting elements. The drum was modelled using MySep Studio to conduct an analytical review of its performance, whilst a 3D CFD model (Figure 5) was prepared to review detailed flow behaviour within the vessel. To ensure realistic simulation of the flow distribution within the vessel, the model included the upstream pipework geometry. The rigorous assessment focused on mechanisms known to influence separator performance and liquid carryover.
The MySep Studio analysis indicated challenging inlet conditions with a high mist fraction and small maximum droplet size (Figure 6).
CFD simulations confirmed that the asymmetric inlet pipe geometry induced non-uniform flow leaving the vane-type inlet device, resulting in preferential gas flow paths across the vessel.
A preferential flow path was observed in Figure 7 with a substantial portion of the gas flow concentrated on the left-hand side when looking from the inlet nozzle into the separator, and clearly jetting over the surface of collected liquid. Under such conditions, excessive gas velocity at the gas-liquid interface can create unstable waves, from which liquid droplets can ultimately be torn off and re-entrained into the gas flow. The onset of this phenomenon was evaluated using the Kelvin-Helmholtz interfacial wave instability criterion. 3
The critical gas velocity was calculated and compared with the actual velocities observed at the liquid surface in
the CFD simulation (Figure 8). For the simulated case, the critical gas velocity was exceeded by a factor of around 15, confirming a strong likelihood of severe re-entrainment from the liquid surface.
Further analysis of the demisting section showed that the two-bank mesh/vane combination resulted in non-optimal gravity separation and significant flow maldistribution across the face of the demisting devices. As commonly observed for such configurations, gas preferentially flowed through the upper region of the demisting device, creating a vertical velocity gradient from top to bottom. Despite the combined flow resistance of the mesh agglomerator, vane-pack demisting device and a downstream flow distribution baffle, local K-values reached up to 0.39 m/sec., exceeding the mean by 54% (Figure 9).
The CFD results showed acceptable left-right flow balance between the two mesh/vane pack banks (+3% and -3% deviation from the mean). However, within each bank, the upper sections carried approximately 56% of the total flow, confirming significant maldistribution, the degree of which was further analysed.
Under the evaluated operating conditions, both liquid re-entrainment from the liquid surface and localised high K-values at the demisting section were identified as major contributors to potential liquid carryover. Accordingly, recommendations were issued to the operator to implement mitigation measures aimed at minimising re-entrainment risk (anti re-entrainment device) and to reduce throughput to maintain efficient separation performance. These findings emphasise the importance of symmetrical inlet piping, uniform internal flow distribution, and optimised demisting device design to achieve reliable and effective gas–liquid separation performance in compressor suction KO drums.
Conclusions
This first part of a two-part article which outlines of separation issues which constrain LNG production introduces the general methodology applied by Kranji Solutions Pte Ltd. It details examples on LNG pre-treatment processing and main liquefaction processes, discussing malperformance issues found in the first case, and the careful exploration of potential issues reported to the operator, in the second case.
The second part of this two-part article will discuss remedial measures more fully, and will also summarise other issues frequently encountered in LNG processes. In addition, part two includes Kranji Solutions’ recommendations on assuring performance through good design practice.
References
1. RALSTON, T. and HICKS, P., ‘Optimisation through digitalisation’, LNG Industry, (March 2023), pp.35 – 40.
2. HINZE, J., ‘Fundamentals of the hydrodynamic mechanism of splitting in dispersion processes’, AIChE Journal, (September 1995), Vol. 1, Issue 3.
3. MATA, C., PEREYRA, E., TRALLERO, J., and JOSEPH, D., ‘Stability of stratified gas-liquid flows’, International Journal of Multiphase Flow, (August 2002), Vol. 28, Issue 8.
Figure 8. Gas velocity contours over liquid surface.
Figure 9. Gas velocity contours of gas flow in the cylinder segment (left) and entering the vane pack (right).
