Issuu

February 2026

Process improvement

is ensuring plant availability while ensuring compliance.

In the oil and gas industry, ensuring highest safety and plant availability is crucial, while achieving decarbonization goals has also become a critical imperative. Our comprehensive portfolio and expertise enable process improvements that increase operational reliability and move us towards net zero targets.

31 Turning compliance into competitive advantage

10 Security and sustainability in Europe's LNG landscape

Abby Butler, Editorial Assistant, LNG Industry, provides an overview of current European import trends and looks at how the LNG industry is responding to geopolitical pressure and approaching sustainability goals.

15 Revolutionising LNG infrastructure with bidirectional cryogenic floating ball

valves

Kfir Ohana, Product Manager, Habonim, examines the engineering principles behind bidirectional floating ball valves, their operational advantages, and their impact on LNG system design.

19 The future of LNG shipping belongs to the digitally prepared

Jeremy Steventon Barnes, Chief Technology Officer, V.Group, highlights how digitalisation within LNG operations has become a necessity, forming a gateway to intelligent and informed decision-making.

22 The millimetres that cost millions

Mark Krajewski, Aspen Aerogels, USA, inspects how insulation quietly shapes LNG capital cost, constructability, and schedule.

LNG pathway towards maritime decarbonisation

The LNG pathway, including increasingly popular bio-LNG, is providing a solid, broad, predictable, and well-established route towards maritime decarbonisation. Starting today, shipowners can take this journey at their own pace, depending on their specific decarbonisation agenda, says Grégoire Hartig, Commercial Director of Titan Clean Fuels, the bunker fuel supplier now part of Molgas.

As carbon pricing reshapes global shipping economics, small scale LNG infrastructure and dual-fuel technology are giving tanker owners a practical path to compliance and profitability. Johnny Kackur, Head Coastal Merchant, Wärtsilä, explains how integrated marine systems are enabling efficient, regulation-ready operations.

35 How can optimised interfaces strengthen LNG bunkering performance?

Matt Richardson, Sales Director at Trelleborg Marine & Infrastructure, sits down with LNG Industry to discuss how standardised interfaces are key to optimising compatibility in LNG bunkering operations.

39 Under pressure: Testing valves for safety critical installations

Gary Burns, BEL Valves, assesses the pressures involved in ensuring valves can be installed with confidence and operate without risk of failure.

42 The hidden role of nitrogen

J. Anguiano, Vice President of Emerging Technologies, Reset Energy, USA, identifies how managing nitrogen in LNG can improve the operational efficiency and commercial impact across the value chain.

47 Electrifying the LNG value chain

Sam Dobos, Business Development Manager, Chromalox, explores how medium voltage electric process heat is powering reliability and productivity.

53 Breaking free from phase separation constraints: Part two

In the second part of a two-part article, Wim Moyson and Tom Ralston, Kranji Solutions Pte Ltd, outline further experiences in troubleshooting LNG processes, looking at particular concerns in the natural gas liquids recovery process, and drawing some important general conclusions relating to all key stages of LNG.

The front cover shows an LNG carrier ship docked at PTT LNG Map Ta Phut Terminal in Thailand. Involved during the facility's expansion project in 2017, Cryogel® Z has been providing value through an unmatched combination of performance advantages over alternative insulation materials.

In 2026, Aspen Aerogels will celebrate 25 years developing and producing the world's most advanced aerogel insulation, and has been specified in over 50 LNG liquefaction and regasification projects around the world. Learn more by visiting aerogel.com

JESSICA CASEY EDITOR

COMMENT

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It’s nearly time for this year’s Oscars, and it is already being met with much anticipation. Taking place on 15 March 2026 at the Dolby Theatre in Los Angeles, the 98th Academy Awards is one of the biggest nights for cinema. Some of the films nominated this year include KPop Demon Hunters for best animated feature film and best original song for the megahit ‘Golden’, as well as Hamnet, for which Jessie Buckley is frontrunner for best leading actress.1

Timothée Chalamet has also made history by becoming the youngest actor since Marlon Brando in the 1950s to receive three nominations for best leading actor by the age of 30, the most recent for his role as the titular character in Marty Supreme 2

One film in particular stands out – Sinners (Ryan Coogler’s vampire horror) has broken history as the most-nominated film of all time at the Oscars with 16 nominations, comfortably beating the previous record of 14 nominations held by La La Land, Titanic, and All About Eve 2 It is up for categories including best actor in a leading and supporting role, best actress in a supporting role, best cinematography, and best costume design, to name but a few.

The LNG bunkering sector has also witnessed some record-breaking activity. According to data compiled by Gasnam, LNG supplied to ships in Spanish ports exceeded 8.1 TWh in 2025, more than quadrupling the volume recorded two years prior, and of which 12% was of renewable origin (bio-LNG). The reported growth is due to an increase in the number of LNG-powered vessels joining the global fleet, as well as the development of bunkering infrastructure. There has also been a supplementary change in the bunkering model, with ship-to-ship operations increasing to account for 80% of the total volumes in 2025 (up from 44%).3

This increase in LNG-powered vessels is also reflected in SEA-LNG’s annual View from the Bridge report, which highlights a strong year of growth in LNG, bio-LNG, and e-methane emissions reductions and availability. According to the report, LNG-powered vessels accounted for 75% of alternative-fuelled tonnage ordered in 2025, up from 67% in 2024. The number of bunkering vessels also increased to over 62 in 2025, accompanied by an order book of 38.4 In keeping with this increase, the Maritime and Port Authority of Singapore has also opened applications for additional licences to supply LNG as a marine fuel in the Port of Singapore, following recent updates to the Singapore LNG bunkering licensing framework and standards, which now include the provision of sea-based LNG reloading and the supply of bio-LNG and e-LNG in the port.5 As the world’s largest bunkering hub, this is a positive move that hopefully reflects the growing trend of LNG and bio-LNG as a marine fuel, especially in relation to the LNG and wider shipping industry’s emission targets and goals. This issue’s regional report takes a deeper look at the opportunities bio-LNG can offer, especially in Europe and the Mediterranean. Elsewhere in Europe, delegates will soon be descending on Barcelona and Rotterdam to take part in LNGCON and StocExpo, respectively, where the role of bunkering and bio-LNG will also be discussed, and where you can pick up your copy of the February issue of LNG Industry

References

1. ‘The 98th Academy Awards | 2026’, Oscars, (2026), www.oscars.org/oscars/ceremonies/2026

2. MCINTOSH, S., ‘Eight surprise takeaways from the Oscar nominations’, BBC News, (22 January 2026), www.bbc.co.uk/news/articles/cp3zzv40422o

3. ‘The amount of LNG supplied to ships for propulsion in Spanish ports has quadrupled in just two years’, Gasnam, (20 January 2026), https://gasnam.es/gnl-suministrado-barcos-propulsionpuertos-espanoles-multiplicado-cuatro-en-solo-dos-anos/

4. ‘Shipping’s methane decarbonisation pathway becomes a clear runway for the future’, SEA-LNG, (20 January 2026), https://sea-lng.org/2026/01/shippings-methane-decarbonisation-pathwaybecomes-a-clear-runway-for-the-future/

5. ‘Singapore Opens Applications for Additional LNG Bunkering Licences’, Maritime and Port Authority of Singapore, (14 January 2026), www.mpa.gov.sg/media-centre/details/singapore-opensapplications-for-additional-lng-bunkering-licences

THERMAL

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NANOTECHNOLOGY

India

MOL and GAIL sign charter contract for LNG carrier

Mitsui O.S.K. Lines, Ltd (MOL) and GAIL (India) Ltd have entered into a long-term charter agreement for an LNG carrier named GAIL BHUWAN. The signing ceremony was held during India Energy Week 2026 in Goa, and was signed between GAIL and LNG Japonica Shipping Corp. Ltd, a joint venture between MOL (74%) and GAIL (26%).

Hisashi Umemura, Senior Managing Executive Officer, Director General, Headquarters of Energy Business, MOL, and Shri. S Bairagi, Executive Director (International Shipping & LNG), GAIL, inked the agreement in the presence of CMD, GAIL, and other functional directors of GAIL, along with dignitaries from MOL. MOL and GAIL share a long-standing business partnership, and this collaboration further strengthens co-operation in LNG shipping and energy logistics. Relying on MOL's proven track record in providing reliable transportation services including its high standards of safety, quality, and strong partnership, the agreement marks an important milestone under the 'Maritime Amrit Kaal Vision 2047', reinforcing India's maritime and energy supply chain capabilities. Both MOL and GAIL have set the ambitious net-zero emission targets, and this agreement contributes to the realisation of a low and decarbonised world.

USA

LNGNEWS

Argentina

YPF and Río Negro establish regulatory framework for Argentina LNG project

Y PF and the government of the Province of Río Negro have signed a framework agreement establishing the regulatory and institutional co-operation framework aimed at promoting the development of the Argentina LNG project.

The agreement provides for 30 years of fiscal and regulatory stability, complementary to the Incentive Regime for Large Investment (RIGI), ensuring predictability for investors participating in the LNG project’s value chain. It also establishes clear conditions for relevant non-tax aspects related to the execution of the project within the Province.

In addition to the fiscal framework, the agreement incorporates a Technical and Professional Training Program aimed at strengthening local capabilities and promoting employment in the project’s area of influence. The programme will be jointly promoted by YPF, companies linked to the project, Fundación YPF, and educational institutions designated by the Province. Its objective is to foster the technical and professional training of the human resources required for the development of the LNG industry value chain in Río Negro, consolidating training opportunities for young people and local workers.

Galveston LNG Bunker Port announces partnership with TOTE Services

Galveston LNG Bunker Port, LLC has signed a strategic heads of agreement (HOA) with TOTE Services, LLC, a subsidiary of TOTE Group, to develop and operate dedicated LNG bunkering vessels. The partnership provides the maritime industry with reliable, scalable LNG bunkering to meet rising demand in the greater Houston port complex. The agreement establishes a framework for vessel development, construction, and long-term operation, positioning GLBP to progress efficiently towards end-to-end project execution as market demand continues to grow. This partnership supports the expansion of the Jones Act

LNG bunker fleet and domestic maritime capabilities while delivering cleaner, lower-emission fuel across the Gulf Coast. Customers also benefit from flexibility to integrate bio-LNG and e-LNG solutions, providing future-ready, drop-in fuel options.

A core element of the GLBP project is the ability to transport LNG within US coastwise trade, which requires that vessels be US-owned, built, and crewed. The HOA lays out a path towards executing a charter agreement for the first LNG bunker vessel to support the GLBP project by the middle of 2026.

LNGNEWS

Oman

Asyad Drydock and Svitzer to build first locally-manufactured tugboat

for

Oman LNG

Astrategic agreement to build Oman’s first locally-manufactured tugboat for Oman LNG has been signed between Asyad Drydock, a subsidiary of Asyad Group, and Svitzer. The project is a key milestone for Oman’s maritime industry, strengthening national industrial and maritime capabilities by localising high-value marine assets.

The signing ceremony was held under the patronage of Abdulsalam bin Mohammed Al Murshidi, President of Oman Investment Authority. The ceremony was attended by Hamed bin Mohammed Al Numani, CEO of Oman LNG; Ahmed bin Ali Al Balushi, CEO of Asyad Drydock and Infrastructure Services at Asyad Group; and Karim Cordahi, Executive Director for the Middle East and North Africa at Svitzer.

Colombia

Caribe LNG signs equity and supply deals

Caribe LNG has announced the closing of a strategic minority equity investment by Six One Commodities (61C), together with LNG supply agreements, under which 61C will supply LNG for the initial phase of the Caribe LNG project in Colombia.

As part of the transaction, 61C made a minority equity investment in Caribe LNG. In addition, under the parties’ investment arrangements, 61C has the option to make a further equity investment, subject to agreed conditions. These arrangements strengthen the project’s capital base while preserving flexibility for additional investors as the platform continues to develop.

Under the LNG supply agreements, 61C will act as supplier for the initial phase of the project, providing up to 51 000 million Btu/d. The agreements secure access to LNG from global markets and support Caribe LNG’s advancement towards commissioning, while preserving flexibility for future commercial arrangements.

USA XRG to increase stake in Rio Grande LNG

XRG P.J.S.C. will increase its stake in Rio Grande LNG, further strengthening XRG’s position in the global LNG market and marking an important milestone in the execution of its international gas strategy.

XRG will increase its overall participation in Rio Grande by acquiring additional 7.6% equity interests in Trains 4 and 5 of the Rio Grande LNG project from an acquisition vehicle of Global Infrastructure Partners (GIP), a part of BlackRock.

The transaction builds on XRG’s initial investment in Rio Grande LNG, through which the company acquired an indirect 11.7% stake in Phase 1 of the project (Trains 1 – 3), also through GIP. Moreover, as part of that transaction, ADNOC Trading entered into a 20-year LNG offtake agreement for 1.9 million tpy from Train 4.

THE LNG ROUNDUP

X Santos announces first Barossa LNG cargo

X Glenfarne announces Alaska LNG Phase One milestones

X PTT welcomes inaugural LNG cargo from the US X Stolt-Nielsen in discussions to sell stake in Avenir LNG X ENGIE welcomes LNG carrier

LNGNEWS

Mozambique

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

28 – 30 April 2026

28th Annual International Aboveground Storage Tank Conference & Trade Show

Florida, USA www.nistm.org

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

02 – 03 June 2026

Gas, LNG & The Future of Energy 2026

Calgary, Canada www.globalenergyshow.com

09 – 11 June 2026

Global Energy Show Canada 2026

Calgary, Canada

www.globalenergyshow.com

Mozambique LNG announces full restart of onshore and offshore activities

Patrick Pouyanné, Chairman and CEO of TotalEnergies, and Daniel Chapo, President of the Republic of Mozambique, have announced the full restart of Mozambique LNG project activities.

This restart of onshore and offshore project activities follows the decision made on 7 November 2025 by the Mozambique LNG consortium to lift the force majeure that was declared in 2021 and resume project activities.

During the meeting, the government of Mozambique confirmed its commitment to work together with Mozambique LNG to support the restart of project activities and address the consequences of the force majeure period. In particular, the government confirmed all measures taken to address the security and the continued co-operation with Rwanda.

Construction activities have now restarted both offshore and onshore at the Afungi site, with over 4000 workers currently mobilised, of which over 3000 are Mozambican nationals. First LNG is expected in 2029 as the project progress is currently at 40% – almost all engineering and procurement of the main equipment has been executed during the force majeure period.

The Mozambique LNG project will bring significant economic benefits to Mozambique during its development phase, notably through a local content plan. The project will provide up to 7000 direct jobs for Mozambicans during construction, and contracts awarded to Mozambican companies are expected to amount to more than US$4 billion.

In addition, Mozambique LNG has launched a large scale socio-economic development programme to support local communities in Cabo Delgado province.

Mozambique

ADBG approves US$150 million for Coral North FLNG project

The Board of Directors of the African Development Bank have approved a US$150 million senior loan to support the development of the Coral North floating LNG (FLNG) project, a transformative energy infrastructure initiative located offshore Mozambique.

Building on the success of Coral South FLNG, which became operational in 2022, the Coral North FLNG project will develop, construct, and operate an FLNG facility with a capacity of 3.55 million tpy approximately 55 km off the coast of northern Mozambique’s Cabo Delgado province.

The project is led by Eni S.p.A., and is expected to cost more than US$7 billion. In addition to the African Development Bank Group, financing will be provided by other development finance institutions, export credit agencies, and commercial lenders. Coral North is estimated to generate more than US$20 billion in fiscal revenues over its lifetime. As well as significantly boosting the Mozambican economy, it will create considerable short-term and permanent job opportunities in construction and operations.

The project commits to set aside a portion of LNG production for clean cooking access, domestic industrial development, and gas export to the Southern African Development Community region, as well as development of gas-to-power projects, which will enhance the region’s energy security and resilience.

As 2026 begins, Europe is brought another year closer to its key 2030 and 2050 sustainability and climate goal deadlines. The EU is aiming for a 55% reduction in CO2 emissions by 2030 and to achieve carbon neutrality by 2050.1 While massive renewable energy integration is being pushed across the continent to help work towards these targets, LNG continues to play a vital role in Europe’s energy mix, helping to bridge the gap from traditional fossil fuels and providing energy during periods of lower renewable power output. Natural gas consumption in Europe grew by almost 5% y/y between 1Q25 – 3Q25, concentrated primarily during 1Q25, which witnessed a demand increase of 9% y/y driven by cold weather and low renewables output.2

LNG is also utilised as a means of boosting energy supply security and increasing gas import diversification as European countries continue to look for ways to reduce dependence on Russian pipeline gas following the 2022 energy crisis. This report provides an overview of current European import trends and looks at how the industry is responding to geopolitical pressure and approaching sustainability goals.

Import trends and supply sources

In a continued effort to redirect away from Russian pipeline gas, 2025 saw European imports reach record highs, surging 30% y/y, according to S&P Global data.3 Since 2022, Europe has built or expanded 19 LNG terminals, which have played a huge role in the continent’s import capabilities. In 2Q25 alone, LNG import figures in Europe hit 35 billion m3, increasing by 11% from 1Q25 and displaying a 37% rise y/y.4 These import trends are still largely the result of Russian pipeline gas replacement as the EU pushes for increased measures against Russian import capabilities.

Efforts to diversify gas supplies have been seen throughout Europe in response to these geopolitical pressures. For example, in 2025, transported natural gas demand in Spain grew by 7.4%, reaching 372 TWh.5 To meet this demand, the country made efforts to diversify its gas supply, receiving natural gas from 16 different origins across the year and reinforcing its position as an entry point for LNG to Europe. Spain’s key suppliers included Algeria and the US while Russian gas imports fell by 44%.5

Meanwhile, in Lithuania, operator, KN Energies, has confirmed that its Klaipėda LNG reloading station reached its highest activity levels since beginning operations in 2017, importing LNG through the terminal from major suppliers such as the US, Norway, and Qatar. Over 1800 LNG trucks were loaded throughout the year and distribution was directed primarily to Poland (which received 80% of the facility’s total distributed LNG) and Estonia, as well as to Latvia and for domestic use within Lithuania.6 With demand for small scale LNG distribution to Poland increasing, the reloading station plays a crucial role in creating a regional value chain from Lithuania whilst adding value to existing infrastructure. Over in Germany, gas usage rose in 2025, with around 16 –17% of imports received at the new LNG landing terminals that have been built since 2022 in response to geopolitical uncertainty.7 The Elbe River terminal at Stade is set to become operational during 2Q26, according to federally-owned Deutsche Energy Terminal GmbH (DET), and will be the fifth FSRU to receive seaborne LNG, which represented 11% of all German gas imports over 1Q25 – 3Q25.8 In 2025, DET increased its contribution to supply security by more than one-third. The company’s three FSRUs were able to provide 79 TWh for industry, commerce, and households, as well as for storage in gas storage facilities.9 Before 2022, Germany did not import any LNG and had no import infrastructure to facilitate importation from overseas, relying heavily on Russian pipeline gas and leaving the country vulnerable to the possibility of geopolitical disruption. Germany now has five FSRUs and is one of

Europe’s largest gas buyers. The country continues to work towards replacing Russian pipeline gas and held talks in 2025 to explore the possibility of importing Canadian LNG. Germany’s FSRUs will eventually be replaced by the onshore LNG import terminals that are currently in development, highlighting that, for Germany, LNG certainly plays a crucial role in lowering energy dependency and promoting supply security.

Diversification struggles remain

Despite many widescale efforts to reduce the consumption of Russian natural gas across Europe, data shows that the EU spent around €7.2 billion on Russian LNG in 2025.10 Despite the European transhipment ban, which came into effect in March 2025, the EU has continued to increase its imports of Russian LNG. The EU received a total of 207 LNG cargoes from Russia’s Yamal LNG project across the year, only a slight reduction from the 217 shipments received in 2024.10 Europe’s imports of Russian LNG increased 2% y/y in 1H25, setting a record high for any six-month period.11 Soon, stronger measures will be in place as the implementation of the EU’s bans on spot-market Russian LNG and pipeline gas imports will come into force from early 2026 and September 2027, respectively.

These additional and stricter bans place further restrictions on Russian LNG, meaning EU countries must continue to source energy from elsewhere. However, experts have warned that, in all its efforts to reduce its energy dependence on Russia, Europe risks creating a new dependency on US LNG, which made up 57% of their imports in 2025 according to the Institute for Energy Economics and Financial Analysis (IEEFA).12 Since 2021, EU imports of US LNG experienced a fourfold increase, from 21 billion m3 to an estimated 81 billion m3 in 2025. Analyses from IEEFA highlights that while 13 EU countries imported US LNG across the year, just a handful of countries accounted for the majority of consumption. In 2025, France, Spain, Italy, the Netherlands, and Germany accounted for 75% of the EU’s imports of US LNG. Moving forward, the EU could source as much as 75 – 80% of its LNG imports from the US by 2030, upon the condition that all supply deals for US LNG are fulfilled and efforts to reduce gas demand are unsuccessful.12

This dependency is not without its own geopolitical risks. In early 2026, the EU put its trade deal with the US Trump Administration on hold following the US’ introduction of 10% tariffs on eight European countries – Denmark, Norway, Sweden, France, Germany, the UK, the Netherlands, and Finland – in relation to disputes over Greenland. These tariffs were set to be increased to 25% later in the year for these countries if the Trump Administration was not satisified with a resolution.13 These tensions put several trade relations at risk, including a trade deal made

Figure 1. LNG regasification terminal in Spain.

in 2025 which features a commitment from the EU to purchase US$750 billion worth of US energy commodities over three years. After discussions with European leaders, the Trump Administration has withdrawn its tariffs but the message remains clear: US LNG is not risk-free. The most expensive LNG for EU buyers, an overreliance on US LNG counters Europe’s intentions to diversify energy supplies and bring down energy prices. In this light, Europe’s focus must remain on the diversification of current energy supplies outside of Russian gas as well as its efforts to meet approaching climate sustainability targets.

The opportunities of bio-LNG

In an environment where decarbonisation and energy supply security are at the fore, the development of bio-LNG presents several opportunities to European shipowners, helping them to meet increasing renewable fuel requirements, and to EU countries looking to explore alternative sources of energy. Produced through upgrading biogas generated by the anaerobic digestion of organic waste, a key advantage of bio-LNG is that it offers a route to decarbonisation without relying on extensive new pipeline developments, supporting more rapid scale-up and adoption capabilities. Wood Mackenzie has labelled Europe’s FuelEU Maritime regulations, aimed at reducing the greenhouse gas intensity of marine fuels, as a catalyst for bio-LNG market growth.14 In fact, research analysts predict that the regulation could be the single biggest demand pull for European bio-LNG, estimated to cover more than half of Europe’s projected bio-LNG production capacity by 2050. Data also shows that while the global bio-LNG market was valued at US$14.8 billion in 2025, it is projected to reach US$97.5 billion by 2035, a sevenfold increase.15 Europe accounted for 57% of the bio-LNG market in 2025 and is likely to continue channelling bio-LNG development as climate policy pressure increases.15

Certainly, many countries and facilities have hit major milestones with bio-LNG integration in recent months. For example, the Dunkirk LNG terminal, located in France, carried out its first bio-LNG loading onto a Molgas tanker in June 2025, and supported the integration of bio-LNG into French natural gas networks. Also last summer, Swiss-based

energy company, Axpo, completed Spain’s first ship-to-ship bio-LNG bunkering operation at the Port of Algeciras. Sourced from the Enagás regasification plant in Cartagena, the bio-LNG has been certified by the EU’s International Sustainability and Carbon Certification, marking Cartagena as a critical LNG infrastructure hub in the Mediterranean and supporting broader European decarbonisation goals.

Returning to the Klaipėda LNG terminal in Lithuania, the facility has become the first in the Baltic region to facilitate virtual bio-LNG liquefaction. This capability demonstrates how bio-LNG producers are able to access LNG markets without physical liquefaction at the injection point. The Baltic region has also seen developments in the use of bio-LNG in the road transport industry. In Norway, Gasum has recently opened a new filling station for bio-LNG in south Oslo, open to all LNG-powered heavy-duty vehicles and meeting high local demand for bio-LNG.16 In 1Q26, Norway’s Lista Biogass plant will also enter the construction phase, with first production targeted for 1Q28. The facility is expected to produce around 90 GWh/y of fossil-free bio-LNG and will serve the maritime and road transport sectors, helping Europe’s sustainability efforts on land and at sea.17

Bio-LNG has been experiencing robust growth and offers a promising option for the future of European energy. However, with LNG prices set to drop due to increasing supplies, bio-LNG suffers a cost disadvantage which could limit its growth potential in the coming years. For bio-LNG to scale up substantially across Europe, cost differentials must be tackled through work such as ironing out the regulatory frameworks surrounding subsidised and unsubsidised bio-LNG. Growth will also likely depend heavily on policy support as the EU continues to push towards decarbonising Europe ahead of its 2030 and 2050 deadlines.

Conclusion

Looking ahead, experts predict that Europe’s LNG terminal buildout will decelerate. Regasification data indicates that Europe’s regasification activity has slowed significantly in 2025 compared to previous years and analysts expect Europe’s gas consumption and LNG imports to fall by 15% and 20%, respectively, during 2025 – 2030.11 LNG prices are expected to fall as a multi-year supply glut approaches. With more than 174 million tpy of gas liquefaction capacity currently under construction, experts estimate that the global LNG supply could reach 594 million tpy by 2030.18 However, until renewable energy generation and infrastructure has become stable and reliable enough to fully meet the region’s energy demands, LNG’s place in the European energy market remains incredibly vital and is expected to retain a high share of Europe’s gas mix moving forward.

References

References available upon request.

Figure 2. LNG carrier vessel lying at anchor near Hammerfest, Norway.

Kfir Ohana, Product Manager, Habonim, examines the engineering principles behind bidirectional floating ball valves, their operational advantages, and their impact on LNG system design.

The global energy industry is undergoing a profound transformation, driven by the need to reduce carbon emissions and transition to more sustainable energy sources. Among the alternatives to traditional fossil fuels, LNG has emerged as a key player due to its lower carbon footprint and versatility in transportation and storage. As LNG infrastructure expands to meet growing demand, the need for reliable, efficient, and safe cryogenic technologies becomes increasingly critical.

One of the most vital components in LNG systems is the valve, which is responsible for controlling the flow of

cryogenic fluids under extreme conditions. Historically, the industry has relied on globe valves and trunnion-mounted ball valves for these applications. However, recent advancements have introduced a new class of valves: bidirectional cryogenic floating ball valves. These valves offer a compelling combination of high flow capacity, compact design, and bidirectional sealing, addressing many of the limitations of legacy technologies.

This article examines the engineering principles behind bidirectional floating ball valves, their operational advantages, and their impact on LNG system design. A real-world case study further demonstrates how these valves can drive efficiency and sustainability in LNG infrastructure.

The evolution of cryogenic valve technology

Cryogenic systems operate at extremely low temperatures, often below -150˚C, and require components that can maintain integrity and performance under such conditions.

Valves used in these systems must provide reliable sealing, withstand thermal contraction, and prevent leakage of volatile gases.

Traditionally, globe valves have been used for cryogenic applications due to their linear motion and precise flow control. However, they suffer from several drawbacks:

z Limited flow capacity: Globe valves typically have lower flow coefficients (Cv), which can restrict throughput and necessitate larger valve sizes.

z Complex actuation: Their linear actuation mechanisms are more intricate and expensive compared to rotary options.

z Bulky design: Larger valve bodies and associated piping increase the overall footprint and weight of the system.

Trunnion-mounted ball valves offer bidirectional sealing and are commonly used in high-pressure applications. Yet, they too present challenges:

z High cost: Trunnion valves are expensive to manufacture and maintain.

z Complexity: Their design involves multiple components, increasing the risk of failure and maintenance requirements.

z Size and weight: These valves are heavier and bulkier, complicating installation and integration.

In response to these limitations, manufacturers have sought to develop more efficient valve solutions that meet the stringent requirements of cryogenic LNG systems.

Floating ball valve technology: A compact alternative

Floating ball valves are characterised by a ball that is held in place by two seats, allowing it to move slightly under pressure to create a seal. This design offers several advantages over traditional valve types. For example, higher flow rates. Floating ball valves provide significantly higher Cv values compared to globe valves, enabling greater throughput with smaller valve sizes. Additionally, they have a compact design with improved flow characteristics, which allow for reduced pipe diameters and valve dimensions, minimising system footprint. They also offer simplified automation as the quarter-turn actuation mechanism is simpler and more cost-effective than linear actuators, reducing installation and maintenance complexity.

Despite these benefits, conventional floating ball valves have been limited to unidirectional sealing due to the presence of a pressure relief hole in the ball. This hole is necessary to prevent pressure build-up in the valve cavity caused by the expansion of trapped cryogenic media. However, it compromises the valve’s ability to seal in both directions, restricting its versatility in LNG applications.

Engineering the bidirectional breakthrough

To overcome the limitations of unidirectional sealing, Habonim developed two solutions that enable bidirectional

Figure 2. Habonim actuated ball valve in an LNG fuelling station.

Figure 1. LNG bunkering ship with Habonim valves and CompAct Actuators.

sealing in cryogenic floating ball valves, without sacrificing safety or performance.

Self-releasing spring-loaded seats

This patented design integrates spring-loaded seats with embedded seals. When pressure within the valve cavity exceeds a predefined threshold, the seat compresses against the spring, allowing the trapped media to escape into the pipeline. Once the pressure normalises, the spring returns the seat to its original position, re-establishing the seal.

Key features include pressure relief on both sides of the valve, enhancing operational flexibility, compatibility with small valve sizes (up to 2 in.) and pressure ratings up to Class 300 (50 bar), and improved safety without compromising bidirectional sealing by preventing overpressure scenarios.

In-ball embedded pressure relief valve

The second involves embedding a pressure relief valve (PRV) directly into the valve ball. This device functions like a check valve, allowing excess pressure in the cavity to vent upstream when necessary. Once the pressure drops, the PRV closes, restoring the valve’s sealing capability.

Advantages include:

z Retrofit capability: Existing valves can be upgraded by replacing the ball with a PRV-equipped version.

z Applicability to larger valve sizes (2.5 in. and above).

BOG Management for LNG and LH2 Fuel Stations

z Maintained bidirectional sealing without external modifications.

These solutions represent a significant leap forward in cryogenic valve technology, enabling floating ball valves to perform reliably in bidirectional applications across the LNG value chain.

Case study: Optimising LNG valve systems

A leading engineering firm specialising in LNG infrastructure faced a complex challenge during the design phase of a new project. The system required valves capable of handling flow in both directions to eliminate the need for redundant piping and reduce overall system complexity.

The firm’s objectives included:

z Cost reduction: Minimise CAPEX by reducing the number of valves and associated piping.

z Space efficiency: Design a compact system suitable for constrained installation environments.

z Operational simplicity: Streamline actuation and control mechanisms.

z Environmental responsibility: Support carbon capture and minimise fugitive emissions.

• Plug and play modular design

• Turn-key projects

• Energy efﬁcient Stirling cycle

• Small footprint 1.6 sqm (17,2 sqft) per unit

• Available in cooling coil set up or alternatively as a subcooler

Cryogenics (Head Ofﬁce) Science Park Eindhoven 5003 5692 EB Son, The Netherlands T +31 40 26 77 300

By integrating Habonim’s bidirectional cryogenic floating ball valves, the firm achieved:

z Up to 60% cost savings through reduced valve count, smaller pipe diameters, and simplified actuation.

z Space optimisation by eliminating dual pipelines and using compact valve designs.

z Improved installation efficiency due to the quarter-turn actuation mechanism and reduced system complexity.

z Enhanced environmental performance by preventing leaks and supporting energy-efficient operations.

This case study highlights the practical benefits of adopting advanced valve technologies in LNG systems, demonstrating how engineering innovation can drive both economic and environmental value.

Applications across the LNG value chain

Bidirectional cryogenic floating ball valves are versatile and suitable for a wide range of LNG applications, including:

z LNG terminals: Managing flow between storage tanks, loading arms, and transportation systems.

z Marine vessels: Controlling LNG transfer between onboard tanks and dual-fuel engines.

z Tankers and carriers: Facilitating filling, draining, and inter-tank operations with minimal infrastructure.

z Fuelling stations: Ensuring safe and efficient LNG dispensing to vehicles and equipment.

Their ability to function as both loading and offloading valves within a single pipeline simplifies system architecture, reduces installation time, and enhances operational flexibility.

Comparative analysis: Floating vs trunnion ball valves

While trunnion-mounted ball valves have long been the standard for bidirectional sealing in high-pressure applications, they present several challenges. For instance, trunnion valves are more expensive to manufacture and maintain, often costing twice as much as floating ball valves. Their design involves additional components, such as

trunnion supports and complex sealing mechanisms, which increase maintenance requirements. Trunnion valves are also bulkier and heavier, requiring more space and structural support.

In contrast, bidirectional floating ball valves offer compact size and weight which means they are easier to install and integrate into tight space. They also have lower torque requirements; the seat design reduces actuation force, enabling the use of smaller, more efficient actuators. Additionally, bidirectional floating ball valves have simplified maintenance requirements due to having fewer components and their straightforward designs, reducing downtime and service costs. Lower manufacturing and installation costs make them ideal for small-to-medium scale LNG applications.

These advantages position bidirectional floating ball valves as a superior alternative for many LNG system designs, particularly where space, cost, and operational simplicity are critical.

Outlook: Driving innovation in LNG infrastructure

As the LNG industry continues to expand, the demand for scalable, efficient, and sustainable infrastructure will grow. Technologies like bidirectional cryogenic floating ball valves are poised to play a central role in meeting these demands. Their ability to reduce system complexity, enhance safety, and support environmental goals aligns with the broader industry trend towards decarbonisation and digitalisation.

Moreover, the modular nature of these valves supports flexible system design, enabling operators to adapt to changing market conditions and regulatory requirements. Whether in large scale export terminals or decentralised micro-LNG facilities, the adoption of advanced valve technologies will play a crucial role in shaping the future of LNG.

Conclusion

The development of bidirectional cryogenic floating ball valves marks a significant milestone in LNG infrastructure engineering. By addressing the limitations of traditional valve technologies, these innovations offer a path towards more efficient, compact, and sustainable LNG systems.

Through enhanced flow capacity, simplified actuation, and reliable bidirectional sealing, these valves provide tangible benefits across the LNG value chain. The case study presented underscores their real-world impact, demonstrating how engineering innovation can translate into operational excellence and environmental stewardship.

As the LNG industry evolves, the integration of advanced valve technologies will be essential to achieving the dual goals of economic viability and climate responsibility. Habonim’s contributions in this space exemplify the kind of forward-thinking solutions that will define the next generation of energy infrastructure.

Figure 3. Habonim valves and CompAct Actuators on LNG bunkering ship.

Jeremy Steventon Barnes, Chief Technology Officer, V.Group, highlights how digitalisation within LNG operations has become a necessity, forming a gateway to intelligent and informed decision-making.

The LNG shipping sector is undergoing a period of significant transformation. Decarbonisation, regulatory pressures, and market volatility alongside technological advances and innovation are creating new layers of operational complexity for vessel owners. At the same time, LNG’s role in the global energy mix continues to evolve, with emissions reductions and commercial agility becoming increasingly decisive factors.

In this environment, digitalisation has shifted from niche to necessity. Maritime digitalisation is nothing new and has been developing for over a decade. The organisations that will best manage this era of complexity are those that are able to recognise digitalisation as much more than data collection. Digitalisation, done right, is a gateway to intelligent and informed decision-making, but tapping into these benefits depends on access to ‘digital heritage’ – a powerful combination of historical operational data, contextual understanding, and advanced analytics that transforms information overload into genuine strategic foresight and intelligence across verticals and functions.

LNG’s unique digitalisation equation

Few segments of shipping illustrate the stakes of digitalisation as clearly as LNG, where maximising uptime

is key. Consider boil-off gas (BOG) management: without accurate and transparent data forecasting tools, vessels often fall into inefficient patterns, such as ‘sail fast then wait’ which involves racing to a terminal only to wait at anchor for days or steam in circles to burn off gas to preserve cargo integrity (since LNG carriers are not designed to remain stationary). This behaviour increases fuel burnt, emissions exposure, and reduces commercial flexibility. Better data-driven communication between vessels and terminals can address these inefficiencies and complexities, and using data to co-ordinate arrival times can allow LNG carriers to reduce speed, save fuel, costs and emissions, and arrive ‘just in time’.

Many LNG vessels also continue to depend on noon reports as their primary source of operational information. While these reports have their place, a handful of data points every 24 hours cannot capture the real-time complexity of a vessel subject to BOG dynamics, shifting cargo schedules, and emissions constraints. Relying on this limited dataset also restricts the potential of artificial intelligence (AI) models to optimise performance.

LNG shipping also grapples with methane slip, which is a key focus under the EU’s FuelEU Maritime regulation. Methane penalties can quickly erode voyage margins and

tackling this requires more than technical upgrades. While the most effective measure is to modify gas-burning engines to reduce methane slip, shipowners still need accurate, high-quality data and robust modelling to evaluate where methane emissions originate, and how remedial actions may perform. Simulation models on the potential financial and regulatory impact of these actions allows shipowners to decide if they should invest in alternative fuels or energy efficiency technologies to maintain compliant and cost-effective operations. These assessments rely on digital heritage – the accumulation of vessel and fleet performance spanning years. It links maintenance records, voyage data, equipment history, environmental conditions, cargo operations, and commercial decisions into a coherent analytical architecture, without which predictions become guesswork.

LNG shipping has historically relied on human expertise developed across long careers. Today’s vessels still need that expertise, but they also generate masses of data that, when used alongside human interpretation and experience, can prove to be a highly valuable strategic asset.

The data flywheel: Where optimisation meets scale

The LNG sector’s operational margins have always been sensitive to inefficiencies, and this makes the impact of in-depth data collection especially powerful. As vessels install more sensors and as data streams grow richer and more contextual, operators gain the ability to pinpoint inefficiencies with far greater accuracy than was previously possible. This new visibility extends across everything from trim and draft profiles to boil-off management, engine performance, and weather-routing decisions.

As these insights drive better day-to-day optimisation, operators begin to realise measurable improvements in fuel consumption, emissions performance, and cargo-handling efficiency. Those operational gains, in turn, can generate more consistent and more useful datasets. With each optimisation cycle, the data feeding analytical systems becomes stronger, enabling even more refined insights on the next iteration.

Over time, this creates a self-reinforcing ‘flywheel’ of learning and improvement. What starts as isolated vessel optimisation matures into fleet-wide intelligence, where data from multiple LNG carriers contributes to a common analytical foundation. The scale of this combined dataset becomes a decisive differentiator. A single vessel’s data can highlight inefficiency; a fleet’s data can reveal patterns, predict outcomes, and guide long-term strategic decisions with far greater certainty.

Tier 1 ship managers bring this scale of data, alongside a wealth of expertise, experience, and integration capability to turn data into a real, actionable advantage. Organisations with long-established digital frameworks demonstrate how meaningful value emerges when systems, processes, and data are connected rather than fragmented. V.Group’s ShipSure platform illustrates this point. Developed over the past two decades, it stands as an example of how sustained investment in integrated digital infrastructure enables the ‘data flywheel’ to operate

at scale, strengthening decision-making and giving operators clarity in increasingly complex environments. Take emissions reductions as an example, by combining historical operational patterns with real-time data, derived from using sensors to measure actual emissions at the exhaust stack, a platform like ShipSure could help vessel owners and operators gain a more accurate image of a vessel’s true environmental impact, rather than relying on theoretical calculations. By working with experts at V.Group, this data can also help assess retrofit scenarios before committing capital, forecast long-term regulatory exposure, and model how operational changes influence emissions reporting.

Data from ShipSure also informs the use of predictive systems such as Sentinel AI, which applies machine learning models to large, diverse datasets spanning operations, maintenance, routing, fuel, and weather conditions. By anticipating future events and identifying early-stage risks, such tools help reduce unnecessary cost and enhance operational stability. Importantly, they are built on years of real-world vessel performance data.

As the maritime sector becomes more interconnected, siloed decision-making is no longer viable. Technical, commercial, and operational choices increasingly intersect, and the ability to integrate data across these domains will shape competitive advantage. This is where digital heritage matters: organisations that treat data as an institutional asset, rather than a collection of isolated reports, gain the clarity needed to navigate environmental pressure, regulatory change, and market volatility.

Digitalisation as a strategic advantage

The LNG sector is highly specialised, technically complex, and commercially sensitive. Its competitiveness and ability to meet decarbonisation, regulation, and fuel market shifts, will continue to be determined by its digital maturity.

True leadership in this sector will come from those who can turn maritime complexity into clarity through data-driven insight. These organisations will use their digital heritage, years of operational data, engineering knowledge, and fleet experience to anticipate challenges before they emerge and optimise performance in real time. They will build the scale required to do this well: scale in data volume, operational understanding, global touchpoints, and the human expertise needed to convert information into foresight. Crucially, they will understand that digitalisation is not a single project or a technology upgrade, but a continuously evolving capability, one that strengthens with every dataset captured, every optimisation delivered, and every insight applied back into the fleet.

Here, proven operational excellence becomes a strategic differentiator. The most advanced ship managers see digitalisation as more than just a set of tools but rather a key part of their DNA. By integrating predictive analytics, performance data, and real-time monitoring into day-to-day operations, they help shipowners turn incremental optimisation into competitive advantage, setting new benchmarks for efficiency and sustainability.

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COVER STORY

Mark Krajewski, Aspen Aerogels, USA, inspects how insulation quietly shapes LNG capital cost, constructability, and schedule.

Forecasting power demand has become a tougher business than it was a decade ago. At that time, global electric vehicle (EV) adoption only saw 500 000 sold worldwide, and data centres consumed a fraction of the electricity they do today. Since then, both EV adoption and artificial intelligence (AI)-driven data centres have rapidly changed electrical requirements. In turn, this accelerated the need for new power generation capacity that is both scalable and lower in carbon intensity. Coupled with an overall global increase in natural gas consumption, demand has grown more rapidly than forecasts anticipated, driven by faster-than-expected electrification, rising power demand, and the expanding role of LNG in global energy systems.

One consequence is clear: demand is driving a major expansion of LNG liquefaction capacity. Projects are advancing simultaneously across the development lifecycle, with new facilities being completed, sanctioned at final investment decision (FID), and planned in parallel at a pace not previously seen in the industry.

In the urgency to be part of this wave, owners and engineering firms are leaving no stone unturned in the effort to design facilities with the maximum return on investment (ROI), which means facilities with the most efficient design and the quickest path from groundbreaking to first cargo. They look for any possible edge from using electrified liquefaction trains to lower the carbon footprint to the latest in process innovations to

further push the efficiency envelope. On the construction side, the trend is utilising highly modularised construction techniques to reduce expensive stick-built modes of construction. But there

is one design lever available that is highly impactful and often overlooked: the type of thermal insulation material used on the facility.

Cryogel Z is a next-generation aerogel fibre composite blanket insulation that can meet thermal design requirements with significantly less thickness than traditional rigid insulation materials (Figure 1). When spacing between piping and equipment is governed by insulated outer diameter, higher-performance insulation can enable more compact layouts, creating additional benefits across structural design, foundations, logistics, and installation productivity.

Quantifying the impact: An independent design impact study

To quantify the downstream effects of insulation choice, Aspen Aerogels commissioned an independent design impact study led by two experienced project engineers with civil and structural backgrounds, each with extensive experience in project and construction management both at the end user and EPC level. The analysis evaluated a 1000 ft LNG pipe rack with 51 bents carrying a range of pipe sizes (Figure 2).

Using the Figure 2 piping layout as an uninsulated baseline, the pipe rack dimensions were adjusted to accommodate insulated pipe diameters. The calculated rack widths and deltas are shown in Table 1.

With rack geometry established, the study sized structural elements to support:

z Gravity loads (piping and insulation system weight).

z Environmental loads, including wind loads influenced by insulated diameter and rack sail area.

From these forces, the foundation piers were sized, and material quantities were translated into steel and concrete cost estimates (Table 2).

Logistics and constructability: Fewer truckloads, fewer parts, less handling

Beyond structural impacts, insulation choice changes how much material a project must receive, stage, and move to the work front, an often-hidden driver of labour hours and schedule risk.

As shown in Table 3, insulating the studied rack scope with a rigid system (e.g. cellular glass) required approximately 75 truckloads of material, depending on site/off-site fabrication assumptions and packaging efficiency. The equivalent Cryogel Z scope required approximately 19 truckloads.

Just as important, rigid insulation systems can require hundreds of SKUs across thicknesses, fittings, and accessories. Cryogel Z consolidates systems to a single blanket product SKU which simplifies procurement, warehousing, and field execution.

Key outcomes

z The rack insulated with Cryogel Z required 16% less facility square footage for the same process scope.

z When material and soft costs were combined with the insulation total installed cost (Table 4), the analysis showed a total savings of US$822 000 for the

Figure 1. Insulation thickness required to meeting condensation control and heat gain requirements.

Figure 2. Base piping layout for design impact study.

Table 1. Rack widths from insulated pipe diameters

Table 2. Steel and concrete cost detail

representative 1000 ft pipe rack segment – driven by reduced rack width, lower structural steel and foundation requirements, and simplified logistics.

z The savings impact increases dramatically when the entire facility utilises these simple design optimisations.

Multi-service performance in a single system

For LNG facilities, insulation often must deliver more than heat gain control. Cryogel Z can be engineered to support multiple protection goals in one system, reducing secondary layers and interface complexity:

z Thermal insulation and acoustic attenuation without a separate acoustic overwrap.

z Thermal insulation, passive fire performance, and cold-spill protection, supported by qualification testing such as

UL 1709 pool fire, ISO 22899 jet fire, and ISO 20088-3 cold spillage.

Cryogel Z’s tough flexible form is easy to install and does not require contraction joints. It allows for pre-insulating and vapour sealing assets off site and bringing them fully dressed to the project, which not only reduces on-site labour requirements, but takes the insulation time out of the project critical path. Figure 3 shows a 280-ft pipe spool that has been fully insulated, vapour sealed, and is being lifted into a pipe module. One project that utilised this time and schedule saving technique had the fastest groundbreaking to first cargo of any LNG liquefaction mega-project to date, at 58 months.

Table 3. Material handling (soft cost) detail

Table 4.

Installation productivity: Field experience and scaled evaluation

Across two decades of LNG participation, multiple data points indicate that Cryogel Z can be installed faster than traditional rigid insulation systems – ranging from controlled demonstrations showing a 30% time advantage to customer-reported productivity gains that can exceed 50% on large-bore piping.

Importantly, installation performance depends on project conditions, workforce experience, access, weather, and the execution model. To address this variability, Aspen Aerogels engaged with a Tier 1 EPC to evaluate installation performance at full project scale. In that assessment, Cryogel Z was faster and easier to install than traditional rigid systems, particularly due to simplified logistics, ease of handling, flexible product form, and fewer part numbers. The system achieved equivalent or better thermal performance with half the circumference coverage and, in some parts, lower total installed cost.

Track record and specification discipline

Cryogel Z has been used in LNG service for more than two decades, evolving from an emerging innovation into a mature, validated insulation platform. As aerogel-based blankets become more widely available, owners and EPCs should recognise that similar-looking composites can deliver significantly different performance in thermal conductivity, durability, hydrophobicity, and quality consistency.

Once the decision is made to use high-performance aerogel composites as part of a design, procurement should emphasise verified performance requirements such as thermal conductivity,

fire testing, cold-spill performance, QA traceability, and proven in the field performance, not just claiming similarity.

Conclusion

The rapid growth in energy and electricity demand driven by electrification, AI-enabled data centres, and global decarbonisation goals has fundamentally altered the trajectory of power generation and LNG development.

In this new environment, project success is defined not only by capacity delivered, but by speed to market, capital efficiency, constructability, and carbon intensity. LNG developers and EPCs are re-examining every design lever available to maximise ROI while minimising risk.

The selection of thermal insulation – often treated as a late-stage specification choice – has proven to be a meaningful upstream design decision with cascading impacts across structural steel, foundations, layout density, logistics, installation labour, and schedule. The independent design impact study quantifiably demonstrates that Cryogel Z enables smaller pipe rack footprints, reduced steel and concrete quantities, lower wind and foundation loads, and simplified construction logistics. When these hard and soft cost benefits are combined with installed cost savings, the total project advantage is substantial, exceeding US$822 000 for a single 1000 ft representative pipe rack while simultaneously reducing material usage and embodied carbon. This translates to millions of dollars saved when these design changes are utilised across an entire facility.

Beyond quantifiable cost and space savings, Cryogel Z offers multi-service functionality – thermal insulation, acoustic attenuation, passive fire protection, and cold-spill resistance – in a single, flexible system. This capability eliminates secondary systems, simplifies engineering interfaces, and supports modularised and off-site fabrication strategies that are critical in shortening project schedules. Real-world project experience further confirms that Cryogel Z can meet or exceed installation rates of traditional rigid insulation systems, even in less-than-ideal conditions. Its ease of application allows an inexperienced workforce the ability to install these systems without failure with even further productivity upside as crews gain familiarity.

With more than two decades of proven performance in LNG service, Cryogel Z represents a mature, validated technology rather than an emerging risk. As aerogel-based insulation becomes more widely adopted, it is essential for owners and EPCs to distinguish between superficially similar materials and true high-performance composites backed by rigorous research and development, testing, and successful performance history in the field.

In an industry where marginal gains compound into significant competitive advantage, thermal insulation such as Cryogel Z offers a rare opportunity: a single material choice that improves plant efficiency, reduces capital and schedule risk, lowers carbon footprint, and enhances long-term operability. For next-generation LNG facilities, insulation selection is no longer a detail; it is a strategic design decision.

Figure 3. Fully insulated and vapour sealed pipe spool being lifted into a pipe module.

Figure 4. Thermoacoustic insulation system meeting an ISO-15665 D2 performance.

Pioneering small scale LNG operators have established a global LNG bunkering infrastructure network that provides a strong basis for the use of bio-LNG today and, in the future, e-methane. Bio-LNG and e-methane can be ‘dropped into’ all the established conventional and small scale LNG infrastructure, including LNG dual fuel vessels, and blended with each other or LNG at any ratio – all with little to no equipment modification required. This level of infrastructure flexibility is clearly unmatched by other alternative fuels.

The opportunity to use existing natural gas and LNG infrastructure to the benefit of LNG, bio-LNG, and e-methane bunkering allows the industry to concentrate its investments on the actual production of renewable methane, rather than the establishment of the new logistics chains needed to deliver other alternative fuels.

The readiness of ports, when it comes to the authorisation of LNG bunkering, has also dramatically increased and reaches far and wide. There are around 188 ports offering LNG bunkering, with a further 82 bunkering locations under active discussion, according to SEA-LNG’s Mid-year Review.

Ultimately, LNG as bunker fuel has become an almost mainstream, commercialised, and commoditised marine fuel. While 4Q25 bunkering figures from the Port of Rotterdam have not been released at the time of writing, LNG bunkering volumes in the port in 2025 to date are consistent with 2024, a strong year that saw a significant 322 123 m3 increase compared to 2023.

The total addressable market for LNG, bio-LNG, and e-methane is expected to grow tremendously in the near future. According to DNV orderbook figures, there are a total of 1369 LNG dual fuel vessels in operation and on order, and this strong orderbook momentum is continuing. In 1H25, 87 new LNG dual fuel vessels were ordered, up from 53 in 1H24.

In the initial stages of LNG bunkering’s history, small-to-medium size LNG dual fuel vessels and tanks were

predominantly ordered, but there are now LNG dual fuel vessels of all sizes, from medium size to very large, being ordered. This significantly boosts the switch from oil to LNG in terms of bunkering volumes.

Solid operational foundations

The ‘soft infrastructure’ of a fuel pathway – such as training schemes, seafarer experience, and safety standards – are also a vital basis for decarbonisation progress. LNG has been safely shipped around the world for 60 years and, more recently, bunkered hundreds of times, with no major incidents. Rigorous safety standards are in place, and crews have had thorough training on how to handle, store, and bunker LNG, as well as operate dual fuel engines.

Amongst the very legitimate focus on greenhouse gases (GHG), it is often overlooked that LNG and all its ‘pathway fuels’ also heavily reduce local pollutant emissions. They eliminate up to 95% of nitrogen oxide (NOX) emissions and achieve virtually zero sulfur oxide (SOX) and particulate matter (such as black carbon) emissions. These local emissions reductions improve air quality and support the health of people working in or living near the shipping industry, as well as the customer experience on passenger vessels.

The attractiveness of LNG as a pathway to decarbonisation resides in the fact that grey LNG already provides a good GHG emissions reduction platform, while grey methanol and ammonia both increase GHG emissions over oil-based fuels.

As a result, ship operators have a substantive emissions head start on the pathway to net-zero shipping, needing less bio-LNG and e-methane in any fuel blends to achieve the targeted emissions reductions. Ship operators can blend in renewable methane as and when needed, without having to switch to expensive e-fuels from day one. They also need less renewable methane than alternatives because it has a higher energy density (calorific value), which minimises the impact on valuable cargo space too.

Bio-LNG scaling up

Bio-LNG is liquid biogas made by processing organic waste flows that are widely available and support the circular economy, also contributing to reducing organic waste and its impact on the environment. Bio-LNG produced from waste feedstock, particularly domestic and agricultural waste, can capture methane that would otherwise be released into the atmosphere, resulting in a fuel that is not just net-zero in GHG emissions, but also potentially ‘net-negative’ in emissions.

Feedstock origins (the strict avoidance of food crops, and of land use changes for the production of biomethane) are regulated by sustainability frameworks such as the EU Renewable Energy Directive (RED III) and the US Renewable Fuel Standard (RFS). These lay out the rules, ensuring that bio-LNG production is traced and does not interfere with food systems or biodiversity. The application of such rules is monitored, audited, and certified by schemes like International Sustainability and Carbon Certification (ISCC).

In recognition of these advantages, bio-LNG bunkering volumes are growing. In 2Q25, bio-LNG bunkering volumes in Rotterdam were 4752 m 3 – up from 2200 m 3 in 2Q24. That is a 116% increase y/y for the busiest quarter in each. There have been frequent bio-LNG bunkering operations announced, and Titan has played a central role.

In 2024, for instance, Titan completed the world’s largest ship-to-ship bio-LNG bunkering. The company bunkered 2200 t of mass balanced bio-LNG to a Hapag-Lloyd containership in Rotterdam. The bio-LNG was ISSC certified and recognised under the EU’s RED III, marking a major milestone in the clean marine fuels transition.

United European Car Carriers (UECC), meanwhile, signed an agreement that saw its vessels sail on bio-LNG supplied by Titan for most of 2025. This multi-delivery agreement forms part of UECC’s ‘Sail for Change’ sustainability strategy, with the shipowner calculating that the emissions reduction is equivalent to the annual emissions of around 10 000 EU citizens. Through its CO 2 registry, this agreement offers UECC’s customers, car manufacturers, the opportunity to significantly reduce their Scope 3 transport emissions.

FuelEU Maritime compliance

A further incentive to use LNG and bio-LNG as bunkering fuel is provided by the FuelEU Maritime regulation. Under this regulation, ships using LNG will meet the GHG intensity requirements from day one until at least 2030.

After this date, bio-LNG can be introduced as required by the tightening targets, and in line with shipowners and operators’ voluntary decarbonisation initiatives.

Through its bio-LNG bunkering operations with Titan, UECC, for example, has gained FuelEU Maritime overcompliance. These surpluses can then be used to achieve compliance for other vessels in this fleet by transferring the FuelEU overcompliance to another vessel, which is called ‘pooling’. Such a scheme efficiently supports fleet compliance for operators that run their vessels on LNG or bio-LNG. This allocates a value to the overcompliance and incentivises operators to increase the share of LNG-fuelled tonnage in their fleet or to start running on bio-LNG earlier than initially planned.

Next steps on the pathway

Ensuring that there are no barriers to physical mass balancing throughout Europe is a further key step to scaling bio-LNG bunkering and lowering supply-side costs. Mass balanced bio-LNG can then be injected into the gas network and transported to liquefaction plants and LNG terminals using the existing infrastructure. This eventually works in the same way as when renewable electricity is transported via the power grid from its production site to the consumer that decided to use only renewable electricity. Such a system allows the industry to leverage existing infrastructure, thus reducing the cost for the production and transport of new renewable energy, facilitating its adoption.

Looking at the latest EU perspectives on mass balancing, the Sustainable Transport Investment Plan (STIP) has recommended member states avoid barriers to bio-LNG scaling up, but how this is implemented in reality must be closely monitored. Titan and other industry leaders have, in this respect, called on the Dutch government to ensure mass balancing and European biogas are recognised in its interpretation of EU regulations. Developing these practical delivery processes will support e-fuels like bio-LNG in the future.

When e-methane, e-methanol, and e-ammonia do emerge at scale in the future, they are expected to have similar costs of production as they require the same renewable hydrogen molecules and electrolysis capacity. As a result, the price will be led by infrastructure costs, making it clear that the opportunity to use existing infrastructure will convey a competitive advantage to renewable methane.

Titan support any fuel that can substantially decarbonise shipping, but for now the company has to recognise the cost, availability, and emissions advantages that the LNG route offers shipowners and operators today. LNG has set the strong infrastructure, safety, and emissions basis required for bio-LNG and e-methane to thrive, and bio-LNG is taking advantage of these foundations as it continues to emerge and scale up. Leading shipowners and operators recognise the clear benefits of bio-LNG today, and regulations like FuelEU Maritime are supporting demand. However, it is important that policymakers continue to break down barriers to the use of bio-LNG and all clean fuels at an even larger scale. This will allow the shipping industry to maintain competitiveness as it travels along the pathway to decarbonisation.

Figure 1. UECC’s Auto Advance vessel, fuelled with bio-LNG and delivered by Titan.

As carbon pricing reshapes global shipping economics, small scale LNG infrastructure and dual-fuel technology are giving tanker owners a practical path to compliance and profitability. Johnny Kackur, Head Coastal Merchant, Wärtsilä, explains how integrated marine systems are enabling efficient, regulation-ready operations.

Every shipowner asks a variation of the same question: which fuel will keep vessels compliant and profitable through 2030? The answer is not simple. But for a significant proportion of tankers, LNG has quickly become not only an interesting option, but the most viable fuelling option available today with the regulatory deadline hurtling ever closer.

From the International Maritime Organization’s (IMO) 2050 net-zero target to the EU’s tightening carbon rules, the pressure on tanker operators is mounting fast. Carbon pricing, lifecycle reporting, and efficiency ratings are no longer policy discussions; they are commercial realities. Against that backdrop, LNG stands out as a fuel that can reduce emissions today, control compliance costs, and maintain the operational performance shipowners rely on.

Wärtsilä’s work begins on the ship itself. Dual-fuel propulsion, optimised gas handling, and intelligent energy integration are the real enablers of decarbonisation. The challenge is not proving that LNG works; it is proving that it works everywhere, across every operating profile, without compromise – and it increasingly does.

Data from Clarksons shows that 23% of tanker newbuilds ordered in 2024 included LNG or LNG-ready propulsion, up from just 6% five years earlier. Owners are acting on operating economics, not sentiment: the financial logic of compliance now drives fleet strategy.

The wider growth of small scale LNG infrastructure is also transforming the economics of marine decarbonisation. Modular liquefaction plants, coastal terminals, and dedicated bunkering vessels are extending LNG availability to ports that were

previously beyond the reach of large scale import facilities. For LNG bunkering vessels, there is now a newbuilding boom, demonstrating the industry’s belief in LNG as a fuel for the future. Wärtsilä’s technology portfolio supports both sides of this ecosystem, covering gas-handling systems for bunkering vessels as well as the dual-fuel engines and hybrid solutions that enable ships to use the fuel efficiently on board.

LNG for compliance and profitability

Wärtsilä’s Future Fuels Report forecasts that policy measures such as the EU ETS and FuelEU Maritime will double the cost of fossil fuels by 2030. In this context, LNG emerges as one of the most immediate pathways to maintain compliance and reduce carbon exposure while sustainable fuel costs escalate.

According to Wärtsilä’s modelling, the cost of fossil diesel could rise by up to two times by 2030 due to emissions trading fees (EU ETS and FuelEU Maritime penalty), and beyond 2030 the emission trading fees will be higher than the fuel costs. This creates a tangible commercial case for LNG adoption over the next two decades, particularly for vessels subject to EU ETS coverage and FuelEU Maritime penalty requirements.

With EU carbon allowances averaging €78/t of carbon dioxide (CO2) in 2024, and projections above €100 by 2030, the incentive to decarbonise is financial, as well as environmental. Lower greenhouse gas intensity also translates into fewer penalties under the FuelEU Maritime regulation and a more favourable Carbon Intensity Indicator (CII) rating.

Within this policy landscape, LNG stands out as a practical option for owners seeking to limit exposure to rising carbon costs. Fossil LNG delivers approximately the same emission trading fees as the use of fossil diesel fuel with a methane slip rate of 3.1%, but lower methane slip rates give significantly lower emission trading fees. Wärtsilä’s NextDF technology achieves methane slip as low as 1.1%, which can reduce ETS costs by approximately 20% and may offer savings on emission trading fees of up to 80% until 2034, thanks to overcompliance for FuelEU Maritime fees. However, these substantial savings are only possible with lower methane slip rates.

These savings are not just about avoiding fines. They go directly to operating margins and competitiveness in charter tenders. LNG delivers up to 25% lower CO2 emissions than oil-based fuels and almost eliminates sulfur oxides while

cutting nitrogen oxides and particulates. It is one of the most practical ways to meet the EU ETS and IMO targets without introducing alternative fuel risk or large infrastructure changes. It is an obvious point, but shipowners need a compliance pathway that works across regions, charter requirements, and trading patterns. LNG offers that bridge: it is proven, available, and supported by a global bunkering network that grows every quarter.

That maturity is significant because compliance is now embedded in finance. Under the Poseidon Principles, 35 major shipping banks assess loan portfolios against IMO decarbonisation trajectories. LNG’s lifecycle and certification frameworks are already established, making it a compliance choice recognised by regulators, lenders, and investors alike.

System efficiency and operational consistency

From a systems perspective, efficiency is not only about the fuel but how the propulsion ecosystem performs as a whole. Wärtsilä focuses on integrating propulsion, automation, and control so that LNG-powered vessels can maintain consistent efficiency across all operating modes.

Whether a vessel is at sea, manoeuvring in port, or idling at berth, its propulsion system must handle frequent load changes smoothly. Wärtsilä’s control and safety logic ensures reliable fuel delivery to the dual-fuel engines while minimising methane loss and maintaining stable combustion. The goal is not just to run on gas; it is to run efficiently across the whole voyage profile.

According to DNV’s Alternative Fuels Insight database, there were 241 LNG bunker-capable vessels in service globally at the start of 2025, with a further 136 on order. This expanding infrastructure means the operational challenge is shifting from fuel availability to system optimisation on board.

The same principles apply to boil-off gas management. While Wärtsilä offers reliquefaction technology, the real value lies in the integration of propulsion, control, and gas-handling subsystems. Integrated control recovers energy that would otherwise be wasted, reduces tank pressure fluctuations, and keeps the power plant operating in its most efficient range.

In practice, this means the technology supports the crew rather than burdening them. Tanker operators report fewer manual adjustments and more predictable performance over long voyages. That reliability underpins the compliance case and ensures that the theoretical emission reductions seen in design studies are actually achieved on the water.

Dual-fuel propulsion and methane slip reduction

The methane slip debate has dominated LNG discussions for years, sometimes productively, sometimes not. What has changed is that engineering has caught up with the criticism.

Low methane slip from both main engine(s) and auxiliary engines is crucial for the success with LNG as marine fuel. Therefore, Wärtsilä has invested heavily in technologies which minimise methane slip. The company’s NextDF engine technology

Figure 1. Wärtsilä’s Future Fuels Report predicts EU ETS and FuelEU Maritime policies will double costs for fossil diesel fuel by 2030.

offers the lowest methane slip among four-stroke dual-fuel engines and can challenge two-stroke engines on methane slip. Low methane slip is no longer theoretical; it can also be achieved at multiple engine load points. Certification of methane slip will come in due time, but, until the certification process is finalised, it is important for shipowners that engine makers can provide guarantees for methane slip at multiple engine load points.

As of today, three of the company’s engines – Wärtsilä 46TS-DF, Wärtsilä 25DF, and Wärtsilä 31DF – are available with this NextDF technology. NextDF optimises air-fuel mixing and combustion timing to achieve methane emissions reductions down to less than 1.4% of fuel use across all load points, achieving as low as 1.1% in a wide load range.

For vessels already in service, progress continues. A software and combustion upgrade for the Wärtsilä 34DF can reduce methane slip by up to 60% depending on load profile. The company’s service engineers can install the upgrade during a scheduled maintenance window, avoiding downtime and capital expense.

Crew familiarity has also evolved. Improved automation means less manual tuning and greater consistency between voyages. For charterers monitoring emissions performance, that repeatability is as important as the headline numbers themselves.

In practical terms, LNG propulsion has moved from early adoption to optimisation. The engines are cleaner, the software smarter, and the learning curve largely complete. Methane slip is falling, combustion efficiency is rising, and the technology is fully compatible with renewable LNG variants as they enter the market.

Integration, hybridisation, and lifecycle efficiency

Once a ship adopts LNG, the next challenge is to keep improving performance. The solution lies in integration and digitalisation: connecting propulsion, electrical systems, and analytics to create a single operational ecosystem.

The Wärtsilä HY concept combines dual-fuel engines, batteries, and power electronics under unified control. The result is smoother load management, optimised efficiency, and lower fuel burn. During manoeuvring, bow thruster use, or port stays, the system automatically selects the most efficient energy source to meet demand.

Hybridisation helps the engines operate at consistent loads, reducing wear, thermal cycling, and unburned methane. Every incremental efficiency gain contributes directly to lower carbon cost exposure and stronger CII performance.

Digital tools sustain those gains. Expert Insight, Wärtsilä’s real-time performance monitoring service, analyses operational data and flags deviations before they affect efficiency. Combined with Operational Performance

Improvement, these services help operators optimise fuel use, extend maintenance intervals, and document emissions performance automatically.

Predictive analytics are now integral to vessel management. Wärtsilä’s data show that ships under continuous monitoring achieve higher availability, lower lifecycle cost, and fewer operational interruptions.

For LNG-fuelled tankers, this connected approach ensures that design-level performance is sustained throughout the vessel’s lifetime. It also simplifies compliance reporting. Measured data can feed directly into EU Monitoring, Reporting, and Verification (MRV) and IMO Data Collection Submissions, reducing administrative effort while improving accuracy.

Looking ahead, the same systems will underpin the transition to renewable LNG. Bio-LNG and e-LNG can be used interchangeably in existing dual-fuel engines without hardware modification. That means vessels built or retrofitted today are already compatible with tomorrow’s lower-carbon supply chains.

Conclusion

Will LNG be the final answer for maritime decarbonisation? Almost certainly not.

But right now, it is the answer that works best for a significant proportion of the global tanker fleet: technically proven, commercially viable, and regulation-ready.

For tanker operators facing carbon costs in 18 months, that is not a theoretical advantage but the difference between leading the transition and scrambling to catch up.

By 2030, the EU’s carbon market alone could add more than €2 million in annual operating cost to a 50 000 DWT tanker burning heavy fuel oil. For shipowners, that is reason enough to act now.

As small scale LNG networks continue to expand, access, and affordability will keep improving, strengthening LNG’s position as the most deployable low-carbon fuel of this decade. The journey to net zero will demand multiple solutions, but the ships that start with LNG will not be starting over. With efficient dual-fuel propulsion, low methane slip over the whole load range, integrated power systems, and digital lifecycle optimisation, LNG-fuelled tankers are already showing that compliance and profitability can coexist.

Figure 2. Wärtsilä HY concept combines dual-fuel engines, batteries and power electronics under unified control.

Figure 3. Wärtsilä Expert Insight, delivered through Wärtsilä’s global Expertise Centres, leverages artificial intelligence technology for predictive maintenance.

LNG carriers have played a foundational role in establishing LNG as a marine fuel. For nearly 60 years, these vessels have used boil-off gas from their cargo as fuel, refining best practices in cryogenic handling, boil-off management, emergency shutdown procedures, and ship-shore transfer routines. This extensive operational experience has created a safety culture and technical knowledge base unmatched by other alternative fuel pathways.

As LNG bunkering has grown, these lessons have informed global standards such as the International Maritime Organization’s (IMO) International Code of Safety for Ships Using Gases or Other Low-Flashpoint Fuels (IGF Code), Society of International Gas Tanker and Terminal Operators (SIGTTO) guidance, Society for Gas as a Marine Fuel (SGMF)

recommendations, and Baltic and International Maritime Council’s (BIMCO) contractual provisions for LNG quality and delivery. These frameworks incorporate critical safety features, including emergency shutdown logic, compatibility planning, and crew competency requirements. By adapting these practices to new vessel types, the industry has developed a blueprint for safe, predictable, and repeatable LNG bunkering operations.

The accumulated expertise from LNG cargo operations gives stakeholders the confidence and predictability needed to scale LNG bunkering efficiently. It also provides valuable insights that will support the future adoption of other alternative fuels in shipping.

What do you see being the biggest operational challenge of scaling LNG as a marine fuel?

One of the largest operational challenges in scaling LNG as a marine fuel is managing the growing variability and compatibility gaps across bunkering interfaces.

Despite advances in safety standards, differences in vessel and terminal systems – such as safety links, hose and transfer systems, manifolds, and fenders – can create operational unpredictability during each refuelling event. LNG bunkering involves more frequent transfers and a wider variety of vessel sizes and configurations than traditional cargo operations, which amplifies technical

compatibility risks. These variations impact safety margins, flow performance, and turnaround times. Efficient LNG bunkering requires careful planning, monitoring, and training, as well as attention to factors like hose sizing, vessel positioning, and mooring under variable conditions.

Without standardised interfaces and robust compatibility planning, these challenges can slow LNG uptake and compromise safety, efficiency, and profitability. Recent cases have shown that incompatibility between vessel and terminal systems can restrict operational flexibility and trading routes.

Operators often assume that selecting the correct bunker containment system or adhering to key procedural guidance is sufficient. However, ship operators prioritising flow rates to maximise turnaround times will need to consider a multitude of interconnected factors, from hose size and configuration to fender selection, vessel positioning, and mooring under variable conditions such as tidal movements, variable drafts, or different loads.

These interlinked technical factors are often overlooked, particularly as more vessel operators and suppliers from outside of traditional LNG supply chains become involved. This risk of ‘compatibility chaos’ across systems and interfaces is fast becoming an operational challenge in scaling LNG as a marine fuel.

A recent commissioning example illustrates this challenge. A major LNG carrier operator found that its installed ship-shore link (SSLs) and mooring load monitoring systems were incompatible with most Japanese terminals, preventing the vessels from calling and limiting global trading flexibility. By replacing the SSLs within extremely tight timescales, commissioning them during subsequent port calls and even in transit, Trelleborg restored terminal compatibility, enabling compliant data transfer and re-establishing safe, efficient berthing and transfer operations.

How can LNG suppliers and ship operators improve the predictability of bunker transfer operations?

Improving predictability starts with a thorough understanding of the technical details of each ship and terminal’s interfaces, including both mechanical connections and digital safety systems. The high frequency of LNG transfers compared to traditional cargo operations demands robust, specialised equipment and strong support networks to minimise unplanned downtime.

Advance planning, detailed interface knowledge, and structured crew training help operators anticipate and resolve compatibility and efficiency issues. LNG bunkering is a collaborative process whereby equipment across ship-to-ship (STS) and ship-to-terminal transfers must work seamlessly under variable conditions. Understanding flow behaviour, hose sizing, pressure drops, and multi-line configurations is crucial for managing boil-off, surge risks, and overall transfer performance.

Proactive equipment maintenance and lifecycle support further enhance reliability. Real-world examples show that motion analysis and automated mooring systems can stabilise vessel movement, while systematic calibration programmes ensure consistent performance. With robust equipment, detailed planning, and ongoing training, operators can significantly reduce unpredictability and improve bunkering consistency.

Figure 1. Ship-to-ship LNG transfer highlighting the importance of compatible mooring, fendering, and transfer interfaces in maintaining safety and efficiency.

Figure 2. Parallel berthing of LNG carriers during transfer operations, illustrating the role of operational stability during bunkering.

At an offshore LNG terminal in West Africa, long-period infragravity waves induced sway and surge motions that risked snapped moorings during continuous product transfer. Motion analysis and the installation of automated dynamic mooring units provided the adjustment range and redundancy to stabilise vessel movement, improve safety, and enable continuous, reliable transfer operations.

Predictability is also shaped by how well equipment is supported throughout its lifecycle. At a major Middle East terminal operating more than 400 quick release hooks, maintaining calibration across ageing equipment required a structured approach. A dedicated load cell exchange programme enabled planned swap-outs, rapid reinstallation, and systematic recalibration, ensuring compliance and consistent performance.

What

competencies

do crew need to develop and apply to ensure safe, efficient

LNG bunkering?

Crew competency is essential for safe and efficient LNG bunkering, especially as more operators bring in personnel without extensive LNG experience. While international standards such as the Standards of Training, Certification, and Watchkeeping for Seafarers, Section A-V/3 (STCW A-V/3 – specific to personnel on ships using gases or other low-flashpoint fuels) and IGF Code set minimum training requirements, practical skills in managing day-to-day bunkering operations are critical.

Crews must understand the technical differences between bunkering and receiving vessels, including safety links, transfer equipment, mooring arrangements, and the sequencing of key tasks. They also need to recognise how maintenance affects system performance, given the higher frequency of LNG transfers compared to traditional cargo operations.

Structured, hands-on training is vital. Programmes that combine project-specific manuals, classroom instruction, simulation tools, and onboard practice help personnel operate, maintain, and troubleshoot systems effectively.

During the conversion of Puteri Delima Satu into an FSU, the installation of a Gen3 double-bank SSL required comprehensive training for 42 crew members with varied technical backgrounds. A blended programme, incorporating project-specific manuals, classroom instruction, a Figma-based simulation tool, and onboard practical training enabled personnel to operate, maintain, and troubleshoot the system effectively, reducing downtime risk and strengthening transfer safety. Simulation is especially valuable for preparing crews for real-world scenarios, emergency responses, and efficient transfer sequencing.

Ongoing assessment and training is necessary as the industry adopts new alternative fuels such as hydrogen, ammonia, and methanol. Initiatives like Trelleborg’s Gas Transfer Centre of Excellence support the development and maintenance of the skills needed for today’s LNG systems and future fuel transitions.

What further steps does Trelleborg

recommend in improving compatibility?

Improving compatibility requires co-ordinated action at both the vessel design stage and during day-to-day operations.

While organisations like SGMF offer technical guidance, broader adoption of standardised specifications is needed to ensure seamless integration across LNG bunkering systems.

Shipyards should prioritise interoperability in design, moving away from proprietary solutions that create compatibility barriers. Modular design principles such as universal standards for connection points, valve configurations, and control systems enable LNG-capable vessels to work with a wider range of bunkering infrastructure.

Digital communication protocols and standardised sensors can automate compatibility checks and co-ordinate transfer parameters before physical connections are made, reducing manual verification and human error. Embedding automated safety shutoffs and common control interfaces from the outset streamlines operations, minimises risk, and improves reliability.

Operationally, flexible, well-supported equipment and informed planning are essential. Real-world examples show that adaptable transfer systems and systematic maintenance programmes can reduce downtime and enhance compatibility across multiple transfer modes.

For example, at a Mediterranean terminal handling multiple vessel sizes and transfer modes, including STS, ship-to-shore, and direct reloading from an FSRU to truck, variability created inefficiencies and required frequent equipment adjustments. By developing a flexible hose transfer system with enhanced diagnostics and minimal adjustment requirements, Trelleborg improved compatibility across all modes, reducing downtime.

Ultimately, improving compatibility depends on aligning interoperable vessel design with reliable equipment, strong digital systems, and competent crews. When these elements work together, LNG bunkering becomes more consistent and scalable.

What impact will getting ahead of these challenges have on the growth of LNG marine fuel operations?

Addressing these challenges is a critical step towards scaling LNG marine fuel operations. Standardising bunkering interfaces and improving compatibility will unlock operational efficiency, transforming LNG from a complex fuel choice into a scalable, streamlined business decision.

This optimisation creates a virtuous cycle: reduced transfer times, fewer delays, and improved safety margins drive down costs and boost service reliability. As a result, LNG bunkering becomes more attractive to a broader range of operators seeking immediate, viable alternatives to traditional marine fuels.

These improvements also accelerate LNG adoption across the global fleet, enabling operators to realise the benefits of cleaner fuel options at scale. The lessons learned from standardising LNG transfer interfaces will support the industry’s readiness for future fuels like ammonia, methanol, and hydrogen, creating transferable expertise in bunkering requirements, protocols, and safety procedures.

Ultimately, operational excellence and standardised interfaces lay the foundation for both environmental progress and commercial opportunity as the alternative fuels landscape evolves.

Gary Burns, BEL Valves, assesses the pressures involved in ensuring valves can be installed with confidence and operate without risk of failure.

Valves play a vital role wherever they are installed –controlling and isolating fluids and gases at extreme pressures and temperatures in a variety of different installation locations.

The most common places that valves and actuators can be found in use are in offshore topside facilities and deepwater production systems and subsea manifolds and pipelines. The company’s safety critical isolation valves are used for high-integrity pressure-protection systems, emergency shutdown, boarding shutdown, and subsea isolation.

The installation locations, product type, and size – valves can be manufactured from 0.5 in. diameter right up to 56 in. diameter – may well differ greatly, but the common ground they all share is that they need to be uncompromisingly reliable as they are there to safeguard operations, people, assets, and the environment.

That translates to a lot of pressure on each and every valve, and so it is clear that the standards they are manufactured to need to be exacting, to say the very least.

Valve testing

Valves, including those of BEL Valves, are engineered to comply with a variety of requirements, which can comprise BS, EN, API, and ISO series’ standards (e.g. API 6A, 6D, 6DSS, 17D; ISO 15848, 10497); UK Pressure Equipment Safety Regulations; the European Pressure Equipment Directive; relevant regional specifications such as NORSOK; and any client/end user-specific requirements.

To achieve this, the company’s valves undergo a tailored sequence of qualification and production tests depending on end use and function:

z Hydrostatic testing is crucial in ensuring the safety and reliability of pressure systems. It involves filling the system with water and applying pressure, typically at 1.5 times the rated working pressure, and checking for leaks or deformation. It is carried out to provide confirmation that the equipment can operate to its required limits.

z Gas testing confirms a valve’s leakage performance at the seats, stem packing, and pressure retaining joints, as well as through wall leakage to defined limits, ensuring it seals

properly in service. It uses air or nitrogen to verify sealing integrity because gases are compressible and can reveal finer leak paths than water. Gas tests validate real world performance and often detect leaks that a hydrostatic test may not.

z Fugitive-emissions testing assesses leakage to atmosphere from the stem packing and body joints under pressure and thermal/mechanical cycling. Most often performed with helium as the test medium, its small molecule size reveals ultra fine leak paths. It demonstrates environmental compliance and low emission design.

z Endurance/cycle testing evaluates the performance and durability of valves by subjecting them to repeated opening and closing cycles under strictly controlled conditions. The testing is essential for identifying potential failures and ensuring the valves will withstand the demands of their intended applications.

z Hyperbaric testing verifies valve integrity and operation under pressures simulating subsea depth. In a pressure chamber, the valve is cycled and checked for ingress (external to internal) and egress (internal to external) leakage, plus actuator performance, proving sealing and function at depth.

z Temperature testing assesses the performance of valves in extreme temperatures – typically from cryogenic lows of -150˚C to extreme highs of 315˚C.

z Fire testing, as the name suggests, is carried out to demonstrate a valves ability for containment and operability under fire conditions.

In addition, advanced non-destructive examination (radiography, ultrasonics, PMI, dye-penetrant, and more) supports each stage of manufacture, along with safety integrity level (SIL) capability assessments for safety critical valves and actuators.

All type, qualification, and factory-acceptance testing is carried out in the company’s purpose-built, high-integrity facilities in Newcastle upon Tyne, the UK. This puts the company in a position where feedback on testing is rapid and continuous improvement is a key element of the product development lifeline of every single valve being designed, engineered, and manufactured.

For projects with extreme operational scenarios –ultra-deepwater or hydrogen service, for example – valves are tested well beyond the minimum requirements. Working closely with clients, the company designs bespoke type tests that replicate field conditions more severe than any standard demands.

Of course, not every product tested ends in success. Occasionally a prototype is pushed past its limits, which is the point. Whether it is minor seat leakage or unexpected actuation torque, every anomaly feeds directly into the continuous-improvement loop; driving the development of safer, more reliable products.

The world though does not stand still and so the onus is on manufacturers to keep pace with technological developments and changing industry requirements. The shift

Figure 2. BEL Valves’ 6 in. NB, CL900, through conduit expanding gate valve, which was installed at the Kårstø processing plant in Norway.

Figure 1. The Kårstø processing plant in Norway.

towards hydrogen, carbon dioxide, and other low-carbon fluids is certainly the key focus for companies and the industry as a whole, and one that is being discussed amongst various industry working groups. The aim of them all being to identify and develop new working practices and drive standardisation – ensuring all new standards are created by those who can rightfully lay claim to being experts in the field.

At present, the creation of valves that deliver greater control of seat leakage and tight shut-off performance; fugitive emissions; fire safety; and metallic and non-metallic material qualification is high on everyone’s agendas.

What is certain during this period of change is that new standards will be developed and ratified, new products engineered, and existing ones modified – ensuring the safety critical operation of the valves used in these high-value, high-importance installations is never compromised.

A real-world example

BEL Valves manufactures high integrity valves, complete with actuation and control systems for oil and gas, hydrogen, and carbon capture installations, with its products in demand around the world. Most recently, the company supplied valves worth six-figures to Norwegian multinational energy company, Equinor, for its Kårstø processing plant in Norway. The plant, which is located in Nord-Rogaland, plays a key role in the transport and processing of gas, condensates, and light oil from major sites on the Norwegian continental shelf. Around 30 fields are connected to it via pipelines, and millions of cubic metres of gas and condensates and light oil flow into the plant

CRYOGENIC PUMP SURVIVAL!

every day. There, the heavier components are separated out, and the remaining dry gas or sales gas is piped onwards to the continent.

BEL Valves’ CL900 topside through conduit double expanding split gate valves with gearboxes were specified due to fast lead times. Supplied in two sizes – 10 in. and 6 in. diameter – the valves were designed, tested, and manufactured at the company’s HQ in Newcastle upon Tyne, and enable double block and bleed functionality within one single valve assembly, as opposed to the two conventional slab gates that would otherwise be required.

The benefits of these valves include overall cost, size, and weight reduction, and have an ability to be configured to seal in either the closed position (single expanding) or open and closed position (double expanding). Further options ensure a fit-for-purpose solution can be developed to suit specific application demands.

Conclusion

The importance of valves in an LNG installation cannot ever be underestimated. An unproven or under-specified product not only puts the installation at risk, but the entire operation and – far more importantly – lives. A BEL Valves valve can be specified and installed with confidence, with each product embodying decades of engineering expertise, a culture of safety, and innovation. By exceeding global standards, pioneering new test methods and validating performance under the harshest conditions, the company fulfils one simple promise – safe, reliable, and built to last valves.

J. Anguiano, Vice President of Emerging Technologies, Reset Energy, USA, identifies how managing nitrogen in LNG can improve the operational efficiency and commercial impact across the value chain.

As US LNG exports continue their upward trajectory, passing 13 billion ft 3 /d, facilities along the Gulf Coast are grappling with increasingly complex feed gas compositions. Among the many variables, the rising presence of nitrogen (N 2 ) has emerged as a significant concern for domestic natural gas production, particularly for LNG producers. Nitrogen can strain liquefaction efficiency, impact operability, and diminish commercial performance. Midstream pipeline specifications typically require less than

3 mol% inerts (N 2 and carbon dioxide [CO 2 ]), while liquefaction specifications typically demand a much stricter limit of less than 1 mol% N 2 . Therefore, the need for effective nitrogen removal is not a temporary issue, but a potentially permanent fixture of the industry.

For LNG producers, traders, and midstream operators, understanding the role of nitrogen is no longer optional – it is essential for protecting margins and fulfilling contractual obligations. This article explores how nitrogen affects every stage of

LNG production, storage, and transport. It will also detail why proactive management is critical for operational reliability and sustained profitability in an increasingly competitive global market.

Why nitrogen matters in LNG

Nitrogen finds its way into the LNG value chain through various sources. It is naturally present in underground gas reservoirs, can be introduced during gas-cap injection for enhanced oil recovery, can enter through air ingress in gathering systems, and is sometimes used in pipeline blending. While upstream processes rarely control nitrogen content, its presence at the liquefaction stage introduces measurable and costly challenges.

Global trade specifications, such as those from GIIGNL and ASTM, typically cap nitrogen at 1 mol% in commercially-traded LNG. US export contracts often tighten these limits even further. These strict limitations exist for sound scientific and commercial reasons. Nitrogen’s boiling point of -196˚C is significantly lower than methane’s at -162˚C. This difference in volatility increases the refrigeration loads required to liquefy the natural gas stream, can shift critical pinch points within heat exchangers, and increases the boil-off rate of the LNG product. Additionally, each 1 mol% increase in nitrogen content can reduce the LNG’s higher heating value (HHV) by approximately 0.5%. Even small deviations in nitrogen content can lead to a cascade of negative effects, including higher power consumption, changing LNG density, and reducing the heating value – all of which directly impact the economics of each cargo.

Technical impact on liquefaction

LNG liquefaction trains are complex systems engineered for predictable thermodynamics. Nitrogen disrupts this delicate balance by requiring additional refrigeration

duty to condense the lighter, more volatile component. Every 1 mol% increase in nitrogen in the feed gas can raise power consumption by roughly 1 – 1.5% in a liquefaction refrigeration loop. Additionally, roughly a 2 – 2.5% reduction in LNG production can be expected for every 1 mol% increase in nitrogen. For example, a 10 million tpy facility, using a delivered price of US$580/t, would result in US$130.5 million/y loss of production for a 1% increase in nitrogen.

Cryogenic heat exchangers, the heart of the liquefaction process, are particularly sensitive to changes in composition. The presence of excess nitrogen can cause shifts in pinch points – the locations within the heat exchanger where the temperature difference between the hot and cold streams is at its minimum. These shifts can complicate process control, reduce thermal efficiency, and, in more extreme cases, force operators to reduce feed gas rates to maintain stability. For facilities operating under tight delivery schedules and take-or-pay contracts, this nitrogen-induced variability can translate into lost capacity and higher unit costs. What begins as a minor compositional issue quickly becomes an operational risk with clear and significant commercial consequences.

Storage and shipping challenges

Nitrogen’s influence does not end once the LNG leaves the liquefaction train. In cryogenic storage tanks, a higher nitrogen concentration elevates the vapour pressure of the stored LNG and accelerates the rate of boil-off gas (BOG) generation. Because nitrogen is more volatile than methane, it tends to accumulate in the vapour phase above the liquid. This requires more frequent venting or reliquefaction to maintain safe tank pressures and control inventory losses. Both solutions come with their own costs, either through the loss of valuable methane or the energy required to reliquefy the BOG. Note that when reliquefying the BOG, there is still venting required to remove some of this nitrogen content which means some methane will be lost as well.

During shipping, these effects are amplified. LNG with elevated nitrogen content is lighter, meaning it has a lower density. This can create density mismatches when loading or commingling different cargoes, complicating blending strategies at receiving terminals. As a ship travels to its destination, nitrogen continues to vaporise and concentrate in the vapour space of the cargo tanks, steadily increasing pressure and BOG rates. As BOG is removed, methane is lost with it, causing the liquid to become heavier, which creates more complications. Marine carriers must deploy active vapour management systems, such as gas combustion units or on-board reliquefaction plants, to manage this pressure build up. Failure to do so can result in off-spec deliveries or, in a worst-case scenario,

Figure 1. Potential points of installation for nitrogen rejection units within the gas processing and LNG process chain, with key advantages and limitations.

Table 1. Effect of 3 mol% nitrogen in feed gas (vs 1 mol%)

NRU – Truth in Numbers

44 NRU Installations

46 Years of Industry Leadership 31 Patents Awarded

Our expertise in NRU design comes from real-world startup and operational experience, not just process simulations. With a proven track record and unmatched engineering pedigree, the BCCK team ensures every NRU project is a success. Trust the industry leaders in nitrogen rejection technology for reliable performance.

Failure is not an option with BCCK.

Our track record speaks for itself.

safety incidents. These management systems add cost, complexity, and fuel consumption to marine operations. Examples of the operational and commercial consequences are shown in Table 1.

Strategic approaches to nitrogen removal

Given the operational and commercial stakes, LNG producers are increasingly focused on strategic solutions for nitrogen management. The primary tool for this is the nitrogen removal unit (NRU), and decisions surrounding its implementation involve several key considerations.

Where to place an NRU?

There are three primary locations for installing an NRU:

1. At the cryogenic plant residue stream.

2. Along the pipeline system.

3. At the LNG plant itself.

Each option carries distinct advantages and constraints, as demonstrated in Figure 1.

Locating an NRU at the cryogenic plant residue offers the benefit of existing pretreatment infrastructure – amine units, dehydration systems, and other balance-of-plant equipment – but is constrained by site throughput limits and emissions requirements.

Pipeline-based NRUs, by contrast, provide access to high volumes and economies of scale; however, they require full pretreatment build-out, greenfield construction, and are restricted by pipeline scheduling and siting challenges.

At the LNG facility, an NRU can leverage established pretreatment systems and highly efficient cold-energy integration, but available footprint and regulatory constraints often limit feasibility.

Installing an integrated NRU at the LNG plant is technically the most straightforward solution; after all, the facility is already liquefying methane, making nitrogen separation more efficient. Yet this becomes far more complex across existing brownfield facilities where large, established production assets often involve layered ownership structures and multiple stakeholders. LNG plants operate under tight permit envelopes, with fixed equipment layouts and contractual structures that resist major process changes. As a result, the nitrogen challenge

often shifts upstream, prompting the midstream sector to determine where NRUs should be deployed to meet downstream specifications.

By contrast, a standalone NRU operates independently of the main liquefaction train. While it requires its own support utilities, it offers greater operational flexibility and is far less disruptive to install at an existing site. For large, established LNG facilities with limited plot space or those looking to avoid a prolonged and complex shutdown, a modular, standalone unit is often the more feasible option. Another possibility is locating an NRU at a ‘straddle plant’ outside the boundaries of the LNG facility altogether. This midstream approach treats the gas before it even reaches the plant’s fence line, which can benefit multiple downstream users.

If nitrogen levels in feed gas continue to rise, fully integrated LNG facilities represent the most technically robust long-term approach. However, the question remains: how industry contracts, cost allocation dynamics, and the perennial ‘not my problem’ mindset will ultimately distribute the burden of this investment.

The role of NRUs in the midstream sector

Midstream operators play a crucial role in managing gas quality for the entire network, including LNG export facilities. Midstream NRUs are often designed for bypass and blending capabilities, allowing operators to precisely control the final inert content to meet pipeline specifications of <3 mol%. These units are highly capable and can be designed to reduce nitrogen to levels below 1 mol%, providing a high-purity stream that can be blended with untreated gas. This flexibility allows operators to manage a wide range of upstream nitrogen concentrations while consistently delivering on-spec gas.

A key design choice for midstream NRUs is the number of distillation columns. A single-column design is simpler and has a lower capital cost but is less energy-efficient, particularly when dealing with low-nitrogen feed gas. A two-column system, while more complex and expensive upfront, offers superior thermal efficiency by better utilising heat exchange between streams. This reduces the required compression horsepower and lowers long-term operating costs for low-nitrogen feed gas. The choice between them depends on factors like expected nitrogen loads, energy costs, and required outlet pressures. Compression requirements are the major driver of an NRU’s OPEX, as significant power is needed to compress the treated gas stream to the target delivery pressures.

Conclusion

Nitrogen may seem like a minor component in the vast natural gas value chain, but its influence is pervasive and significant. From adding refrigeration duty and increasing power consumption at the liquefaction plant to accelerating BOG during storage and transport, nitrogen introduces risks that operators, traders, and commercial teams cannot afford to ignore. Its impact on heating value directly affects revenue and contract compliance, making effective management essential for profitability.

Figure 2. 3D plot plan illustrating the overall equipment arrangement, major process units, and interconnecting piping for a 250 million ft3/d NRU facility.

Sam

Dobos, Business Development Manager, Chromalox,

explores how medium voltage electric process heat is powering reliability and productivity.

In the past decade, electric process heating has emerged as a growing technology supporting the most critical operations within the LNG value chain. From liquefaction and transport to regasification, electric heating technologies have increasingly played a vital role in ensuring efficiency, safety, and environmental compliance. Their precision, reliability, and adaptability make them indispensable across every stage of LNG processing.

Low voltage (LV) electric process heaters have predominantly served as the standard. These solutions offer clean, controllable heat for smaller scale applications such as gas preheating, trace heating, and utility systems. However, as LNG facilities have grown in scale and complexity, and as pressure mounts to replace energy-intensive fired systems, the demand for higher-capacity, more efficient, and more reliable heating technologies continues to rise.

Today, medium voltage (MV) electric process heating systems are expanding what is technically achievable, providing capabilities that exceed the limitations of traditional LV systems. Combining the proven safety and precision of electric heating with the durability and scalability needed for large scale LNG operations, MV solutions are enhancing the delivery of process heat across the LNG value chain, from the front-end gas treatment process to balance-of-plant (BOP) and auxiliary systems.

A legacy of electric process heating in LNG

Electric process heating has long been an established solution in LNG due to its accuracy, cleanliness, and responsiveness. Unlike combustion-based systems, electric heaters deliver heat directly into the process fluid with minimal losses, no onsite emissions, and no need for fuel handling infrastructure.

These electric heating systems support critical functions such as:

z Feed gas preheating prior to cryogenic liquefaction.

z Amine regeneration and molecular sieve dehydration.

z Boil-off gas (BOG) management.

z Vaporisation and re-gasification processes.

z Tank and pipeline heat tracing.

z Utility heating, including water and glycol loops.

In many of these processes, uptime and reliability are non-negotiable. Any variation in temperature control can disrupt production, activate safety protocols, or even force plant shutdowns. That is why LNG operators value the stability and controllability of electric heat, qualities that contribute directly to process productivity and facility availability.

The rise of medium voltage electric process heat

In recent years, electric process heat technology has advanced significantly, enabling electric heaters to handle multi-megawatt loads efficiently and safely. MV electric process heat solutions are ideal for large scale applications such as LNG facilities where total thermal demand can reach hundreds of megawatts.

What is driving the shift to medium voltage?

Scalability and efficiency

MV heaters significantly reduce current draw for a given power level. This allows for smaller conductor sizes, fewer transformers, and simplified cabling – reducing installation complexity and operational inefficiencies.

Reduced infrastructure complexity

Unlike LV systems that require numerous parallel circuits to achieve higher capacities, MV systems can achieve the same thermal output with fewer connection points. The result is reduced capital investment, reduced maintenance complexity, and minimised risk of component failure.

Figure 2. MV systems integrate seamlessly into modern digital control architectures.

Figure 1. MV solutions are enhancing the delivery of process heat across the LNG value chain.

Enhanced reliability and uptime

By minimising the number of cables, contactors, and fuses, MV solutions reduce the likelihood of electrical faults. A simplified circuit architecture improves system reliability and uptime, both of which are top priorities in LNG operations.

Operational flexibility

MV systems integrate seamlessly into modern digital control architectures. Advanced power electronics and modular converter systems enable precise temperature control, rapid response times, and continuous monitoring – aligning with the LNG industry’s drive for predictive maintenance and remote diagnostics.

Where electric process heat fits in the LNG value chain

Electric process heating can be applied across virtually every step of LNG production and handling. Each application brings its own technical demands, but across them all, the same values of reliability, controllability, and efficiency apply.

1. Gas treatment and conditioning

Before natural gas can be liquefied, it must be purified. Electric heaters are integral to:

z Amine regeneration (heating the solvent to remove absorbed carbon dioxide [CO₂] and hydrogen sulfide [H₂S]).

z Molecular sieve dehydration (desorbing moisture from adsorbent beds).

z Mercury removal and nitrogen rejection units.

In these stages, precise heat control ensures optimal solvent regeneration, protects catalyst beds, and maximises system efficiency. Any deviation from the specified temperature range can shorten catalyst life or reduce gas purity – both costly outcomes.

2. Liquefaction and pre-cooling

While refrigeration systems perform the core duty of cooling natural gas to cryogenic temperatures, electric heaters often support peripheral systems such as oil heating for compressors, lube and seal oil systems, process gas preheating prior to cryogenic expansion, and heat tracing of cryogenic lines.

Electric heating solutions are particularly valuable in these areas, where power demands are high and reliability is critical. With numerous thermal loads, the scalability and modularity of electric systems – able to meet true demand through LV and MV configurations – offer a strong alternative to centralised fired systems, which rely on complex thermal distribution networks. This approach minimises electrical infrastructure requirements, reduces footprint, and lowers downtime risk.

3. Storage and boil-off gas management

BOG handling is another area where electric process heat plays an essential role. Heaters are used in BOG

vaporisers and compressors, LNG re-condensers, and fuel gas conditioning systems.

MV solutions are particularly valuable here, providing high-capacity heat to manage these critical systems –ensuring the continuous reintegration of BOG without process interruption.

4. Balance of plant and utilities

Beyond the main process, electric heating is crucial in BOP and utility systems such as hot water or glycol heating loops, space and enclosure heating, instrumentation freeze protection, and flare knockout drum heating.

These systems ensure smooth, safe, and continuous operation, often consistently supporting uptime for the entire facility.

5. Marine loading and regasification terminals

At LNG export and import terminals, electric heaters support vaporisation and pressure management. Their inherent safety (no open flame) and ability to operate in hazardous environments make them well aligned for ship loading and unloading operations.

Reliability and process productivity in LNG operations

The LNG industry is defined by its scale and its intolerance for downtime. Unplanned outages can result in substantial production losses. For this reason, reliability and process uptime are at the core of any equipment decision.

Electric process heaters, especially MV systems, offer inherent advantages. There are no moving parts, reducing mechanical wear and maintenance. Additionally, they offer precise control, ensuring process stability and repeatability. These systems come with built-in reliability features, including modular design and replaceable heating elements, and also offer predictive diagnostics, enabling proactive maintenance and minimising downtime.

Where fuel-fired heaters can suffer from burner fouling, flame instability, or emissions system downtime, MV electric systems operate cleanly and consistently, even under fluctuating process conditions. This reliability contributes directly to process productivity, supporting LNG operators in achieving production targets and operational commitments.

The advantages of medium voltage electric heat

Both LV and MV systems deliver clean, controllable heat, but MV systems offer distinct advantages for large scale applications:

z Typical voltage: 1 – 7.2 kV.

z Typical power capacity: >2 MW.

z Few or single circuits needed for large loads.

z Cable and conduit requirements are reduced.

z Efficiency is higher, with fewer losses and smaller conductors.

z Maintenance complexity is reduced with simplified architecture.

z Uptime and reliability are higher, with fewer points of failure.

z Capital cost (installed) is lower for multi-megawatt systems.

To summarise, MV systems provide superior efficiency, scalability, and reliability – key considerations for large LNG facilities operating 24/7 under demanding environmental conditions.

Safety and environmental advantages

As global LNG producers move towards cleaner, more sustainable operations, electric heating aligns effectively with environmental and safety requirements.

z Zero Scope 1 emissions: Electric heaters eliminate on-site combustion, reducing carbon footprint and simplifying compliance with emissions regulations.

z No fuel storage or handling: This improves site safety and frees up valuable space.

z Integration with renewable energy sources: As grid electricity increasingly incorporates renewables, electric heating becomes progressively lower in carbon intensity over its operational life.

z MV systems, when designed with appropriate insulation, grounding, and protective relaying, meet stringent international safety standards (such as IEC, IEEE, and API).

Medium voltage innovation: A proven technology

Recent innovations have pushed MV electric heating technology into mainstream LNG adoption. Systems such as Chromalox’s DirectConnect MV process heating platform exemplify this shift, integrating heating elements, MV power conversion, and control systems into a unified engineered solution. This technology has been deployed globally across oil, gas, and chemical sectors, demonstrating reliability in some of the harshest industrial environments. With fewer step-down transformers and simplified wiring, DirectConnect systems ultimately reduce costs while improving thermal efficiency.

Case study: Medium voltage heating at a major US LNG facility

A large LNG export terminal on the US Gulf Coast recently faced the challenge of implementing high-capacity, reliable electric heating systems as part of its multi-train expansion. The project required robust solutions to support both gas treatment and auxiliary

heating processes under demanding performance and uptime criteria.

The EPC contractor sought a partner with proven expertise in MV electric process heat. After evaluating options, they selected a solution built on DirectConnect MV technology, chosen for its extensive track record in global markets, backed by decades of experience and over 280 MW of DirectConnect systems installed worldwide.

The system provided:

z Reduced site infrastructure, thanks to minimised circuit counts and direct MV connection.

z Higher overall system efficiency, with lower electrical losses and smaller conductors.

z Simplified maintenance, through modular design and digital monitoring.

z Zero Scope 1 emissions, supporting the facility’s sustainability goals.

The equipment spans multiple process trains and will play a vital role once the site becomes fully operational. Its durability and scalability will help ensure consistent performance across the plant’s lifecycle, supporting uptime, efficiency, and long-term productivity.

Full range in cryogenics

The future of electric process heating in LNG

The transition to MV electric heating is a meaningful advancement. It is a key step forward for future LNG facilities. As global energy markets focus more on efficiency, lower emissions, and reliable operations, electric process heating is positioned to play an increasingly important role.

Key trends shaping this evolution include:

z Electrification and decarbonisation of process utilities to meet environmental, social, and governance targets.

z Integration with renewable power sources and hybrid energy systems.

z Digitally-enabled heaters with predictive analytics and remote monitoring.

z Modular MV architectures for faster installation and reduced commissioning time.

By investing in proven MV electric heat technologies today, LNG operators position themselves to support safer, more reliable, and sustainable energy delivery for decades to come.

LNG STORAGE, CARGO AND FUEL TANKS

CRYOGENIC TRANSPORT TANKS

CRYOGENIC STORAGE TANKS

REGASSIFICATION PACKAGES

LCO2, NH3, (L)H2 TANK

VAPORIZERS (WATERBATH AND AMBIENT)

TRUCK FUELING STATION TANK

Maritime LNG Fuel Tank

Designing risk out of digital pipelines

Featuring Hector Perez, Head of Strategy for Black & Veatch’s Industrial Cybersecurity practice. This episode discusses digital twins, predictive analytics, and emerging AI tools, highlighting how siloed data, legacy systems, and unmanaged digital risk can undermine operational gains if security is treated as an afterthought.

We cover:

• How pipeline operators are moving from reactive maintenance to predictive maintenance.

• Digitally enabled asset strategies.

• Why cybersecurity must be embedded from the outset.

Hector Perez, Black & Veatch

Elizabeth Corner

Part one of this two-part article explored case studies carried out by Kranji Solutions involving LNG pre-treatment and main liquefaction processes.

In this second part, the article will look at a third case, where Kranji Solution’s flow analysis expertise was applied to evaluate the adequacy of flow conditions

in a key part of the natural gas liquid (NGL) recovery process.

Case 3: NGL recovery fractionator column – design review

In addition to the phase separation applications described in part one of this article, Kranji Solutions has also been

commissioned by operators, engineering contractors, and equipment vendors to perform independent design verification studies for columns and their internals in NGL recovery and fractionation units associated with LNG facilities. An example of this work was the CFD review conducted to assess the gas flow distribution within the inlet section of an NGL stabiliser column, for a newbuild LNG project in North America.

The CFD model included upstream piping geometry, vane type inlet device, chimney tray deck, and the bottom section of the packed bed with a multi-beam gas injection support plate (Figure 1).

The analysis revealed a somewhat biased gas flow distribution within the inlet section, with preferential flow to the right-hand side, defined as right when viewed from the inlet nozzle into the column (Figure 2).

Numerous LNG facilities have experienced fatigue-related failures of inlet devices resulting from vibrations induced by unstable and transient flow conditions. In this case, the left-right flow distribution across the vane type inlet device was monitored over time to evaluate cyclic pressure loading on the individual vane blades. This data enabled a fatigue assessment, incorporating flow-induced vibration analysis coupled with finite element modelling, to quantify the inlet device structural integrity under operational conditions.

To quantify the preferential flow effect at the inlet section, the gas flow rate through each chimney was monitored over time, and deviations from the overall average chimney velocity were evaluated (Figure 3).

Across all chimneys, the deviation from the mean flow was found to be less than 5%, indicating that the flow distribution between chimneys was acceptable for good mass-transfer performance.

Further evaluation of the flow distribution over the perforated multi-beam support plate and into the packed bed was performed (Figure 4). Comparison of velocity profiles at successive elevations shows progressive improvement in flow uniformity through the support plate and into the packed section. The lower 1 m of the packed bed was included in the simulation and results demonstrate that the gas velocity profile is fully uniform at this height, with the maximum velocity being less than 1% above the mean.

Overall, the CFD analysis confirmed a well-balanced gas distribution throughout the inlet section of the NGL stabiliser column (Figure 4). These findings validate the effectiveness of the column internal configuration and confirm the adequacy of the current design for stable and efficient operation.

Remedial solutions

Referring back to part one of this two-part article, Kranji Solutions is often involved in developing remediation solutions. Where retrofit modifications are proposed, these are generally required without replacement of vessels or modification of connected pipework.

Case 1: Kranji Solutions’ study demonstrated the requirement for an anti-swirl element, immediately upstream of inlet and the need for replacement of the inlet diverter arrangement with a vane-type

Figure 3. Gas flow distribution at chimney tray.

Figure 4. Gas flow distribution within packed bed.

Figure 2. Gas flow distribution at inlet section.

Figure 1. CFD model geometry on inlet section of NGL stabiliser column.

inlet device. Like other separators encountered by Kranji Solutions, this vessel would have also benefited from a more generous length of horizontal pipe at inlet. Its operating envelope could have been extended through a retrofit by repositioning the inlet device to a lower elevation in the vessel using internal ducting. Such a reconfiguration would allow provision of higher performance demisting technology.

Case 2: The internals could be re-configured as shown in Figure 5. On the left, the original configuration with a highly-undesirable arrangement of two-bank gas box is shown. Superficially, this would appear to offer sufficient flow area for adequate demisting performance; however, constraining the gas flow into a small cross section to feed either bank promotes significant mal-distribution.

On the right of Figure 5 is a retrofit arrangement frequently recommended by the Kranji Solutions team’s phase separation experts. This promotes good distribution of gas flow through the combination of agglomerator and demisting cyclones. In addition, an anti-re-entrainment device would be recommended to minimise the interaction of the incoming gas with the surface of collected liquid.

Case 3: Verification confirmed the adequacy of the proposed design. In many cases Kranji Solutions will recommend retrofit options for existing vessels where mal-performance has been identified. These recommendations are always verified by CFD simulation of the remedial arrangements, often in combination with MySep software performance evaluations. Many instances of field confirmation of performance are cited by Kranji Solutions’ customer references.

Conclusions and recommendations

The case studies outlined in part one (published in the December 2025 issue of LNG Industry) 2 and in part two here all relate to LNG processes; however, the problems encountered are all too common across upstream oil and gas production, midstream gas processing, LNG, and refining.

Other common issues for LNG processes, encountered by Kranji Solutions, are important to list:

1. Operators often report issues in gas sweetening units where off-spec product gas or excessive consumption of solvents result from foaming in amine contactors. This is usually the result of excessive carry-over of hydrocarbons into the contactor.

2. Similar issues to those listed in the first point (above) are experienced on glycol contactors in dehydration units.

3. In large baseload LNG processes where the feed gas has a high concentration of hydrogen sulfide, sulfur recovery units (SRUs) can experience issues with separation equipment on the process side of SRU sulfur condensers, with carry-over of liquid sulfur presenting corrosion issues in the tail-gas treatment units.

4. Kranji Solutions’ multi-phase CFD experience has also been applied to water-side corrosion issues in SRU sulfur condensers. 1 Such experience reported on large scale gas export plant would be equally relevant to similar units in LNG processes with SRUs.

Poor design and performance of separation equipment often stems from application of crude, criteria-base sizing practices that fail to consider:

z Inlet piping configuration and biased flow effects.

z Inlet stream phase conditions, including mist fractions and droplet size distributions.

z Flow maldistribution in gravity section and demisting sections of separation equipment.

z Flow distribution resulting in re-entrainment from the surface of collected liquids.

z Separation efficiency and liquid handling capacity of demisting equipment.

Many of these problems can be avoided at the design stage, by adoption of the good practice and incremental separation analysis provided in MySep Studio and MySep Engine software. Adopted by many leading operating companies and the premier engineering contractors, these provide an industry-wide recognised standard approach for separator design. MySep is also acknowledged also for off-line rating of operating separation equipment and for rigorous separation modelling in process digital twins.

References

1. RALSTON, T., SINGAPORE WALA, A. A., and VAN-VORSELEN, M., ‘Understanding Heat Transfer and Complex Buoyancy Driven Circulation in Sulphur Condensers’, ADIPEC, (November 2020), SPE-203107-MS.

2. MOYSON, W. and RALSTON, T., ‘Breaking free from phase separation constraints’, LNG Industry, (December 2025), pp.43 – 46.

Figure 5. Original and preferred optimum design by MySep software.