LNG Industry May 2022

May 2022

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ISSN 1747-1826

CONTENTS

03 05 07 12

Comment Guest comment LNG news Make an entrance

Laura Page, Kpler, UK, explores how the emerging LNG markets in the Philippines, Vietnam, and Hong Kong are gearing up to start imports, how high prices could impact future demand, and outlines the sustainable benefits of LNG.

18 A seismic shift

David Stokes, Olly Spinks, and David Duncan, Timera Energy, UK, unpack the effects of the Russia - Ukraine conflict in triggering a new LNG market regime and set out its implications for LNG portfolio value and risk.

24 Bridge the knowledge gap

Tim Wyatt, Cheniere, USA, details how the lifecycle emissions of an LNG cargo can be more accurately estimated, and how the absence of transparent, credible data in this area is being addressed.

28 A step forward for carbon-neutral LNG

Rogier Beaumont, Head of Atlantic LNG Origination and Global Environmental Solutions, Pavilion Energy, Singapore, outlines how a greenhouse gas methodology for delivered LNG cargoes paves the way towards a carbon-neutral LNG world.

32 The building blocks for success

Chuck Hayes, Swagelok, USA, describes how to choose the right tube fittings for LNG vehicle and infrastructure projects.

37 Oceans of potential

Anna Apostolopoulou and Panos Mitrou, Lloyd’s Register, Greece, explain the opportunities presented by floating gas technology, discussing matters such as energy security, affordability, and the choice between building new or converting existing vessels.

39 El Salvador powers up

Alberto Osorio Liebana and Joel Schroeder, Invenergy, USA, outline how the first FSRU in El Salvador is contributing towards Central America’s energy transition.

43 The perfect synergy

Kym Winter-Dewhirst, Venice Energy, Australia, explores the promising future of LNG in Australia, detailing how combining renewables with LNG could create an ideal amalgamation.

45 Future fuels: a story of technical development

Mireille Franco, HSEQ and Technical Department at TotalEnergies Marine Fuels, France, details how technical developments in the LNG bunkering chain will play a pivotal role in enabling the transition to future marine fuel solutions.

MAY 2022

48 The ability to adapt

James Smith, Houlder, UK, details how infrastructure choices made today will determine how much flexibility LNG projects have to evolve over the long-term.

53 World Gas Conference 2022 preview

LNG Industry previews a selection of companies that will be exhibiting at this year’s World Gas Conference in Daegu, Korea, 23 - 27 May 2022.

59 Clean Canadian LNG

Scott Neufeld, FortisBC, Canada, outlines why the Tilbury LNG facility is so important for Canada’s energy industry, detailing how it differs from other LNG facilities.

63 Unlock the energy world

Karthik Sathyamoorthy, President LNG Terminals and Logistics, AG&P Group, Singapore, explores how transitioning to different energy sources, such as LNG, can help emerging economies advance by providing more stable and reliable power supplies.

67 Innovation in dehydration

Margaret Greene (USA) and Tobias Eckardt (Germany), BASF, and Patrick Peters and Javed Adam (Trinidad and Tobago), EG LNG, discuss how new materials and bed designs can solve molecular sieve degradation issues and increase LNG production.

73 The key is accuracy

Dr Matthew Hammond, EffecTech, UK, outlines the difficulties that come with measuring LNG, detailing how the calibration of spectroscopic instruments helps to make gas measurement more accurate.

77 The right tools for the job

Hans-Peter Visser, ASaP B.V., the Netherlands, considers how to measure and sample LNG in a cost-effective and accurate way to make sure every Btu counts.

83 Focus on fire safety

William Gielen, VIKING Life-saving Equipment, the Netherlands, discusses why investments in fire safety training and equipment are central to marine operations in the LNG industry.

86 A coat for all climates

Mads Raun Bertelsen, Hempel, Denmark, highlights the importance of utilising a versatile hull coating that keeps fouling at bay in all conditions, regardless of climate or geography.

ON THIS MONTH’S COVER

Beginning this year, Cheniere plans to provide Cargo Emissions Tags that quantify the estimated GHG emissions of its LNG cargoes.

The company believes enhanced data-driven emissions transparency will help everyone — Cheniere and its customers, suppliers, and other stakeholders — as the company works to identify tangible opportunities to quantify and improve environmental performance. www.cheniere.com/our-responsibility

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JAMES LITTLE MANAGING EDITOR

COMMENT T

hat LNG will play an even greater and more important role in the supply of energy in Europe and across the globe as a result of the conflict in Ukraine is a given. Hitherto, Russia has supplied 30 - 40% of Europe’s natural gas over the past five years. Following Russia’s aggression, the EU has asserted that it aims to reduce natural gas imports from Russia to zero by 2030, if not sooner. As Timera Energy makes clear in their article entitled, ‘A seismic shift’, which starts on page 18 of this issue, “Given the absence of other supply flexibility into Europe, a pivot away from Russia is effectively a pivot towards LNG”.

For LNG producers, this ‘pivot’ looks like good news and is a bullish signal to the LNG power houses of the US, Qatar, Australia, and others. Indeed, as Europe scrambles for new natural gas suppliers, the US is adapting to a new role as the world’s largest producer of LNG. Having produced 9.76 billion ft3/d in 2021, US LNG production is expected to reach 12.19 billion ft3/d in 2022 and 12.64 billion ft3/d in 2023. Quite some achievement from a standing start in 2016 when it first began exporting in earnest.

However, the International Group of Liquefied Gas Importers (GIIGNL) has crystallised their concerns about rising LNG prices in the light of the current global energy crisis in a public declaration issued 11 April 2022. GIIGNL states that “access to LNG is increasingly critical to energy security and emission reduction worldwide, including in emerging markets.

In this context, further facilitation and strengthening of LNG trade is paramount”. It goes on to call for market interventions from governments and public institutions to make permitting and construction of key LNG infrastructure easier to facilitate across the developed and developing world. “Without supportive policy and regulatory frameworks creating an adequate environment for LNG investments, many countries

Managing Editor

James Little james.little@palladianpublications.com

Assistant Editor

will be facing energy security issues or will be forced to burn more coal and oil, compromising the mitigation of climate change and the attainment of net zero ambitions”.

The Russia - Ukraine conflict has triggered a profound shift in energy policy in Europe and inevitably this will play out across the world. As Russia starts to ratchet up the pressure by cutting off natural gas supplies to Poland and Bulgaria, as seen in the past few days, the reality comes into even sharper focus. The LNG sector stands at the very forefront of the solution. However, current global LNG capacity is finite. New projects take years to come onstream as does shipping capacity. Action is required by governments to clear the way for LNG expansion worldwide or inevitably there will be a return to burning coal and oil – if not in Europe then in developing nations unable to afford escalating natural gas prices.

Alongside LNG, hydrogen is emerging as an important element of the global energy transition strategy. As such, I am delighted to announce the launch of our new publication, Global Hydrogen Review. This sits alongside our existing portfolio of leading energy publications (from upstream to downstream and coal and renewables) and is dedicated to the coverage of hydrogen production and its applications worldwide.

If you would like to receive a regular copy of Global Hydrogen Review, please sign up for a free subscription by visiting www.globalhydrogenreview. com/magazine (or by scanning the QR code on the right).

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Get on board

EemsEnergyTerminal Open for business

EemsEnergyTerminal, our new floating LNG-facility is expected to arrive in Eemshaven – located in the province of Groningen – this summer.

For further information about EemsEnergyTerminal visit: Eemsenergyterminal.com

Ready for use by customers this winter. In the long term, the terminal can be repurposed for green hydrogen storage.

COMMENT DR JOE M. KANG PRESIDENT OF THE INTERNATIONAL GAS UNION (IGU)

L

NG has been a critically important growing segment of the gas industry. It is also an integral cross-cutting building block in the IGU. LNG is in many ways a unifying force across our members who are engaged in all segments of the gas value chain across every continent, from the fundamentally important decarbonisation activities, upstream, transmission and distribution networks, low- and zero-carbon gases, and integration of renewable energy sources. It connects producers and customers, it links markets, and provides the level of flexibility that the gas sector could hardly imagine even a decade ago. Today, that flexibility is challenged by tight supply. We know that the industry is working hard to mitigate but it also needs a positive enabling policy environment.

LNG has been in the spotlight of global energy discussions at nearly all levels. The public has possibly never before been so acutely aware of the importance of gas and LNG in their lives.

The world is looking to the LNG sector to help address the energy crisis that we have been experiencing, but not only this.

As an industry, we are facing a defining moment.

Decision-makers around the world are grappling with the challenge of energy security and asking hard questions about the role that gas will play in this over the long-term. This is a pivotal time to determine the future of the gas and LNG sectors. It is up to us, as an industry, to demonstrate the verifiable environmental and economic value that gas provides, and the essential long-term contribution to the sustainable energy future and to the goals of the Paris Agreement. None of these propositions should be taken for granted.

Gas continues to be a necessary component for a sustainable, secure, and achievable energy transition, supplying one-quarter of the world’s energy. It plays a critical role in powering economies, enabling growing shares of renewable energies, reducing air pollution by replacing coal, oil, and traditional biomass across all sectors of the economy, and paving a way to decarbonisation through cleantech pathways, renewable

gas, hydrogen, and carbon capture. Breakthrough technologies in small scale LNG are unlocking new possibilities for gas to accelerate access to clean energy and work with renewables in remote communities, replacing highly polluting fuels. LNG infrastructure will be a backbone to global markets of renewable and carbon-free gases, including green hydrogen.

LNG-to-power will provide vital backing to the temporal intermittency of renewable energy.

I firmly believe that the industry needs to continue to demonstrate transparency and to clearly communicate the value of gas in a clean and reliable global energy system for this value to be understood, acknowledged, and accepted. At IGU, we have been raising the global voice of gas on the international stage to communicate these messages to decision-makers and the public.

We will continue to do so at the two upcoming IGU flagship events: the 28th World Gas Conference in Korea in May, and the 20 th International Conference and Exhibition on Liquefied Natural Gas – LNG2023 – mid next year. These global energy gatherings will act as global platforms to communicate the value of gas to the world. I would like to personally encourage readers and LNG industry leaders who have not yet registered for WGC2022 to attend, and to participate in the open LNG2023 Call for Papers.

At WGC2022, the biggest gas industry gathering in Korea, I invite you to contribute to the momentous discussions about the role of gas in the long-term energy future, through and beyond the current crisis. I ask that you propose bold ideas on how our industry can be a critical part of the solution, particularly when it comes to ensuring both energy and environmental security.

Now more than ever, we cannot afford to lose sight of the energy transition goals, amidst crisis. We need to join forces with the global community and provide them with solutions. The IGU is going to continue to be the voice of gas delivering these messages to the world, and we are here to listen to yours.

May 2022

5

CHENIERE

CARGO

EMISSIONS

TAGS

Coming to an LNG Vessel Near You In 2022, we plan to provide tags that quantify the estimated GHG emissions of our LNG cargoes. We believe enhanced data-driven emissions transparency will help us all — Cheniere and our customers, suppliers and other stakeholders — as we work to identify tangible opportunities to quantify and improve environmental performance.

www.cheniere.com

LNGNEWS USA India

GlobalData: India to lead Asia’s LNG regasification projects

A

sia is expected to lead the LNG regasification project starts among the regions globally from 2022 to 2026.

India is anticipated to be one of the primary countries to drive Asia’s LNG regasification projects count by 2026, contributing approximately 21% of project starts, says GlobalData.

The company's latest report, ‘LNG new-build and expansion projects analytics and forecast by project type, sector, countries, development stage, capacity, and cost, 2022 - 2026’, reveals that India leads the region with the 20 LNG regasification projects with a total capacity of 3.4 trillion ft3 between 2022 and 2026. In India, approximately 40% of the upcoming regasification projects are likely to be in the approval stage and expected to start operation from 2022 to 2026. Feasibility and construction follow with 35% and 20% respectively.

Sudarshini Ennelli, Oil and Gas Analyst at GlobalData, commented: “In India, 16 upcoming regasification [plants] would be new-build projects while the rest are expansion projects. Growing demand from both industrial sectors and [the] Indian government’s plans to increase gas share in [the] energy mix to reduce emissions are driving the natural gas demand in India.”

Kakinada GBS Floating is the largest upcoming regasification project in India, with 351 billion ft3 capacity. It is expected to be complete by 2024. It will be operated by Crown LNG, serving industrial consumers such as power and fertilizer plants in and around the Andhra Pradesh state.

TotalEnergies signs Cameron LNG expansion agreement

T

otalEnergies has signed a heads of agreement (HOA) with Sempra Infrastructure, Mitsui & Co Ltd, and Japan LNG Investment for the expansion of Cameron LNG, an LNG production and export facility located in Louisiana, US. This expansion project includes the development of a fourth train with a production capacity of 6.75 million tpy, and a 5% increase of the current 13.5 million tpy first three trains through debottlenecking. It will also include design enhancements aiming to reduce the emissions of the facility, including electric drive technology. Under the terms of the HOA, TotalEnergies will offtake 16.6% of the projected fourth train’s production capacity, and 25% of the projected debottlenecked capacity. Additionally, Cameron LNG advances the development of this project with the selection of two contractors to conduct a competitive FEED in view of the selection of the engineering, procurement, and construction (EPC) contractor.

“We are pleased to take this new step with our partners to increase liquefaction capacity at Cameron LNG, a facility ideally located on the Atlantic basin for export to Europe. In recent years, TotalEnergies has become a leading exporter of US LNG, most of which has been exported to Europe in recent times, contributing to the continent’s security of energy supply. TotalEnergies is committed to further expanding its presence in the US, thus meeting growing need for LNG, a key transition fuel,” said Patrick Pouyanné, Chairman and CEO of TotalEnergies. “The expansion of Cameron LNG will contribute to our LNG growth strategy by investing in low-cost, long-term competitive LNG projects with lower GHG emissions.”

Development of the project remains subject to definitive agreements, obtaining the necessary permits, and all partners reaching a final investment decision planned for 2023.

Republic of Congo

Eni and the Republic of Congo agree to increase gas production

I

n the presence of the Minister of Foreign Affairs of the Republic of Congo, Jean-Claude Gakosso, of the Italian Minister of Foreign Affairs, Luigi di Maio, and of the Italian Minister for Ecological Transition, Roberto Cingolani, the Minister of Hydrocarbons of the Republic of Congo, Bruno Jean Richard Itoua, and the CEO of Eni, Claudio Descalzi, signed a letter of intent (LOI) in Brazzaville, the Republic of Congo, to increase gas production and export.

Following the signature, a meeting was held with the President of

the Republic of Congo, Denis Sassou Nguesso.

The agreement provides for the acceleration and increase of gas production in the country, primarily through the development of an LNG project, with start-up expected in 2023 and with a capacity of over 3 million tpy (over 4.5 billion m3/y) once fully operational. LNG exports will allow the Republic of Congo to valorise the production of gas that exceeds the country’s internal market needs.

May 2022

7

LNGNEWS Antigua Malaysia

PETRONAS Marine and Titan LNG partner for STS LNG bunkering

T

itan LNG has partnered with PETRONAS Marine to deliver LNG under a term supply agreement to very large crude carrier (VLCC) Yuan Rui Yang, chartered by Koch Industries and owned by Costco. The ship-to-ship (STS) transfer bunkering of the world’s first LNG-fuelled VLCC took place in the port of Pasir Gudang, Malaysia, using the Avenir Advantage – PETRONAS’ long-term chartered barge.

Delivered in February 2022, the Yuan Rui Yang is the world’s first LNG-fuelled VLCC. The vessel is 333 m long, 60 m wide, and 30.5 m deep. It has a WinGD low-pressure, dual-fuel main engine, and two 3500 m3 LNG storage tanks.

This is the first delivery under contract agreement between Titan LNG and Koch Industries, and marks another milestone for the PETRONAS-Titan collaboration, which has previously supplied LNG across Asia to vessels including the Siem Aristotle and several other smaller vessels that were en route from Asia to Europe. This demonstrates Titan LNG and PETRONAS’ shared purpose to create a cleaner future.

Global access is now a reality as the LNG bunkering pioneers collaborate to deploy expertise worldwide. As the expansion of LNG infrastructure continues to build momentum in meeting cleaner energy demand, multiple players are coming together to ensure availability and supply, as well as technical assistance and compatibility.

Michael Schaap, Titan LNG’s Commercial Director Marine, commented: “We are proud of the strong and ongoing relationship with our supply partner, PETRONAS Marine, and the faith shown by our long-term customer, Koch Industries. As the LNG pathway gains recognition and momentum, taking a collaborative approach enables us to continue to deliver LNG safely across Europe, Asia, and around the world.

“Shipping companies, such as Costco and Koch, are becoming much more aware of how to meet the 2030 and 2050 decarbonisation targets and recognise that the use of LNG as a marine fuel has a multitude of benefits. Not only its negligible local emissions profile but its clear global emissions reduction pathway through the introduction of bioLNG and hydrogen-derived LNG. This is why Titan is committed to providing access to LNG, and all commercially viable alternative fuels, enabling more shipping companies to start the journey towards a zero-carbon future today.”

8

May 2022

INOXCVA wins terminal contract in Antigua

I

NOXCVA has been awarded a contract by Caribbean LNG Inc for the design, engineering, and supply on a turnkey basis for a MiniLNG receiving and regasification terminal to be set up in Antigua, West Indies. Caribbean LNG Inc is a joint venture between Eagle LNG Partners (Eagle LNG) and Antigua Power Company (APC). The terminal will provide natural gas for APC’s on-island 40 MW power plant. The terminal is expected to be a future template and anchor plant to service power and other energy requirements in the Eastern Caribbean Islands.

Speaking on the occasion, Mr Vijay Kalaria, Global Head LNG at INOXCVA, said: “We are excited and honoured to have been given this opportunity to set up this prestigious MiniLNG terminal with vacuum insulated storage tanks and a regasification system to feed the gas-based power plant. Caribbean LNG’s terminal will be capable of receiving LNG through smaller ships while provisioning for LNG distribution and ship bunkering in the future. Our innovative design and modularised concept will ensure minimum site activity and enable faster implementation of the project. All major critical equipment to be installed in the MiniLNG terminal will be manufactured in INOXCVA’s state-of-the-art manufacturing facility in Kandla, India.”

This project comes soon after the successful commissioning and operations of a similar multifunctional MiniLNG terminal set up by INOXCVA in Scotland.

THE LNG ROUNDUP XX Woodfibre LNG issues notice to proceed to McDermott International XX Gasum to distribute LNG in Belgium XX Saipem awarded maintenance services contract Follow us on LinkedIn to read more about the articles

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LNGNEWS Germany Poland

PGNiG signs charter contract for four LNG carriers

P

GNiG Supply & Trading (PST), part of PGNiG Group, has signed charters for four more LNG carriers. Two will be delivered by companies of the Norwegian Knutsen Group and the other two by affiliates of Maran Gas Maritime, the LNG arm of Angelicoussis Group.

Similarly to the LNG carriers previously ordered by PGNiG, each of the new vessels will have tanks with a capacity of approximately 174 000 m3, which means they will be able to carry cargoes equivalent to approximately 100 million m3 of regasified LNG. PST will use them for a period of 10 years on an exclusive basis, with an extension option. As under the previous charter contracts, the shipowner will be responsible for delivering, manning, and keeping the vessels in good technical condition, whereas commercial control will lie with PST. Adding the previously chartered carriers, PGNiG Group’s new LNG fleet will consist of eight vessels. The first two LNG carriers will start to operate next year.

In early 2023, the Lech Kaczynski will begin its first journey. The making of its hull in a dry dock is currently nearing completion. Most sections of the vessel have already been fabricated and put together. Reinforcing, metalwork, and outfitting have begun. In March, the propellers and the main and auxiliary engines were installed. The making of individual parts of the hull of the Gražyna Gesicka has also begun. The outfitting of individual blocks, which will later be assembled in a dry dock, is underway. The main and auxiliary engines have been tested in the manufacturers’ workshops.

T

ree Energy Solutions (TES) has announced an open season to fast-track LNG imports into Europe through its Wilhelmshaven regasification terminal.

Commencing on 25 April 2022, the open season is accessible to all parties seeking to import LNG in the drive to reduce the EU's and Germany's energy dependence on Russia.

Parties are invited to submit an expression of interest to reserve capacity and services for the import of LNG volumes.

TES is planning for initial capacity to import up to 16 - 20 billion m3/y from 2025 onwards. The terminal will be connected through the new OGE 42 in. pipeline with the European high-pressure gas grid. Terminal and pipeline capacity may be further expanded through the integration of further LNG tanks and commissioning of a second export pipeline. The expansion's timing and size will be determined by market demand for LNG imports from 2025 onwards, as well as the planned transition to green and clean, hydrogen-based gas.

The open season will cover three phases: non-binding application expression of interest, binding application window, and closing of binding window, offering market participants an important opportunity to secure future capacity in the Wilhelmshaven Green Energy Hub. The Wilhelmshaven terminal layout will ultimately comprise six ship berths, 1 600 000 m3 of onshore storage capacity using eight onsite tanks, of which four will be available during the initial stage. The terminal will offer direct access to an extensive gas pipeline network, including existing salt caverns in Etzel, Germany, and proximity to the Groningen gas grid infrastructure in the Netherlands.

23 - 25 May 2022

23 - 27 May 2022

06 - 10 June 2022

Rotterdam, Netherlands

Daegu, Korea

Athens, Greece

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Houston, US

Gastech Exhibition and Conference 2022

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TES announces open season

May 2022

World Gas Conference 2022

Posidonia 2022

Turbomachinery and Pump Symposia 2022

Laura Page, Kpler, UK, explores how the emerging LNG markets in the Philippines, Vietnam, and Hong Kong are gearing up to start imports, how high prices could impact future demand, and outlines the sustainable benefits of LNG.

T

he Philippines, Vietnam, and Hong Kong are poised to enter the LNG market for the first time this year, with all three countries making final preparations to their first LNG import terminals. Hong Kong is set to bring one terminal online, two could start operations in Vietnam this year, while as many as five terminals are targeting first operations in the Philippines. As much as 30 million tpy of LNG import capacity could be installed in these three countries by the end of the year, although some facilities could face delays.

The three countries will join many existing LNG regasification markets in South and Southeast Asia, namely India, Pakistan, Bangladesh, Thailand, Singapore, Indonesia, Malaysia, and Myanmar. According to LNG flow data from Kpler, the region imported 48 million t of LNG last year and accounted for approximately 13% of global LNG demand.

While import volumes flattened out in 2021 due to high and volatile LNG spot prices, new entrants are expected to bring a resumption to LNG demand growth over the coming years.

Alongside China, South and Southeast Asia were set to offer very promising demand growth prospects over the next two decades amid rapid growth in energy demand, government targets to transition away from burning coal, and falling domestic gas production in the case of the Philippines and Vietnam. However, these countries are entering the market at a time of record high LNG prices, which poses a major threat to the pace of LNG demand growth going forward.

In this article, Kpler examines the drivers behind the move towards the international LNG market, and what impact high prices could have on future demand prospects.

12

13

Declining domestic production drives LNG capacity build-out in the Philippines

The Philippines will become increasingly reliant on LNG imports this decade amid diminishing reserves at the country’s only commercially operational gas field, Malampaya. The deep-water development started commercial operations in 2001, off the coast of Palawan, and has produced between 3 - 4 billion m3/y of gas since 2004. Malampaya is critical to the country’s energy needs and provides up to 20% of the country’s power supply, according to the Environmental Investigation Agency (EIA). But production from the field is set to start declining from this year and the field is at risk of running dry by 2027. With no immediate alternative sources of domestic supply, and power plants in desperate need of finding a replacement fuel source, LNG supplies will be critical to backfilling production from Malampaya.

Imported LNG will also be crucial to meeting the country’s growing power sector demand, particularly so after a moratorium on new coal-fired power plant developments was issued in October 2020. Coal-fired power accounted for approximately 57% of the country’s power supply in 2020, followed by renewables at 21% and gas at 19%. By 2030, gas is set to contribute towards 40% of power generation capacity, followed by renewables at 35% and coal at 25%. Installed capacity is anticipated to more than double from 26 GW in 2020 to 55 GW by 2030, according to the Philippine Energy Plan (PEP) 2020 - 2040.

To date, six LNG import terminals with a total capacity to import 22 million tpy of LNG have been issued with notices to proceed (NTP) by the Philippines’ energy department. A seventh facility, developed by Batangas Clean Energy, also received

Figure 1. LNG imports into South and Southeast Asia, million t.

Source: Kpler.

approval but never reached the construction stage due to financing problems. All six import terminals are set to provide regasified LNG to new and existing power plants.

Five out of six LNG regasification facilities are targeting to start operations this year, while the final terminal is targeting a start-up date of early 2023. Excelerate Energy expects its 5 million tpy project at Batangas Bay, to start as early as 2Q22.

Singapore-based Atlantic, Gulf & Pacific International Holdings (AG&P) said in February that its 3 million tpy terminal is expected to be commissioned on 1 July and will start commercial operations soon after. This could be followed by Philippine power producer First Gen and Tokyo Gas’ 5.3 million tpy project in September. Shell and EWC’s 3 million tpy projects are also targeting commissioning this year, though EWC’s project could be at risk of slipping. The LNG-to-power project at Pagbilao, has faced a number of delays in recent years due to funding concerns, regulatory hold-ups, and delays to gaining approval to connect to the power grid.

Hong Kong eyes LNG as key to decarbonisation targets

Hong Kong’s entry into the LNG market is being driven by a transition from coal to gas in the power sector in order to achieve the carbon emission targets outlined in the Climate Action Plan 2030+ report published in 2017. According to the report, electricity generation makes up 70% of overall carbon emissions in Hong Kong, so credible steps to reduce emissions in the power sector will go a long way to achieving net zero by 2050.

In 2020, coal accounted for approximately 25% of the generation mix in Hong Kong, while gas made up 50% and non-fossil fuel sources the remainder. Investment in coal-fired power capacity ceased following a moratorium in 1997, and over the next decade, coal-fired power facilities will gradually be phased out as they reach end of life. In October, Hong Kong committed to phasing out the use of coal for power generation by 2035. Coal will increasingly be replaced by gas and renewable generating capacity.

Importing LNG is now in touching distance, with the first regasification terminal set to start operations in the middle of this year. The 4 million tpy terminal will utilise the world’s largest FSRU – the 263 000 m3 MOL FSRU Challenger, which will be renamed Bauhinia Spirit. The terminal is being developed by the country’s two power utilities – Castle Peak Power Co (CAPCO) and The Hongkong Electric Company.

Regasified LNG will supply expanding gas-fired power generating capacity at CAPCO’s Black Point power plant in the New Territories and Hong Kong Electric’s Lamma power plant on Lamma Island.

Gas demand from the power, industrial, and fertilizer sectors grow in Vietnam

Figure 2. Global gas prices, five-day moving averages, US$/million Btu. Source: Nymex.

14

May 2022

A combination of growing electricity demand and uncertainty in domestic gas production has driven Vietnam towards the LNG market in recent years.

According to Vietnam’s Minister of Industry and Trade, Nguyen Hong Dien, Vietnam deems LNG “one of the most important solutions” to ensuring its energy security amid declining domestic gas production and

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Table 1. Key LNG import terminal projects under construction in the Phillippines Main developer

Location

Import capacity Type (million tpy)

Target start-up date

High LNG prices could stifle LNG demand prospects and delay coal exit

The Philippines, Vietnam, and Hong Kong are entering the LNG market at a time of high LNG prices. In under two years, LNG AG&P Batangas Bay 3 FSRU 2022 prices in Europe and Asia have risen from record lows of US$2/million Btu in the First Gen Corp/Tokyo Gas Batangas Bay 5.3 FSRU 2022 LNG glut of summer of 2020 to record highs of more than US$50/million Btu this Shell Batangas Bay 3 FSRU 2022 winter.

The upward trend began last summer Energy World Pagbilao 3 Onshore 2022 when global LNG supply failed to keep Corporation pace with rising gas demand, owing to the reopening of economies after the COVID-19 Vires Energy Batangas Bay 3 FSRU 2023 pandemic and low hydropower generation in South America. This led to Europe, Asia, and South America all competing for Table 2. Key LNG import terminal projects under construction in Vietnam limited LNG supplies and fuelling price Import capacity Target start-up rises across the world. This winter, Developer Location Type (million tpy) date European TTF gas prices have been Hai Linh Corporation Ba Rja-Vung Tau 2 - 3 Onshore 2022 supported by supply uncertainties from Russia and low storage levels in the region.

PV Gas (Thi Vai) Ba Rja-Vung Tau 1 Onshore 2022 Whilst contractual LNG prices remain at a significant discount to spot, rising oil prices are feeding through into oil-linked contract robust economic growth. Gas demand is also growing from the prices and will continue to do so over the coming months. industrial and fertilizer sectors.

High prices have already started to hit LNG demand in Sentiment towards coal-fired power is starting to shift in traditional import markets in South and Southeast Asia, such as Vietnam, with the country making a surprise commitment to stop India, which accounts for half of the region’s LNG consumption. building new coal-fired power plants at the COP26 climate After consistently growing LNG purchases since 2013, imports summit in November 2021. Vietnam was a full signatory to a into the country plummeted by 8% last year to 24 million t as UK-backed pledge calling for countries to stop permitting and high market prices have all but wiped out the country’s spot building new coal power plants, and to fully transition away from demand, while investment in upstream gas production has the fuel by the 2040s. ramped up. India has a long-term ambition to widen the share of But a number of revisions to the Power Development 8 plan gas in its energy mix from 6% in 2021 to 15% by 2030. The gas since it was first published in March 2021 show that the country penetration targets are at risk of being reviewed if LNG prices could still rely heavily on coal by the end of this decade. remain high and uncompetitive against alternative fuels.

Coal-fired power accounted for 53% of power generation in 2020.

According to Shell’s 2022 Outlook, Southeast Asia is expected The government is targeting coal’s share in the power mix to fall to add nearly 100 million t of incremental LNG demand growth to 31% by 2030. But when factoring in that installed capacity is between 2020 and 2040, followed by South Asia at over projected to rise from 70 GW in 2020 to as much as 144 GW by 85 million t and China at 65 million t. But high and volatile 2030, coal-fired power capacity will in fact rise. Natural gas made global gas prices are prompting questions over the role of gas in up just 16% of the power mix in 2020 and will rise to 21 - 22% the future energy mix. Asian utilities have been reverting to by 2030, while hydropower and renewables will make up the burning dirtier coal and fuel oil in the power sector, meanwhile, remainder. future plans are also being impacted. Vietnam’s revised Power Construction of Vietnam’s first LNG import terminal by Development 8 plan, released in October, boosted coal-fired private company Hai Linh Corporation was completed in power capacity targets for 2030, reduced renewables’ share of June 2020. The 2 - 3 million tpy facility has yet to start the power mix, and slashed the number of proposed importing LNG, however, amid delays to testing and gas-to-power projects to be developed by the end of the decade commissioning. The facility could come online this year, by approximately 40%. followed by PetroVietnam Gas’ 1 million tpy Thi Vai onshore With market balances set to remain tight until at least 2025, LNG terminal in 2H22. The Thi Vai terminal will have the there is little price relief in sight. This is a key risk for emerging capacity to import 1 million tpy but can be expanded to markets such as Vietnam and the Philippines, which have relied 3 million tpy in the second development phase of the project. on cheap coal up until now. While significant LNG import PV Gas will supply approximately 70% of the regasified capacity is due to come online this year, import projects, which LNG-to-power plants, as well as the petrochemical and are more exposed to spot market prices, could limit their LNG industrial sectors. A number of other import terminals have purchases in this high price environment, while investments in been proposed, including PV Gas and AES’ 3.6 million tpy future LNG-to-power capacity could be scaled back. This could Son My terminal in Binh Thuan province which could start have damaging consequences for the energy transition and commercial operations in 2026. climate change goals.

Excelerate Energy

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May 2022

Batangas Bay

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FSRU

2022

David Stokes, Olly Spinks, and David Duncan, Timera Energy, UK, unpack the effects of the Russia - Ukraine conflict in triggering a new LNG market regime and set out its implications for LNG portfolio value and risk.

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T

he Russia – Ukraine conflict has just triggered the most profound shift in European energy policy history. Russia has accounted for 30 - 40% of the European gas supply mix across the last five years, as shown in Figure 1. The EU has just announced its ambition to reduce this to zero by 2030, with political pressure mounting to accelerate this to 2027.

Achievable or not, these policy targets reflect a 180˚ handbrake turn away from Russian gas. Given the absence of other supply flexibility into Europe, a pivot away from Russia is effectively a pivot towards LNG. And Europe’s appetite for LNG has already triggered structural changes in market pricing, contracting, and flow dynamics.

A new LNG market regime has begun where Europe is dynamically competing for all available LNG supply. Europe’s role in the LNG market is transitioning from being a passive and flexible sink for global LNG oversupply (as seen in 2019 - 2020), to a direct and aggressive competitor for LNG against other markets, particularly Asia.

Competition for marginal cargoes is set to manifest itself in the death of the structural premium of JKM prices over TTF. Instead, expect to see a more dynamic TTF vs. JKM spread relationship as the price signal to balance the LNG market across the Atlantic and Pacific basins. At the same time, liquidity for financially settled contracts has sharply deteriorated due to large increases in collateral requirements to support trading. Both these factors are driving up price levels and price volatility.

Timera Energy is already seeing in its work with large LNG portfolios that the new market regime and associated pricing dynamics are having profound implications for portfolio value and risk.

Europe’s changing role driving regime shift

The European gas market has driven global LNG market pricing across most of the last decade. This is a direct result of Europe’s role in providing price responsive volume flexibility, allowing the global LNG market supply and demand balance to clear.

The three factors that enable European gas market flexibility provision to the LNG market are: � Switching between gas and coal plants across European power markets. � Large volumes of underground gas storage (vs. relatively low capacity in Asia).

� Significant annual and daily flexibility in pipeline supply contracts (ACQ/DCQ), dominated by Russian volumes.

These sources of flexibility have been important drivers of marginal pricing at TTF, which in turn has anchored global LNG market pricing e.g., driving Asia’s benchmark JKM price marker.

This flexibility has allowed Europe to act as both a ‘sink’ during times of surplus LNG in Asia (e.g., 4Q18 - 2Q20 slump) and a ‘tap’ during periods of strong Asian LNG demand, via cargo diversion flexibility (e.g., 2Q20 - 4Q20 COVID-19 recovery).

Under the new LNG market regime, Europe’s ability to provide flexibility is becoming structurally inhibited.

Inhibited European flexibility drives higher volatility Two of the three major sources of European flex listed previously are currently inhibited.

Power sector switching, the first and most important source of flex, has been inhibited by market pricing dynamics.

Very high gas prices mean Europe’s power sector is effectively fully switched (i.e., coal plants are running at maximum output). This is illustrated in Figure 2 with the TTF forward curve (green dashed line) well above coal and lignite switching ranges until at least 2025.

The second source of inhibited flexibility is gas storage.

New government storage volume mandates across Europe to target security of supply are reducing the commercial flexibility of storage sites to respond to market price signals.

Somewhat ironically, Russian long-term gas contracts are the only major source of supply flexibility that have not so far been significantly inhibited. This of course could change if any Russian flow interruptions occur due to the current conflict.

Could European price responsive flexibility return if the impacts of the Russian conflict ease? This looks increasingly unlikely given current events are just accelerating what is a structural decline in traditional sources of European gas market flexibility.

For example, the European coal fleet is set to be largely closed by 2030, substantially reducing power switching potential. Russian supply flex will decline as supply volumes fall and storage mandate constraints are likely to remain.

From an LNG market pricing perspective, the closure of Europe’s coal fleet is the most important of these factors.

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Power switching ranges have anchored TTF and in turn LNG spot markers (e.g. JKM) since the middle of the last decade.

As gas market flexibility erodes under this new market regime, Europe is transitioning from a more passive role as a swing market, to directly compete with other markets in Asia and Latin America for available LNG.

What drives LNG market flexibility and pricing under the new regime?

The erosion of European gas market flexibility, particularly from power sector switching, is set to increase the importance of other price responsive demand sources across the LNG market. This includes gas intensive industry in Europe (e.g. ammonia production), and power sector switching and industrial response in Asia.

Marginal price setting via these demand sources is not going to be as smooth as European power sector switching

has been. Power sector switching is both price responsive (given liquid price signals) and granular (given switching across hundreds of gas and coal plants).

Industrial demand response and Asian power switching are much less responsive and granular. It can take weeks to months for Asian power switching to respond in scale. Asian industrial response is also lumpy, limited in flexibility, and can have significant lead times.

This new regime is not just about higher prices as Europe competes with Asia and Latin America for available LNG. It is also set to be characterised by higher price volatility and changing price correlations between TTF and JKM as can already be seen in Figure 3. Correlations with Brent crude have also been significantly impacted.

Under the new regime, the erosion of European market flexibility structurally underpins higher LNG price volatility, as less responsive demand sources set marginal prices. Volatility has been compounded by high collateral requirements driving poor market liquidity.

Five impacts of the new regime on market drivers are summarised in Table 1.

Implications of new regime for LNG portfolios

Figure 1. LNG vs. Russian gas in Europe’s supply mix.

Source: Timera Energy, ENTSOG.

Figure 2. European power sector flex is ‘switched out’.

Source: Timera Energy, CME.

The new market regime has come upon LNG portfolios like a freight train out of a tunnel, with key implications for portfolio value and risk.

Figure 4 summarises four key challenges companies are facing in managing LNG portfolios.

Portfolio construction

Market events in 2022 are triggering LNG companies to undertake major portfolio strategy reviews. These are covering value impact on existing portfolios as well as value creation and growth opportunities. Europe is a big focus.

There is a ‘molecules’ challenge of sourcing adequate supply. This is triggering a new wave of contracting e.g., buying US and Qatari volumes, particularly from European and portfolio buyers looking to backfill Russian supply exposure.

The structure and valuation of supply flexibility is important e.g., the advantage of US supply given diversion flexibility to deliver into both European and Asian markets.

There is a ‘capacity’ challenge focused on access to regas and shipping. Constraints on access to European regas capacity are driving up value with new capacity being marketed as Europe scrambles to secure FSRUs to allow greater LNG import flow. Portfolios are also re-evaluating shipping requirements given structural changes in cargo flows.

There is also a ‘pricing’ challenge given structurally shifting correlations between TTF, JKM, and Brent. The new regime looks set to accelerate penetration of hub indexation of contracts and growth of derivative and hedging products.

Value management

Figure 3. Regime shift illustrated via JKM vs. TTF price spread volatility. Source: Timera Energy, CME, ICE.

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May 2022

High prices, extreme volatility, and rapidly changing price correlations are driving seismic value shocks and unprecedented portfolio value management challenges. This is compounded by poor market liquidity given collateral and funding constraints.

To illustrate the impact of regime change on portfolio value, Timera Energy has quantified the value distribution of a case study LNG portfolio in its ‘LNG Bridge’ portfolio valuation model under old and new regime pricing dynamics. The portfolio

contains US export tolling contract, Australian crude indexed supply, regas capacity, and Asian sales contracts.

Table 1. Five market impacts of new regime Market drivers

Summary

High prices

Prices elevated as Europe and Asia compete for available supply.

High price volatility Inhibited European market flexibility provision drives up price volatility.

Changing price correlations

More dynamic TTF vs. JKM pricing correlation; shifting in gas vs. Brent relationship.

High charter rate volatility

Charter rates buffeted by more dynamic flows between Atlantic and Pacific basins (Europe competing with Asia).

Hub price penetration

New wave of supply and growth in role of mid-market players to accelerate hub price penetration (i.e. TTF/JKM vs. Brent indexation).

Figure 4. Four key LNG portfolio management activities.

Source: Timera Energy.

Figure 5 illustrates the impact of a substantial increase in portfolio value under new regime conditions, given the case study portfolio is net long both supply and flexibility. However, there is also a substantial increase in portfolio risk i.e., value distribution has widened.

High levels of volatility and market liquidity constraints make it increasingly important to dynamically manage and value interdependent exposures across a portfolio. For example, spot cargo liquidity has recently increased as some companies have unwound positions ahead of delivery to reduce exchange margin costs.

Basis exposures across LNG portfolios are also becoming more important to manage. For example, DES NW European spot prices (historically closely anchored by European hub prices) have been trading at a steep and volatile discount to TTF given regas access constraints in Europe.

These challenges are seeing LNG companies invest in both people and analytical capabilities to address challenges in quantifying and managing portfolio value.

Risk management

Risk management challenges under the new regime are closely related to the value management issues mentioned previously.

Portfolio risk has surged with rising prices and volatility.

This is also uncovering issues that require the adaptation of conventional ‘at risk’ metrics such as value at risk (VaR) and earnings at risk (EaR).

Risk quantification and risk management need to be underpinned by a robust portfolio valuation modelling capability that effectively captures complex portfolio exposure interdependencies. These include, for example, the impact of changing price correlations, capture of basis risks, and the effective quantification of sold flexibility in supply contracts.

Management of collateral and funding is also key. Very large increases in margin and collateral requirements are impacting LNG company liquidity positions and ability to transact. New products are emerging to help manage funding issues e.g., liquidity swaps that allow cargo title transfer to banks or hedge funds.

Under the old regime these were secondary issues. In the new regime they are constraining the ability of LNG portfolios to manage and hedge exposures, with major implications for balance sheet and capital management.

Portfolio optimisation

Figure 5. Case study: impact of new vs. old regime on portfolio

value distribution. Chart background: portfolio comprises ACQ of 1.3 million tpy US supply, 0.8 million tpy Australia supply, 1.4 million tpy NE Asia sale, 1.2 million tpy combined regas and DES sales into Europe modelled across a five year horizon. Analysis is undertaken in Timera Energy’s ‘LNG Bridge’ stochastic portfolio valuation analysis model. For each of the new and old regime scenarios, the company has simulated hundreds of price paths consistent with price behaviour (e.g., volatility/correlations) under each regime. For each simulation the company optimises the portfolio to generate a distribution of value outcomes.

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May 2022

Regime change is also seeing a greater proportion of value monetised via portfolio optimisation within the annual delivery programme (ADP) horizon. This is the result of market volatility and correlations driving more dynamic flow patterns e.g., the sharp inversion of the JKM vs. TTF price spread across 1Q22.

Spot cargo trading is increasing as portfolios dynamically reoptimise and manage exposures in rapidly changing market conditions. The new regime also looks set to drive increasing liquidity in the short-term charter market.

Portfolio value capture is underpinned by effective portfolio construction, value management, and risk management.

But portfolio optimisation is where a significant portion of value is monetised. Effective value capture depends on the ability to quickly identify, prioritise, and act on opportunities.

The 2022 Power Play Awards are finally here!

This year, the Power Play Awards will mark ExxonMobil LNG’s fourth year supporting inclusion and diversity by connecting and celebrating women and men across the LNG industry. The key objective behind these awards is to recognize and celebrate the accomplishments of remarkable women and men who uphold the importance of supporting and empowering others in the workplace by demonstrating how a mutually supportive environment can help support great business outcomes across all parts of the LNG value chain.

To help celebrate these leaders, we invite you to nominate the individuals you believe are worthy of a Power Play Award:

The Rising Star – Outstanding Young Professional The Ambassador – Outstanding Leadership The Pioneer – Outstanding Business, Innovation and/or Technology Contribution

Learn more at www.exxonmobillng.com/Power-Play/Power-Play-Awards

LNG

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Tim Wyatt, Cheniere, USA, details how the lifecycle emissions of an LNG cargo can be more accurately estimated, and how the absence of transparent, credible data in this area is being addressed.

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lobal demand for LNG is increasing as the world prioritises lower greenhouse gas (GHG) emissions intensity sources of energy. In 2020, global LNG demand was 356 million t or 484 billion m3 of natural gas equivalent.1 By 2040, Cheniere estimates that LNG demand could reach approximately 670 million t or 910 billion m3 of natural gas equivalent.

In 2019, the International Energy Agency estimated that natural gas accounted for 500 million t of carbon dioxide equivalent (CO2-eq) reductions primarily due to coal to natural gas switching.2 The US Energy Information Administration attributed 65% of the decline in CO2 emissions from 2005 to 2019 in the US power sector to coal-to-gas switching, driving the observed reduction in power sector emissions intensity.3 This is driven by the lower GHG intensity of natural gas relative to other fossil fuels, particularly coal. Cheniere estimates that one cargo of Cheniere-produced LNG delivered to China has a 47 - 57% lower cradle-through-power generation GHG emissions intensity than an equivalent amount of coal-fired electricity.4 Claims about the GHG footprint of LNG must rely on credible and transparent data. Estimates of the climate benefits of natural gas and LNG are dependent on accurate, high-quality, and credible accounting of supply chain emissions. Absent of this transparency, natural gas consumers must rely on outdated and perhaps unrepresentative assumptions, such as national averages, to estimate the emissions intensity of their natural gas supplies.

Estimating LNG cargo lifecycle emissions

To help address this gap, in 2022 Cheniere will start to provide Cargo Emissions Tags (CE Tags) to its customers. These first-of-their-kind CE Tags will include Cheniere’s estimate of lifecycle emissions associated with the production and delivery of that LNG cargo. CE Tags will cover the entire Cheniere natural gas value chain including production, gathering and boosting, processing, transmission, storage, and liquefaction. The CE Tag presents GHG emissions intensity in units of CO2-eq, which equates the warming impacts of CO2, methane (CH4), and nitrous oxide (N2O). CE Tags for cargoes sold free onboard (FOB) at Cheniere’s Sabine Pass liquefaction (SPL) and Corpus Christi liquefaction (CCL) facilities will provide emissions estimates for LNG in terms of t CO2-eq/t of LNG loaded onto the vessel.

The CE Tags for cargoes that Cheniere delivers ex-ship will also cover shipping.

The company charters a fleet of LNG vessels and delivers LNG cargoes

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ex-ship to regasification facilities around the world. For those ex-ship cargoes, Cheniere will provide an emissions estimate in units of t CO2-eq/t of LNG delivered, which includes emissions to account for the shipping fuel consumed in the delivery of the cargo.

Lifecycle analysis framework

The CE Tag estimates of lifecycle emissions will utilise Cheniere’s published, peer-reviewed, supplier-specific lifecycle analysis (LCA) framework.4 The Cheniere LCA is built off the US National Energy Technology Laboratory (NETL) framework and is updated to account for the latest science and customised to Cheniere’s supply chain. This improves the quantification and transparency of GHG emissions for LNG supply chains and identifies areas to improve GHG emission performance. The Cheniere LCA framework makes the following key improvements to other publicly available models: zz Employs supplier-specific emission data and Cheniere’s purchasing data to model the supply chain. zz Uses specific emission and operations data at SPL and CCL to characterise the liquefaction profile. zz For LNG cargoes delivered by Cheniere ex-ship, it estimates shipping emissions using actual vessel performance and fuel consumptions or measured emissions.

The framework utilises emissions data from Cheniere’s upstream producers, midstream operators, liquefaction facilities, and shipping operations. The key primary data sources are shipping operations data and the robust and transparent regulatory reporting of GHG emissions data to the GHGRP. The company will continue to refine and enhance the LCA over time

Figure 1. Cheniere’s Sabine Pass liquefaction (SPL) facility in February 2022.

as it further collaborates with natural gas suppliers, midstream companies, and ship owners to quantify, monitor, report, and verify (QMRV) the GHG emissions profile across its supply chain.

Cheniere’s ongoing collaboration with natural gas producers, midstream operators, and academic institutions to implement pilot QMRV projects will support the LCA and CE Tags, in addition to assessing the scalability and efficacy of a robust QMRV programme and monitoring technologies to verify GHG emissions at a range of industry sites.

The Cheniere LCA’s supplier-specific and voyage-specific methodological framework recognises the variability of GHG emissions in the LNG supply chain and the contribution of previously under-emphasised drivers of emissions intensity, such as producer variability and shipping engine-propulsion technology. The Collaboratory to Advance Methane Science (CAMS), which was co-founded by Cheniere, successfully conducted a first-of-its-kind study in 2021 to directly measure the methane emissions of a live LNG voyage. This study supports Cheniere’s LCA and CE Tags and provides critical data-driven insights into the GHG profile of LNG vessels to identify opportunities to improve environmental performance.

Cheniere believes that the demand for credible GHG emissions data is increasing, and products such as its CE Tags will become essential for all stakeholders. Credible GHG emissions accounting can enable new commercial products.

Customers interested in purchasing low-emission natural gas will need credible data to differentiate natural gas supplies. The LNG market has also signalled interest in carbon neutral LNG cargoes, of which more than 36 cargoes of assorted types have been sold.5 Carbon neutral claims, however, are predicated on accurate estimates of lifecycle GHG emissions associated with the LNG production and delivery. Information products such as Cheniere’s CE Tags will be a necessary prerequisite to credible carbon offsetting.

Although Cheniere believes its CE Tags will be a significant improvement in the quality and transparency of emissions data for LNG and US natural gas, the company is still committed to improving the quality of analysis supporting its CE Tags.

Through its QMRV R&D programme, the company is investigating credible methods to more accurately estimate total upstream GHG emissions while providing that data on a more granular timescale.

Cheniere published its LCA framework because it is committed to transparency. As part of this commitment, Cheniere is collaborating with its supply chain to better characterise US natural gas GHG emissions. CE Tags will be an important step for the company as it shares its best understanding of US LNG GHG emissions and works with its customers, suppliers, governments, investors, and stakeholders to increase the accuracy of the understanding of the GHG footprint of its LNG.

References 1.

GIIGNL, ‘The LNG Industry: GIIGNL Annual Report’, (November 2021).

2.

IEA, ‘The Role of Gas in Today’s Energy Transitions’, (July 2019).

3.

EIA, ‘Electric power sector CO2 emissions drop as generation mix shifts from coal to natural gas’, (June 2021).

4.

ROMAN-WHITE, S. A., et al., ‘LNG Supply Chains: A SupplierSpecific Life-Cycle Assessment for Improved Emission Accounting’, ACS Sustainable Chem. Eng., Vol 9, No.42, pp.

10857 - 10867 (August 2021).

5.

FGE, ‘LNG Market Snapshots’, presentation to Cheniere Energy, (February 2022).

Figure 2. A SeekOps sensor flies over a Cheniere compressor station in March 2022 as part of Cheniere’s midstream QMRV programme.

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May 2022

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A

s the world contemplates a cleaner and more sustainable future, decarbonisation of energy systems and value chains have been thrown into the spotlight. From net zero pledges to advancements in technology such as carbon capture, and exploration of new energies such as hydrogen, energy players have stepped up to field the rising pressure to address greenhouse gas (GHG) emissions from a variety of energy products.

Natural gas has long been touted as the cleanest burning fossil fuel, producing half as much CO2 as coal when burned. However, its fossil fuel status – and the fact that it accounts for approximately one-quarter of worldwide energy consumed – has not excluded it from increasing scrutiny on the GHG emissions it produces.1 Each LNG cargo produces an estimated 250 000 t of CO2 equivalent factoring upstream production, liquefaction, shipping, regasification, and combustion (Figure 2).2 Amidst these considerations and a recognition of the key role natural gas has to play in the energy transition and beyond, carbon-neutral LNG has gained significant traction in recent times. Supported by the notion of a GHG accounting framework, GHG emissions from LNG cargoes are neutralised based on the ability to offset corresponding emissions through supporting abatement projects. In 2021 alone, the industry witnessed more carbon-neutral LNG shipments than 2019 and 2020 combined.3 While carbon-neutral LNG is one of the tools available to abate GHG emissions from

Rogier Beaumont, Head of Atlantic LNG Origination and Global Environmental Solutions, Pavilion Energy, Singapore, outlines how a greenhouse gas methodology for delivered LNG cargoes paves the way towards a carbon-neutral LNG world.

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LNG cargoes, it should not give the industry an excuse to pollute.

Carbon offsets cannot substitute for actual emissions reduction – and neither should it be the first or only solution. On the contrary, knowing exactly the GHG content of each LNG cargo creates necessary transparency and drives decisions to reduce emissions, such as switching from more carbon-intensive fuel sources, such as coal and oil, to cleaner sources of energy.

Hard-to-abate emissions can then be carbon-neutralised through

high quality offsets, which offers a way for companies to support verified GHG restoration projects around the world while decarbonising along the value chain.

Addressing the challenge: no standardised, transparent GHG methodology for LNG

More than 30 carbon-neutral LNG cargoes have been traded since 2019,4 of which most have used global estimations instead of actual data in their calculation of GHG emissions.

This has raised the question on accuracy of the GHG footprint determined for delivered LNG cargoes. The lack of transparency behind these methodologies significantly challenges the credibility of carbon-neutral LNG. Having no consensus on a transparent and standardised GHG accounting framework or parameters of value chain emissions further clouds a future where carbon-neutral LNG is expected to become the norm. With that in mind, Pavilion Energy, together with its partners, QatarEnergy and Chevron, set out to develop a GHG methodology for delivered LNG cargoes. Key to this requirement was data transparency and accuracy: the outcome of the methodology, or any model for that matter, would only be as good as the data available.

Figure 1. Pavilion Energy imported Singapore’s first carbon-neutral LNG cargo in April 2021.

Figure 2. Carbon intensity of the LNG supply chain: each LNG cargo produces an estimated 250 000 t of CO2 equivalent from upstream production to downstream combustion.

Launching the methodology

In November 2021, Pavilion Energy and its partners jointly published the Statement of Greenhouse Gas Emissions (SGE) Methodology, essentially establishing a best practice standard of what GHG emissions reporting for delivered LNG cargoes should look like. It is the industry’s first published GHG methodology for LNG that will be applied to sale and purchase agreements with Pavilion Energy, for supply to Singapore from 2023.

Developed by a team of technical specialists representing Pavilion Energy, QatarEnergy, and Chevron, and supported by global sustainability consultancy Environmental Resources Management, the SGE Methodology was also reviewed by independent academic experts, commercial institutions, and verification bodies to ensure it is robust, reliable, and in line with best practices.

The SGE Methodology is based on the principles of coherence, relevance, completeness, consistency, transparency, and accuracy. zz Coherence: The methodology provides a measurement, reporting, and verification framework for GHG emissions based on industry standards related to the production of carbon footprint, such as the ‘GHG Protocol Product Life Cycle Guidance’ and ISO 14067:2018 on Carbon Footprinting of Products. Using the SGE Methodology, LNG sellers can develop and adapt their internal GHG reporting processes to deliver a statement of GHG emissions for each cargo.

Figure 3. Key steps in developing an MMP and how it is used to calculate and report an SGE for a delivered LNG cargo.

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zz Relevance and completeness: The methodology covers operational emissions associated with all lifecycle stages from production wellhead to delivery point, including an incoming ballast voyage and in-port emissions for shipping. Emissions associated with operation of the discharge terminal through to end user are not addressed in the scope of the methodology, but as a natural

sequence, may be integrated within to fulfil the full lifecycle assessment. zz Consistency: The product of the SGE Methodology is a statement of GHG emissions (SGE). The SGE is quantified and reported per cargo as total GHG emissions, expressed as carbon dioxide equivalent (CO2e), emissions intensity per energy content delivered, expressed as t CO2e/million Btu, and methane intensity per energy content delivered, expressed as t CH4/million Btu. At a minimum, emissions of carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) must be included.

All emissions are expected to be allocated appropriately to LNG and all other co-products. zz Transparency and accuracy: One key differentiating factor of the SGE Methodology is the requirement to develop and maintain a methodology monitoring plan (MMP), whereby a reporter documents steps taken to meet criteria established in the methodology, with clearly defined emission sources, calculation approaches, and internal controls (Figure 3). Third party verifiers then review both the MMP as well as reported GHG data, producing a verification report that includes suggested improvements in an operator’s processes.

Theory in practice: applying the methodology to supply deals

In publishing the SGE Methodology, the intent was for it to be practically adopted by industry participants and over time, become the de-facto industry standard. Pavilion Energy has signed supply deals with QatarEnergy and Chevron for supply to Singapore from 2023. Under these agreements, LNG cargoes delivered to Pavilion

Energy will be accompanied with a statement of GHG emissions as part of standardised reporting documentation. Such transparency is proving to be even more important following the Singapore Government’s decision to raise the carbon tax significantly to S$50 - S$80 by 2030, a bold move towards its net zero target by, or around, mid-century.

Given the trajectory of the energy transition, demand for carbon-neutral LNG can only grow. Within 10 years, most LNG cargoes sold in the market could be carbon-neutral, and result in gas and LNG trading at price differentials depending on GHG content. This may take time and depend strongly on market dynamics, as well as the evolving regulatory landscape.

Initiatives such as the SGE Methodology mark a step towards advocating for greater transparency around LNG’s GHG footprint.

Even so, more co-ordinated actions are needed by governments, industries, and corporations to advance progress on decarbonising energy systems. The future for carbon-neutral LNG can only be realised with strong industry collaboration and support for a standardised, verifiable, and transparent methodology. As the energy transition accelerates, the LNG industry can be confident that there are efforts to account for, reduce, and offset LNG emissions, making the cleanest fossil fuel even cleaner for use.

References 1.

IEA, ‘Global Energy Review 2019,’ (April 2020).

2.

UK Department of Business, Energy, and Industrial Strategy (BEIS).

3.

BloombergNEF.

4.

STERN, J., ‘Measurement, Reporting, and Verification of Methane Emissions from Natural Gas and LNG Trade: creating transparent and credible frameworks’, (January 2022).

VACUUM JACKETED PIPE

WE HAVE YOU COVERED YE TERDAY TODAY AND TOMORROW.

Chuck Hayes, Swagelok, USA, describes how to choose the right tube fittings for LNG vehicle and infrastructure projects.

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s countries around the world strive to lower emissions in the transportation sector, they are exploring the possibility of using more LNG vehicles – and manufacturers and buyers have taken note. Per NGV Global, more than 30 million natural gas vehicles were expected to be on the road worldwide by the end of 2021, with more on the way.

Supporting the industry’s anticipated growth will necessitate the efficient production of high-quality fuel delivery systems throughout the value chain, from fuel source to vehicle. That means systems for on-vehicle LNG applications in the light-duty (car and van), heavy-duty (bus and truck), rail, ship, and aerospace markets (Figure 1). It also means systems for LNG infrastructure applications, including the dispensers, storage cylinders, compressors, and pressure

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control devices that make up a station, as well as the tube trailers that deliver LNG to the stations (Figure 2).

The expansion of LNG vehicles will require widespread, reliable refuelling infrastructure to realise its full potential.

Maximised capacity for refuelling stations is critical, with the ability to store large amounts of highly pressurised gases onsite for consumer distribution. This requires the componentry in those systems to be up to the challenge.

Whether it is bent fuel lines, valves, flexible hoses, measurement devices, or tube fittings, components for LNG service must be selected carefully to meet rigorous standards to ensure safety and long-term performance. To achieve these goals, original equipment manufacturers (OEMs) must meet specific performance criteria, focusing on ensuring leak-tight connections, thermal performance, and corrosion resistance in

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components, the consistent availability of components to meet production demands, and the importance of training assemblers to perform expert gas delivery system installations.

Seal tightness

Leaks in LNG systems can put operators in danger, because natural gas is commonly stored at pressures in excess of 275 bar (4000 psi). Specifically, ordinary end users must be able to depend on fault-free performance so they can fill their tanks safely and easily at refuelling stations. Successful operation depends on the use of high-quality components in the system.

To achieve leak-free operation, gas-tight seals are necessary. While bite-type and compression tube fittings (either single- or two-ferrule designs) are standard for industrial applications, they may not stand up to the extraordinary rigors of transportation applications. More

robust protection is required and can be achieved by creating gas seals along multiple lines of contact. When assembling fittings for LNG service, it is important to visually confirm the fitting is completely pulled up by ensuring the dynamic zone is in contact with the shoulder of the fitting body (Figure 3).

Vibration resistance

Unlike standard fittings, LNG fittings must contend with the vibrations inherent in moving vehicles, virtual pipelines, and compressor stations. As a result, vibration resistance is an essential part of choosing fittings for LNG applications.

Tube fittings used in transportation should have a two-ferrule design with hinging-collecting action so they create a twin mechanical grip on the tubing. This arrangement helps reduce the chances that fittings will back off, regardless of how much vibration they endure (Figure 4).

Such fittings allow for tiny movements called ‘spring back’, which makes them perfect for use in vehicle operation and refuelling infrastructure.

Thermal performance

LNG fuel systems are subject to inherent thermodynamic challenges. To keep natural gas in its liquid state, its normal temperature is -260˚F (-160˚C), so prior to use in the engine as a gas (CNG), it must rise to ambient temperature. Tube fittings must be able to accommodate such sudden changes.

Only high-quality materials can avoid potential expansion and contraction during these events, which can cause leaks and other forms of failure.

Corrosion resistance Figure 1. On-vehicle applications for LNG include light-duty (car and van), heavy-duty (bus and truck), rail, ship, and aerospace.

Figure 2. LNG infrastructure applications include the tube trailers that deliver LNG to the stations.

In addition to internal stresses, external environmental conditions can sometimes lead to the corrosion of the components of LNG vehicles and fuelling infrastructure. It is incumbent on OEMs to minimise such damage by using high-quality materials in LNG systems.

Instead of carbon steel, for example, OEMs should consider using high-quality stainless steel with higher nickel and chromium levels. Since most LNG fuels contain odorants (designed to help detect leaks) with sulfur, the higher nickel and chromium levels help resist premature corrosion and rusting. Additionally, LNG has a higher humidity content than other fuels, which can also promote often unseen internal corrosion. High-quality stainless steel also helps to prevent these potentially serious safety risks.

Assembly and availability

Figure 3. When assembling fittings, it is important to

visually confirm the fitting is completely pulled up by ensuring the dynamic zone makes contact with the shoulder of the fitting body.

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Finally, it will be critical for OEMs to provide reliable products quickly and efficiently as LNG mobility solutions expand their reach. To encourage the proper and prompt installation of the correct tube fittings, the installation should be made as easy as possible for technicians. That is why it is important to choose fittings that are specifically designed for high-volume fuel lines. By choosing these specialised tube fittings, technicians are more able to build consistent leak-tight tube connections that resist vibrations as effectively as possible.

High-volume production is not just about easy assembly.

OEMs aspiring to build aggressive production schedules must work with suppliers that can provide a local inventory of components to provide for quick delivery of products as needs

fluctuate. Suppliers should also be able to understand and work around an OEM’s production needs.

Training a company’s team

Regardless of how well designed a company’s tube fittings are, expert installation is key to ensuring they work as designed.

While training has become more challenging in recent years, this essential work has not stopped. One major LNG supplier in Australia quickly realised that to provide its products safely to end users, the supplier would have to continue training.

Figure 4. Two-ferrule, mechanical grip fittings that deliver

hinging-collecting action create a twin mechanical grip on tubing, effectively reducing the likelihood of fittings backing off when subjected to continuous oprational vibration.

Although in-person training had become challenging to conduct, the organisation worked with a qualified component supplier to develop an all-virtual training programme to ensure employees were equipped with the skills necessary to continue working safely.

The LNG supplier discovered that sharing skill sets among its technicians and system operators helped the organisation reduce the likelihood of loss through containment incidents.

After all, the whole staff must have the right knowledge to work safely, no matter their role. The virtual training programme, developed in partnership with its fitting’s supplier, helped the organisation feel confident in its teams’ abilities to safely install and maintain critical tubing connections.

The virtual courses the Australian LNG supplier conducted included both practical and written assessments, and attendees were mailed training kits before their virtual session. With these kits in hand, the trainees were asked to demonstrate their knowledge by making a small tube fitting assembly. Those assemblies were then evaluated by the supplier, and errors or inconsistencies were corrected for the trainees.

Virtual training offered greater flexibility to the employees and smaller class sizes for trainees, which allowed them to build greater rapport with the instructor and receive personalised answers to their questions. It allowed attendees the flexibility to attend trainings onsite or from their own homes, and the electronic platform used for testing was easily accessible on mobile devices and laptops from anywhere.

By providing employees with the flexibility to do the training in their own time, the LNG supplier realised that it could reach more employees in a shorter time period with high-quality training that might not otherwise be available. As an additional benefit, the costs of virtual training are significantly less than traditional in-person training, which requires travel and accommodation charges for qualified trainers to be on location.

The company also found that flexible virtual training significantly boosted employee engagement in the training, and employees reported greater satisfaction with the virtual training than more traditional in-person opportunities. Virtual training for critical installation applications in the LNG vehicle and infrastructure realm is increasingly making sense and providing the necessary expertise to reduce mistakes in this increasingly critical transportation sector.

An ideal fitting for LNG applications

Figure 5. Assembly-by-torque fittings assemble quickly to be a predetermined torque, which facilitates the reliability and repeatability of creating fitting assemblies.

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May 2022

To succeed in the LNG market, OEMs need tube fitting technology that meets the demanding performance criteria of these fuel systems. Assembly-by-torque (AbT) fittings assemble quickly to a predetermined torque, which facilitates the reliability and repeatability of creating fitting assemblies (Figure 5). The advanced-geometry, hinging-collecting back ferrule tube fittings provide consistent leak-tight performance, and assemble quickly and easily. In particular, AbT fittings provide excellent gas-tight sealing and tube-gripping action, as well as vibration fatigue resistance, even after repeated reassembly.

Building the appropriate framework to support LNG vehicles and their refuelling stations is not a simple one. The criteria to ensure everything functions as expected are critical.

As LNG vehicles and infrastructure are built, it is important to work with reliable component suppliers who can meet all the criteria necessary to ensure success.

, reece G , r e t , Regis s ’ d y ology o n l h L c , e u as t oice tro i g h c g M e n s i h t o t y floa d Pan , and y b n t a i d l i e u t b poulo resen forda o f p l a s ssels. o , t e e y i s t v t i i o r g n p u n A tu existi gy sec r Anna g oppor e n e n i t e h r t s in conve uch a s r expla o s r e w t e g mat ding n n l i i s u s b u en disc betwe

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ecent events have led to untold disruption in global energy markets. The price of all hydrocarbons has risen sharply but gas prices have climbed the most. Despite abundant reserves globally, supply chains are geopolitically sensitive and further increases in the price of gas were to be expected.

However, in the medium-term future and looking beyond today’s geopolitical nightmare, natural gas offers huge benefits as a transition fuel on the global decarbonisation journey that can transform the lives of millions of energy-starved people.

Floating technology, specifically, can provide a faster, cheaper, and more flexible pathway to project development. It offers more flexibility, a more straightforward regulatory approval process, and a faster route to final investment decisions (FIDs).

Floating gas facilities have expanded steadily over the last decade but could now be boosted further. One possible outcome, following the disruption, is a greater focus on energy security. This is likely to boost renewable energy sources but could also provide a stimulus for the floating gas sector.

FSRUs and FSUs linked to regasification plants, either onshore or on barges, are the quickest and most effective way of boosting gas import capability. They offer great potential in many settings globally, including in energy-deprived economies, remote communities, and island nations.

It is also important to note that in relation to long-term climate objectives, gas is an essential stepping-stone on the pathway to new forms of zero-carbon energy. These technologies still pose challenges, while feasibility and scalability may take more time to come to fruition.

Lloyd’s Register (LR) is actively involved in a number of floating storage, regasification, and floating production projects in many parts of the world. And while most of the world faces an era of significantly higher energy prices, floating gas technology still offers one of the quickest, most affordable, and effective ways of generating additional power.

Merits of floating gas

Floating gas has a range of attractions compared to a land-based plant. Benefits span the whole spectrum – speed, cost, design flexibility, public response, and more straightforward environmental and planning approvals. Ultimately, the chance to locate a floating plant offshore has the scope to transform the lives of millions with a relatively clean and secure source of energy – both in populous cities and remote, outlying communities.

The number of projects is rising fast. According to figures from IHS Markit, the fleet of floating gas processing vessels rose from just seven units at the end of 2011 to 56 by 2021 year-end. Processing capacity has increased by a multiple of more than 13 over the period, 37

reflecting the deployment of more, larger units recently.

Meanwhile, from the number of enquiries LR is receiving, the company predicts this rate of expansion will continue to accelerate.

Constraints are likely, however, in terms of new FSRU construction capacity. There are only four to six specialist shipyards capable of building new LNG carriers or floating units that incorporate regasification plants and are significantly more complex. These yards are quite booked up until the middle of the decade and there is little supply elasticity in the system.

This situation is compounded by LR’s estimation that well over half of the existing approximately 600-ship, ocean-going LNG fleet is unlikely to meet IMO Carbon Intensity Indicator (CII) requirements. These enter force next January but will take effect from mid-2024 onwards.

LR’s first indications show that up to 400 ships could soon be rated in categories ‘D’ and ‘E’, requiring them to adopt a corrective action plan to improve their subsequent assessments to categories ‘A’, ‘B’, or ‘C’. Ships in ‘E’ will be required to implement efficiency improvements immediately; ships rated ‘D’ for three consecutive years will have to do the same.

Drawbacks of many LNG tankers

There are more challenges for some vessels than others.

LNG tankers powered by steam turbines, of which there are approximately 250, and four-stroke dual- or tri-fuel vessels – approximately 150 ships – are much less fuel-efficient than the latest low-speed, two-stroke engines. Substantial investment will be needed to achieve compliance. For older vessels with these types of engines, the payback period may not prove worthwhile.

And the CII requirements will tighten steadily over the second half of this decade. Ships initially rated ‘C’ – the lowest acceptable category – or modified to achieve a ‘C’ rating in 2025, are likely to slip into ‘D’ or ‘E’ in subsequent years.

Owners of these vessels face three options. One, make efficiency improvements or green their fuel mix cost-efficiently to ensure CII compliance through to 2030 and beyond. Two, trade assets for as long as possible before disposal for recycling. Or three, identify a floating gas opportunity, either as an FSU or an FSRU, and look forward to a further period of profitable employment lasting for perhaps two more decades.

LR believes that the impact of CII on the LNG fleet will be far-reaching. However, the silver lining may prove to be a ready supply of conversion candidates for floating gas projects.

Smaller complements

Through-life operating costs are also being closely focused on.

Digital technologies are enabling a new approach to human resource deployment. Significant reductions in complements are now possible, and digital twins, drones, cameras, and remote survey techniques can enhance safety, reliability, and availability. Floating assets cannot yet be unmanned, but their improved safety can be assured by smaller crews using the latest technologies.

A wide range of asset deployment arrangements can be tailored to fit specific requirements. These include a new or converted FSRU plugged into a local or national grid, an FSRU to serve energy-remote local communities, an FSU feeding regasification barges or a shore-based plant, and so on. This can sometimes offer a more flexible set-up.

LR is currently inundated with enquiries on projects such as this and the company’s recent track record in floating technology

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is a sound basis on which it can offer a wide range of consultancy services at every stage. These services range from option evaluation assessment, investment appraisal, site assessment, design review, risk analysis (including HAZID and HAZOP studies), conversion design, planning and oversight, and through-life assurance. And all of these services are in addition to the company’s traditional classification functions, including shipyard attendance and asset commissioning.

LR in the Mediterranean region and Israel has been successfully engaged in a number of floating gas developments, including the new FSRU for Cyprus which is nearing completion at Cosco Shipping Heavy Industry in Shanghai, China, and is expected to be deployed onsite next year. The FSRU is a conversion of the 137 000 m3 Galea, built in 2002.

The company’s focus has also been on the first, and now a likely second, FSRU in Greece’s Alexandroupoulis, where LNG is supplied by ships, stored cryogenically onboard, and regasified to be connected to the national gas transmission system via a 28-km pipeline. In a completely independent system, the gas will be supplied to the gas grid in Greece, but also to countries in the wider region, including Bulgaria, North Macedonia, Romania, and Serbia.

Weighing up the options

In any project, there are a wide range of choices, each with their advantages. So one of LR’s first tasks is often to assist with or undertake an assessment of the development pathways. Some of the early decisions will include whether to build new or convert, whether to choose an FSRU or FSU with a regasification plant either on barges or in a shore-based facility, capacity of the plant, and choice of site.

Then there are the more detailed design considerations: mooring arrangement, risers, valves, pipelines, jetties, design of the regasification unit, treatment of boil-off gas (BOG), and so on.

And all of this must be considered over a 20-year timeframe, for example, in a context where the unit will probably remain on station throughout.

There are many benefits to conversions, but they present different challenges. Whereas new FSRUs can be built to a specific design, converting an existing LNG carrier poses many challenges. These include the installation of an entirely new regasification system; redesign of the cargo tank system; new arrangements for BOG; new piping, valves, safety systems, and attention to temperatures and pressures.

Conversions are significantly faster and cheaper, however, and there is likely to be a ready supply of conversion candidates in the next few years. Some ballpark figures on relative costs: LR estimates that a new FSRU is 40 - 50% cheaper than a land-based plant. It might cost US$250 - US$300 million and construction could typically take approximately 24 - 30 months. A conversion, on the other hand, might cost US$80 - US$100 million and take approximately 18 months.

For the moment, construction capacity for new FSRUs is limited. Owing to their complexity, only a small number of shipyards can build them, and as previously mentioned, many of these facilities are full until at least the middle of this decade.

However, there is more flexibility in the conversion market.

Not only are there highly experienced FSRU/FSU conversion specialists amongst Singapore’s major shipyards, but some South Korean shipyards have also expressed interest in FSRU conversion projects recently. There are oceans of opportunity.

Figure 1. Safely moored off the Pacific coast of El Salvador in November, the BW Tatiana FSRU sends regasified LNG via pipeline to the newly constructed 378 MW power plant on shore. Image courtesy of EDP.

Alberto Osorio Liebana and Joel Schroeder, Invenergy, USA, outline how the first FSRU in El Salvador is contributing towards Central America’s energy transition.

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ore areas of the world are looking to increase the use of LNG in the move toward cleaner fuels, and that has led to an expanding use of FSRUs. According to the ‘Global Floating Storage and Regasification Unit Market Insights and Forecast to 2026’ report, written by analysts at 360 Research Reports, the market is expected to grow significantly over the next four years. This anticipated expansion is based in part on the fact that FSRUs are a cost-effective option for developing LNG-to-power projects, particularly in remote areas with lower energy demand.

A project in El Salvador, Energía del Pacífico (EDP), illustrates just how successful such developments can be.

Executed via a partnership headed by sustainable energy developer Invenergy and supported by El Salvador-based partners Grupo Calleja, VC Energy de Centroamerica, and

Quantum Energy, EDP is a landmark project for the region. It is the first permanently moored FSRU on the Pacific coast of the Americas and is a critical component of El Salvador’s journey to adding cleaner and more efficient energy into the country’s generation mix.

Instituting policies for change

Because El Salvador lacks indigenous fuel resources, the country developed an energy matrix for electricity generation and transportation as well as industrial applications that was highly dependent on imported oil byproducts – primarily diesel and heavy fuel oil (HFO). Historically, there was sufficient investment to support the expansion of efficient electricity generation capacity and as a result was subject to unpredictable and highly variable electricity prices.

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In 2012, El Salvador established two critical goals for its domestic energy policy: zz To reduce dependence on oil and its byproducts by promoting renewable energy sources, a culture of rational use of energy, and technological innovation. zz To minimise the environmental and social impacts of energy projects as well as those that promote climate change.

To achieve those objectives, the national energy policy goals focus on promoting diversification by incorporating new, cleaner fuels and encouraging the use of renewable energy sources in the electricity and hydrocarbon subsectors to progressively reduce dependence on oil and its derivatives. The government of El Salvador later implemented regulatory framework modifications to promote renewable energy sources, established incentives for renewable projects, and developed tendering guidelines for solar and wind projects as well as fuels other than diesel and HFO. EDP, El Salvador’s first integrated LNG-to-power project, fits into the country’s plans to diversify its national energy matrix.

The BW Tatiana FSRU is designed with 137 000 m3 of total gross LNG storage capacity and four times the regasification throughput needed to meet the maximum power plant capacity of 378 MW. EDP has contracted with Shell to supply LNG. LNG carriers moor along the starboard side of the FSRU, and LNG is transferred from the LNG carrier to the FSRU via mid-ship manifolds using cryogenic hoses. Gas is delivered to shore from the natural gas manifold on the FSRU via a flexible riser from a

Figure 2. Four SAAM tugboats escort the BW Tatiana

FSRU from her anchorage more than two miles off the coast of Acajutla, El Salvador, to her final destination, with the anchor handling tug (AHT) – the vessel responsible for retrieving the mooring lines preinstalled by Boskalis and transferring them to the FSRU – following behind. Image courtesy of EDP.

Figure 3. With the FSRU on location, four tugboats hold the

vessel in place while the AHT brings the mooring lines closer for final mooring. Image courtesy of EDP.

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port side balcony, to a subsea pipeline end terminal (PLET) connecting to a 1800 m (1.1 mile) pipeline to the onshore power plant.

Converting the vessel

Ruling out a new-build, Invenergy and 50:50 partner BW LNG identified the Gallina Moss LNG carrier as a good candidate for conversion, purchased it from Shell, and contracted Wärtsilä Gas Solutions and Keppel Shipyard Ltd to carry out the conversion.

The experience of Singapore’s Keppel Shipyard in converting the world’s first FSRU in 2008, followed by subsequent similar projects, made it the yard of choice for the project, and with an agreement signed by FSRU Development Pte Ltd (a joint venture company formed by BW LNG and Invenergy) and the Keppel Shipyard, the conversion got underway in 2020 and 2021. Wärtsilä Gas Solutions, a sister company to the Wärtsilä entity responsible for the onshore power plant, provided prefabricated modules containing the regasification unit, electricity generating engine, gas combustion unit, and boil-off gas (BOG) compressors.

As an LNG carrier, the Gallina was designed for LNG transport, so structural changes were required to ready it for regasification as an FSRU. The mooring system and new process equipment introduces additional loads on the structure, which were addressed by reinforcements to the hull to enable it to withstand stresses that it was not originally designed for. Structural modifications and reinforcements allow proper distribution of loads, a rational distribution of stress in the hull, and appropriate motions that will allow the vessel to withstand long-term fatigue.

Equipment installed on the FSRU was manufactured in multiple yards and factories around the world and sent to the Keppel Shipyard for construction. Specialised technicians from the original equipment manufacturers travelled to Singapore to complete commissioning activities.

Among the most significant components on the FSRU is the regasification module. Built and integrated on the port side deck, the module is made up of four LNG vaporisers, each capable of processing 70 million ft3/d, delivering 280 million ft3/d of total regasification capacity. Four seawater pumps hang over the side of the FSRU providing warm seawater to the vaporisers to heat the LNG and convert it to gas. A riser balcony near the regasification module allows hook-up to the flexible riser that connects to the subsea pipeline.

The BOG compressor module, also integrated on the port side of the vessel, allows BOG generated inside the storage tanks to be compressed and injected into the pipeline that connects the FSRU with the EDP power plant. A power module, consisting of three dual-fuel (natural gas or diesel) engines, was fabricated and integrated at the stern of the vessel to provide a reliable, long-term power source. A gas combustion unit was installed at the top of the power module to flare excess BOG when the power plant is unavailable to combust the BOG. With the exception of the systems that require LNG or natural gas for commissioning, the FSRU was commissioned in the yard.

Once LNG was loaded and the FSRU was safely moored offshore El Salvador, the regasification systems, gas combustion unit, BOG compressors, LNG cargo pumps, gas metering systems, and associated controls were commissioned.

Designing and model testing the mooring system

Moored off the Pacific coast, the BW Tatiana FSRU is oriented at approximately 225˚ with the bow facing into the predominate

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direction of the incoming waves. The vessel position provides sufficient water depth for the FSRU and visiting LNG ships and also minimises interference with port infrastructure, port traffic, and nearby anchorage areas.

With the shallow-water site for the FSRU decided, engineers at CAN Systems in Norway were tasked with designing and providing a system to permanently moor the FSRU in 17 m (56 ft) water depth, where the vessel will be exposed to seasonal long-period swell in an area where seismic activity has the potential to create tsunamis. The design environmental conditions considered most severe scenarios in 100-year wave, wind, and current conditions, and extreme 1000-year events for tsunamis, including sea level variations, as well as current speeds.

The CAN Systems solution is a catenary spread mooring system that incorporates a restrictor connected to the port and starboard mooring lines. The restrictor serves two purposes. It holds the mooring lines closer to the FSRU and it adds weight, which reduces the angle of the mooring lines leaving the FSRU, placing them deeper at a shorter distance from the FSRU than would be possible without the restrictor. The restricted catenary mooring (RCM) system designed for the BW Tatiana is the first RCM developed specifically for use in shallow water. It provides an unobstructed path for LNG carriers to moor next to the FSRU by keeping the mooring lines below the carrier’s keel, to enable safe ship-to-ship (STS) LNG transfer, and allows the FSRU to stay safely moored during all expected extreme weather conditions.

The mooring system was designed using a sophisticated computer model to numerically prove the concept. The next step was to physically prove the concept by testing a 3D-model of the FSRU. Model testing, carried out by MARIN in the Netherlands, included scenarios to determine mooring capacity in conditions in which any single component in the station keeping/mooring system is lost. Testing parameters based on the 100-year wave and 100-year wind simulations identified environmental conditions that would lead to the maximum force in each of the anchor chains. Simulations were performed with the most loaded line removed and retested with the second most loaded line removed. MARIN also conducted tests to validate mooring performance for tsunami conditions. The results of these tests were satisfactory, and the safety factors obtained from the wave tank exceeded those obtained in the desktop model.

Setting up onsite

The BW Tatiana left the Keppel Shipyard in Singapore and sailed to Korea, where one tank was filled with LNG to be used in the power plant commissioning. Following the receipt of LNG, the BW Tatiana embarked on a trans-Pacific journey to the Port of Acajutla, El Salvador, where it arrived in late October 2021 for hook-up and commissioning.

The arrival time was carefully planned, taking into account the atmospheric and sea conditions in El Salvador which are affected by seasonality, and avoiding the six-month rainy season when sea conditions would not be amenable to offshore construction activities.

Boskalis oversaw the mooring system pre-installation as well as that of the shore approach pipeline. This included dredging, installing the 1800 m (1.1 mile) long, 24 in. gas pipeline from the onshore 378 MW plant to the FSRU, and backfilling over the line, as well as installing the mooring and riser system that connects to the PLET and riser. All were pre-installed in the dry season before the arrival of the FSRU. The BW Tatiana arrived 25 October 2021, and the hook-up campaign immediately got underway with BW Offshore co-ordinating the hook-up activities performed by multiple contractors.

Boskalis was responsible for installing the 11 anchor and mooring chains prior to the arrival of the BW Tatiana. When the vessel arrived, an anchor handling tug (AHT) was onsite to recover the mooring chains and hand them off of the FSRU for connection. Four tugboats, operated by SAAM Towage, were used to move the BW Tatiana into position for connection to the pre-installed mooring chains. Once the first mooring line was connected, the tugboats stabilised the vessel while the remaining mooring lines were handed off to the FSRU and connected to the chain stoppers.

With the mooring system connected, the FSRU’s boiler propulsion system was shut down and activities got underway to commission the BOG compressors, regasification system, gas combustion unit, and new engine generators. Once the FSRU was able to send regasified LNG to shore, the subsea pipeline was pressurised with gas, and commissioning tests at the generation plant began. Tests included operating the 19 Wärtsilä 18V50SG engines as well as the heat recovery steam generators and the steam turbine in preparation for entering commercial operation.

The preparations to send gas to shore were completed within two weeks of arrival, and gas was first sent to shore on 15 November 2021.

Delivering on a commitment

Figure 4. The Bilbao Knutsen LNG carrier transferred more

than 125 000 m3 of LNG at a maximum rate of 9000 m3/hr to the BW Tatiana in Shell’s first LNG delivery for the EDP project. Four cryogenic hoses conveyed the LNG to the FSRU, while two others recirculated vapour to ensure pressure equilibrium in the storage tanks of both vessels. Image courtesy of EDP.

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EDP not only achieved the goal of replacing HFO with cleaner burning LNG to supply up to 30% of El Salvador’s peak electrical demand, it generated more than 2000 direct construction jobs at its peak, with more than 60% of the workforce being Salvadoran. EDP has provided and will continue to provide investments to promote the economic and social development of the country and the community that hosts the project.

The LNG terminal off the coast of El Salvador is an enabler for the country, introducing the opportunity to develop additional infrastructure to supply gas to other regional consumers. Invenergy is already developing the means to supply both LNG and CNG to several customers in the region, beginning with potential CNG delivery in 2023.

Kym Winter-Dewhirst, Venice Energy, Australia, explores the promising future of LNG in Australia, detailing how combining renewables with LNG could create an ideal amalgamation.

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omestic gas has played a significant role in the Australian energy mix for over 50 years. It is not surprising that the cities with the largest populations on the east coast of the country – in the states of Victoria, New South Wales (NSW), and Queensland – experience the greatest demand.

However, for some time now, warnings of gas shortages have dominated headlines, as significant volumes of gas produced onshore are exported. This is not likely to change any time soon due to strong, legacy contracts between the primary petroleum producers and offshore off-takers.

The issue of increasing onshore production is compounded by political policies that prohibit onshore exploration and production in sensitive communities or agricultural areas. In addition, the cost of exploring untapped, unconventional, or deeper gas reserves in arid regions of Australia is both technically challenging and expensive.

The looming shortage of domestic gas in Australia is expected to continue for several decades to come. In the case of the state of Victoria, 400 PJ of gas is consumed each year, and production is expected to fall by approximately 50% over the next few years.

For Australia, shifting to renewables is a long-term solution that will not come overnight. Gas will continue to play a role in the transition to a renewables landscape that is not yet ready to provide a 100% renewable energy solution.

In addition, there is growing public and political pressure in some areas for an acceleration and earlier exit of coal-fired energy from the domestic network, with several recent

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announcements confirming some early closures of coal-based power stations.

Australian LNG

Just before the end of 2021, the South Australian government approved the company’s first project – an LNG import terminal at the state’s major port, Outer Harbour. The government labelled the project as ‘critical infrastructure’, as it will open Australia to the international gas market, helping the country to meet the demand in gas that currently cannot be met via onshore means.

The AUS$250 million LNG project will establish a new two-berth wharf terminal to accommodate an LNG carrier, a moored FSRU, and supporting infrastructure to import, store, and re-gasify LNG for delivery of gas to customers.

The project will support existing gas-powered infrastructure and the progressive decarbonisation of South Australia’s energy mix.

This will be one of the first terminals of its kind in Australia, and it will help to underpin South Australia’s renewables sector by providing firm, dispatchable energy at times when wind and solar are not generating power.

It is anticipated that LNG will be imported from any number of offshore regions, including Singapore and Qatar, and even the US. Building an LNG terminal did not come as an immediate decision for Venice Energy. The company started with a concept approximately five years ago to build a technologically advanced gas-fired power station. It became apparent that the company could not guarantee that it would be able to secure gas when it was needed. That made the company look at the possibility of importing LNG and the broader benefits it would provide to South Australia and adjacent states.

As an integrated energy company that believes in the global need to decarbonise the energy supply, Venice Energy aims to bring a range of projects to fruition that enable the local (South Australian), growing, renewables sector. The company has committed to ensuring its LNG terminal is powered by renewable energy, and will establish the only terminal of its kind in the world to be powered in this way.

As Venice Energy’s first project, the company felt it was important to demonstrate that it is part of the future of energy.

With 60% of South Australia’s energy already supplied by renewables, the state has the lowest carbon footprint on mainland Australia and one of the lowest in the world. It makes perfect sense that this direction is added to, rather

Figure 1. Artist impression of Outer Harbour LNG terminal to be built in South Australia.

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than introducing an additional carbon load from operating the terminal.

It is estimated that without a renewable energy source, the future terminal would produce approximately 50 000 tpy of carbon. Over its estimated 10-year project life span, around 500 000 t of carbon would be produced. Powering the LNG terminal with renewables cuts those forecast emissions to zero.

The environmental benefits extend further. Now that Venice Energy has been granted approval to construct its LNG terminal, it will undertake a feasibility study into making a key 680 km pipeline bidirectional. The SEAGas pipeline that connects the flow of gas between South Australia and Victoria currently only flows one way into South Australia. Making the pipeline bidirectional would enable the terminal to supply gas to two states – a move that could fast track the decarbonisation of the Victorian energy landscape.

If the gas sent to Victoria is used to displace coal generation, it could displace approximately 3 million t of carbon in Victoria each year. Over 10 years, that is 30 million t.

The company wants to provide a meaningful contribution to reducing carbon at both an operational perspective and more broadly across two states.

The future of LNG and renewables

Recently, there have been widespread reports that coal generation in NSW and Victoria could retire early, leaving a gap in electricity generation within the National Electricity Market. This could potentially lead to blackouts and price increases for consumers, and presents an opportunity for LNG to provide an alternative solution.

Venice Energy’s vision is for a diversified mix of projects that support the transition to renewable energy.

Approximately five years ago, in the early days of the company, the objective was to look at a gas-fired power station. The company is first to admit that a lot has happened in that time.

Now it believes future investment in power generation will incorporate low- or zero-emission technology. With hydrogen development investment likely to increase significantly over the coming years, future energy generation may be increasingly shaped toward hydrogen.

The vision for the company also includes hybrid solutions in power generation. This includes battery storage development as a user or partner, and branching LNG out into other parts of the world.

There are many parts of the world where the company may consider investing and developing similar types of operations and projects. In particular, the developing world is desperate for access to energy and clean water. Both of these elements are critical for the development of civil societies and helping to lift people out of poverty.

This is a place Venice Energy would like to expand its offerings to in the coming years, as it develops its projects in Australia and improves its knowledge and skill base in the industry.

Work is already underway to source the next potential LNG import terminal location in Africa, Asia, or South America.

For now, Venice Energy’s LNG terminal in Australia is the primary focus, with construction expected to commence later in 2022, and first shipment of LNG into the terminal and connection to the South Australian gas network anticipated around late 2023 or early 2024.

Figure 1. The Eagle Valence: one of the world’s first LNG dual-fuelled and most environmentally-friendly VLCCs that joined TotalEnergies’ time charter fleet in February 2022.

Mireille Franco, HSEQ and Technical Department at TotalEnergies Marine Fuels, France, details how technical developments in the LNG bunkering chain will play a pivotal role in enabling the transition to future marine fuel solutions.

T

he transition from conventional heavy fuel oil to LNG has been one of the most significant developments in the shipping industry in the last century. Since the birth of LNG shipping in 1959, significant innovation has been made to apply the use of LNG as a marine fuel across different segments of shipping and vessel sizes.

over 380 new orders, which shows that shipping’s transition to LNG is more evident than ever, particularly in the cruise, container, and tankers segments.

This energy transition also demonstrates the evolution of LNG as a viable, scalable, cleaner, and lower-carbon fuel choice compared to conventional fuel in maritime transport.

Accelerating new-build orders

Ship-to-ship bunkering: adapting from conventional fuels to LNG

Over the last decade, the number of LNG-powered ships other than LNG carriers has increased significantly. Based on Clarksons’ January 2022 data, there are approximately 251 LNG-fuelled vessels currently operating globally with

Developing LNG as a commercially viable fuel has, in turn, led to the development of specific engines, equipment, and safety measures through a management of change. This entailed

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a change of rules and standards, equipment, and safety considerations, amongst others.

Standards and equipment

The publication of the Code of Safety for Ships using Gases or other Low-flashpoint Fuels (IGF Code), as well as dedicated class rules from classification societies added a technical framework for the development of LNG as a marine fuel and provided confidence to the industry. The IGF Code itself was developed to regulate the use of natural gas and other gaseous or volatile marine fuels, including potential future options such as ammonia.

Efforts to standardise the use of LNG as a marine fuel have led to the development of dedicated guidelines and technical documents for LNG bunkering from the International Standard Organisation (ISO) and the Society of Gas as Marine Fuels (SGMF). These standards are vital in scaling up LNG bunkering activity and creating compatibility between the bunker and receiving vessels in ship-to-ship (STS) operations.

As a pioneer in the investment of LNG bunkering infrastructure, TotalEnergies Marine Fuels’ active role in international organisations and industry working groups, including the ISO, SGMF, SEALNG, Society of International Gas Tanker and Terminal Operators (SIGTTO), and Singapore’s MPA Technical Reference 56 (TR 56), has enabled the company to share its knowledge and insights gained from its LNG bunkering milestones and development experiences.

Equipment onboard LNG bunker vessels

Whether looking at the tanks, pumps, flexible hoses, or any other specific LNG-designed equipment, the full chain of the transfer system is successfully working across the bunkering operations today, due to the development of dedicated equipment and processes designed for LNG transport, which was then specifically scaled down for LNG bunkering.

For example, the cryogenic equipment used for LNG carriers needed to be scaled down for LNG bunker vessels and also to be adapted to customer vessels. Manufacturers have adapted their design without reducing the level of safety, which was a strong requirement from all stakeholders.

The subcooler and LNG quality measurement equipment are good examples of new equipment that are not required in conventional bunker barges and optional in LNG bunkers, but have been added to TotalEnergies’ chartered LNG bunkering vessels to improve the company’s operations.

With re-liquefaction capacities of boil-off gas (BOG) varying from 0.2 tph to 3 tph for a single module, the subcooler allows for the reduction of emissions and can be installed on new LNG bunker ships.

LNG quality measurements can now be done onboard an LNG bunker vessel via gas chromatographs or Raman spectrographs, whilst conventional bunker vessels require fuel samples to be taken and sent to a laboratory.

Terminal infrastructures

The development of LNG terminals and jetties is also critical for LNG bunkering activities.

LNG terminals, dedicated jetties, or existing jetty modifications have been created in order to ensure the safe approaching and mooring of the LNG bunker vessels as well as the safe transfer of LNG from the terminal to the small scale ship.

Issues, such as the height of the jetty, the position of fenders specific to ship dimensions, the crane’s reach, the gangway for personnel transfer, mooring arrangements, and the arms envelope have all had to be assessed and managed. The transfer rate and BOG management have also had to be adapted.

Changing safety requirements and safety studies

Compared to conventional bunker fuel, LNG presents a different set of potential hazards.

Consequently, TotalEnergies has implemented new design standards for cargo and transfer systems.

For conventional ship designs, IMO, class rules and standards, as well as some professional documents, define the distances and mitigations to be included in the design, specifically for the bunkering areas and operations, in order to reduce the risks associated with conventional fuels.

For LNG bunkering, however, specific design risk assessments are first conducted, which will define the mitigation measures to be taken. These risk assessments are required by the IMO IGC and IGF codes, ISO 20529 standard for bunkering LNG-fuelled vessels, and SGMF’s FP07 safety and operational guidelines, as well as FP02 recommendations of controlled zones during LNG bunkering.

In terms of safety engineering, LNG bunkering has also overcome the challenge of transferring the LNG in STS operations while the Figure 2. Based in Rotterdam, the Netherlands, TotalEnergies’ first chartered LNG bunker customer vessel is running 3 vessel, the Gas Agility, has delivered over 400 000 m of LNG bunker since commencing commercial operations. operations in November 2020.

The so-called simultaneous

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operations (SimOps) are crucial as to not delay customer operations due to bunkering whilst maintaining the required level of safety.

Finally, a dedicated joint plan operation (JPO) or joint bunkering plan (JBP) is created and put in place for each pair of vessels involved in LNG bunkering. The plan addresses the operation in a step-by-step approach to define the roles, responsibilities, and main actions on each side.

Skills training

With growing LNG bunkering activity around Figure 3. France’s first dedicated LNG bunker vessel and TotalEnergies’ the world, increasing numbers of crews are now second chartered LNG bunker vessel, the Gas Vitality, launched Marseille’s trained in the safe handling of LNG, associated first ship-to-containership operations in January 2022. equipment (cryogenic hoses, membrane tanks, quick connect-disconnect couplers), and STS operations that are, for some LNG bunker vessels, requiring finer manoeuvres and the use of Based on the industry’s LNG bunkering developmental additional propellers among other features, as in the case process, there is much to consider, besides fuel availability of the Gas Agility and Gas Vitality. and market readiness, in order to apply the use of a new energy as a marine fuel. Key issues across the whole supply Developing future green gases chain need to be considered, including: The work that has been done over the last 10 years to scale zz Safety and environment. the application of LNG as a marine fuel forms a strong zz Fuel behaviour and performance. foundation for the industry to address the technical aspects zz Engine design and manufacturing. of designing and operating various infrastructure that will be required to bunker future green gases. zz Vessel design.

Considering, for example, ammonia, which is a zz Operations management. promising low-carbon gas marine fuel contender; the regulatory bodies have already addressed rules for the use zz Storage and transportation. of ammonia as a marine fuel. zz Fuel compatibility with diverse vessel types and sizes.

Additionally, just like LNG, ammonia is also already zz International standards. transported by vessels, with a full set of transfer equipment available for large scale transport. As a next step, the zz Skills/personnel training. industry may need to look at how this equipment can be down-sized and adapted for the different types of receiving Today, there remain unanswered questions concerning and bunker vessels. the supply chain required to bunker these future fuels. For For other elements of the bunker vessel, such as cargo example, will the future see large and small scale ammonia tanks, some manufacturers have also communicated how terminals as has been seen for LNG? Or will it be managed LNG solutions will be ‘ammonia ready’, thereby presenting in shorter supply chains? Will ammonia storage be possibilities to further extend the shelf life of the shipping accepted everywhere? industry’s LNG investments today.

Will harbours segregate the risks by developing new In terms of safety studies, LNG bunkering is bringing a infrastructures dedicated to specific fuel solutions or will proven and reliable methodology that is aiding the they welcome all kind of fuels and manage the risks development of future marine fuels. For example, tools upstream, imposing some constraints to the vessels? developed for natural gas dispersion analysis, such as the Regarding concerns on the molecule, ammonia’s toxicity Bunkering Area Safety Information LNG (BASIL), may be remains a key consideration that will have an impact on adapted for the evaluation of other future marine fuels every asset associated with its bunkering activity. such as ammonia.

Dedicated JPOs for ammonia bunkering will also have Additionally, the LNG bunkering training that ship crews to be developed to deal with new identified hazards have received on low-temperature and high-pressure vessel compared to LNG. Through the company’s collaborations products can be built upon for these future marine fuels. with industry partners, TotalEnergies Marine Fuels is actively participating in different pilot projects around the Future marine fuels: the work world aiming at providing answers to some of these continues technical questions and aspects of development.

IMO’s decarbonisation goal of reducing shipping Until other alternatives come into commercial scale, greenhouse gas emissions by 50%, coupled with the LNG provides the most ready and available fuel solution for European Commission’s proposals for shipping under ship owners and charterers to reduce their emissions today, their ‘fit for 55’ package, will ultimately require ships to whilst providing important technical knowledge and transition to new and lower-carbon marine fuels which are expertise to help the industry step into the future with currently not yet fully commercially available. more proven, new fuel solutions.

May 2022

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James Smith, Houlder, UK, details how infrastructure choices made today will determine how much flexibility LNG projects have to evolve over the long-term.

NG is the cleanest fossil fuel available today, and as the gas market shows burgeoning promise, investors are keen to get projects up and running as quickly as possible. Nations such as Germany, for example, are considering fast-tracking the construction of LNG terminals to increase their energy flexibility.

And while some see LNG as a transition fuel until hydrogen and ammonia come online, there is a growing availability of renewable natural gas (RNG) which means LNG may have a much longer life span than some had previously considered. LNG infrastructure remains similar for other cryogenic substances, and current systems can be upgraded when the time comes.

Therefore, future-proofing LNG infrastructure is essential to ensure projects and systems built now do not become redundant later on.

Current trends

Over the past decade, the transition to LNG has been most pronounced in countries reliant upon diesel or coal-powered power stations, for example Pakistan, Africa, China, and Brazil.

Beyond that, the global market is demanding LNG in smaller parcels for power generation and terminal networks, supplying communities that might be isolated from major hubs, particularly coastal and inland communities, as well as island nations. Many communities, however, have limited appetite for the major civil works required for new harbours, quaysides, and jetties due to environmental sensitivities and lack of readily available investment finance.

Virtual gas pipelines are a key solution. They enable gas to be delivered to users without the need for a fixed, static pipeline – cost and flexibility are key benefits.

There are many such projects underway, including in

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China, Southeast Asia, Australia, the US, Central America, South America, and India, all of which require a flexible approach to distributing LNG between the source and the user through a combination of elements, dependent on the specific situation. Leveraging rail, road, and waterways, virtual pipelines provide a scalable and modular way of achieving the reliable distribution of natural gas.

One example is the Amazonia Energy – or Uirapuru – project which is facilitating supply of natural gas to existing and future customers located along the Amazon River up to the cities of Belém, Manaus, and Porto Velho, Brazil. The flexible infrastructure comprises two reception and stocking LNG terminals, supported by a system of small barges and pushers capable of transporting gas upriver to supply an estimated market of approximately 5 million m3/d under long-term agreements.

Floating transfer terminals

LNG storage infrastructure can be expensive compared to its oil and coal counterparts. Firstly, it is newer and there has been less time to overcome the unique challenges that LNG poses, namely the cryogenic temperatures at which LNG must be stored and transferred. In addition, the growing need for LNG to be transferred in a wider range of locations means projects face unique challenges.

LNG project developers have risen to the challenges, and as a result, there is worldwide demand for flexible,

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modular, tailored solutions that meet specific LNG infrastructure requirements and satisfy local supply chains.

There are even developments underway which insert small scale LNG offtake technology into existing larger scale LNG infrastructure, so small scale LNG does not need to start from zero.

The flexibility benefits of floating LNG terminals over traditional onshore transfer, storage, and liquefaction processes have become clear since adoption. They include shorter construction times, a reduction in environmental impact, and therefore an easier process for projects seeking regulatory approval, as well as general value for money over other methods in deep sea, sensitive, or remote locations.

Floating transfer terminals also offer an alternative to conventional concrete jetties in these scenarios, with most interest from emerging countries experiencing a surge in energy demand, often in remote areas. The construction of a fixed jetty can be prohibitively expensive, and this is often the case in Central and South America, as well as South and Southeast Asia. Floating transfer solutions can be more cost-efficient in certain circumstances, for example in areas of challenging bathymetry, for short-term projects, and in areas with operational, planning, or environmental restrictions.

Floating transfer terminals are highly configurable to the end user’s requirements. They can be dimensioned to suit specific locations, incorporating, for example, a draught restriction, or others such as length, breadth, air draught, etc.

An LNG carrier can come alongside a floating transfer terminal with its own mooring arrangement. Alternatively, the terminal can transit from the shoreline, either self-propelled or tug assisted, out to the LNG carrier and moor alongside with different mooring technologies.

The LNG is transferred from the terminal to/from shore via floating cryogenic hoses. The transfer system itself can be a marine loading arm and hose-based transfer system, mounted on the floating transfer terminal. Equally, any suitable LNG transfer system can be installed onto the terminal to meet the operational requirements. There are numerous permutations, with the overall design being matched to each specific situation. Any commercially available LNG transfer technology can be incorporated into the solution.

Portability is a key benefit of FSUs which offer a more temporary and cost-effective solution in situations where land space is restricted. FSUs can also play a role as permanent storage in projects where the construction of onshore tanks are prohibitively expensive or do not warrant the initial project expenditure until scale production has been met. While some FSUs are being designed and built for purpose, the option of converting existing vessels can prove more financially compelling.

This is driving demand for more flexible, modular, tailored solutions to meet specific alternative fuel infrastructure requirements – particularly last mile connections.

Mobile bunkering solutions

Given that LNG fuelling is still an emergent market, there is a need to ensure any CAPEX on these systems maximises flexibility. For example, a road transportable

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mobile transfer system can provide a safe and efficient hybrid hose handling solution for small to mid scale LNG applications where fixed infrastructure is impractical.

Complexity is the enemy of effective solution design.

As the associated costs of LNG and transfer systems are often higher than for other fuels, simplicity is essential to achieve cost-effective arrangements. Automation is a key simplifier, particularly when it comes to the transfer and connection of the vessel. It minimises human intervention and enables disconnection in the event of an emergency, ensuring separation from the fuel supply.

This is where a transfer arm configuration can come into its own. It protects the receiving vessel manifold from excessive forces during transfer and monitors the manifold position to check for vessel drift. If limits are reached, it triggers emergency shutdown or release through breakaway couplers.

Understanding the challenges

While market drivers can change, controlling time, cost, and resources remain the primary challenge for LNG project developers. Global macro-economic fluctuation and uncertainty has manifested itself in sustained tight margins and rationalisation in the energy sector and low or negative returns in the shipping market, underpinning a challenging marketplace for asset owners and operators to work within.

Additionally, the marine and energy markets are witnessing a period of deeply impacting regulation that is likely to continue, often requiring major investment and technological innovation and advancement. Changes are needed to traditional design concepts for new assets to support this transformation.

Feasibility studies are necessary and prudent to understand which concepts and products (from floating storage and jack up units, to floating transfer technology, cranes, and hoses) combine to deliver the optimum solution for the specific needs of a project. Feasibility studies also provide a solid business case for the final investment decision (FID), which requires the agreement and alignment of multiple parties for the project to proceed.

Houlder is currently working on five feasibility studies in North America, Central America, South America, Central Asia, and Africa – all with the aim of determining the best, most cost-effective solution for each specific project’s needs. There is a range of effective technology that can be deployed today. It is important to determine how it can be best packaged together for greatest effect, to achieve the best return on any investment.

As uptake accelerates, project developers need to understand which solutions will work in each instance: this requires collaboration and independent expertise.

Houlder is ideally placed to support its clients and partners in managing the huge challenges ahead, as the company understands the full lifecycle of assets – how they are designed, built, managed, decommissioned, and recycled.

The company also recognises how operating environments are changing, the impact that this is likely to have on existing assets, and the changes to traditional design concepts that new assets need.

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World Gas Conference 2022 preview

LNG Industry previews a selection of companies that will be exhibiting at this year’s World Gas Conference in Daegu, Korea, 23 - 27 May 2022.

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Cheniere – Stand 2100

C

heniere provides clean, secure, and affordable energy to the world – energy that can reduce carbon emissions and help lead to cleaner air, while lighting homes and powering factories – all manufactured and transported by modern energy infrastructure, and run by a world-class workforce.The energy Cheniere makes is LNG. The company is the largest producer of LNG in the US, and the second largest LNG operator in the world. Cheniere are a full-service LNG provider.

Cheniere procures gas from the abundant and low-cost US gas market and gives its customers the option to have their cargoes loaded at its facilities or delivered

worldwide. Since exports began in 2016, the company has produced, loaded, and exported over 2000 cargoes to 37 markets around the globe. Cheniere’s facilities are located on the US Gulf Coast, and with nine liquefaction trains in operation, the company produces approximately 45 million tpy. Additionally, it recently signed an engineering, procurement, and construction contract for the Corpus Christi Stage III expansion that could add 10 million tpy to its portfolio.

Cheniere’s headquarters are in Houston, Texas, US, and the company have additional offices around the globe in London, UK; Singapore; Washington D.C., US; Beijing, China; and Tokyo, Japan.

eLichens – Stand 4410

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aced with the increasing number of incidents related to gas leaks in industrial and residential sectors, eLichens, one of the leading designers of gas sensors, has released Avolta, a high-performance connected natural gas leak detector. eLichens has leveraged its patent portfolio, which includes an infrared micro-source, to design Avolta, an optical sensor for methane detection and monitoring that offers unparalleled performance: extremely low power consumption, fast response time, ease of configuration, automatic calibration, and a lifespan of more than 20 years, with near-zero temporal drift.

Avolta operates for more than 10 years on battery power, while providing continuous measurement of the

ambient methane level without any maintenance or intervention.

Avolta is capable of communicating on Milli5 (Itron), LoRaWAN, WIZE, Bluetooth, and NB-IoT standards. Such a diversity of communication protocols is unique on the market and allows a maximum of natural gas distributors to drastically reduce leaks on their networks and contribute to a safer world.

Its performance has been validated by internationally recognised independent laboratories in the gas industry such as the Gas Technology Institute (GTI) in Chicago, US. Avolta helps to avoid false alarms of gas leaks and consequently reduces the cost of interventions (e.g. firemen and gas services).

Emerson Automation Solutions – Stand 4245

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as fields, LNG liquefaction and regasification plants, FLNG vessels, and storage terminals want to reduce emissions, reduce the risk of compressor surge, overpressure, overfill, and LNG roll-over. Other challenges include surprise equipment failure leading to missed shipments. Huge tanks hold valuable products in challenging cryogenic conditions. Greenfield projects want to reduce delays in commissioning and start-up.

New ways of working to solve this include equipment performance monitoring, automatic surge control and overpressure protection, and automatic overfill prevention with remote proof-testing. It is possible to predict equipment failure in real-time for predictive maintenance. Inventory measurements are highly accurate. Device commissioning is automated.

This is enabled by Emerson performance analytics, anti-surge valves, regulators, slam shut-valves, and fugitive emission-compliant pressure relief valves. Radar level measurement technology is robust and virtually maintenancefree with no moving parts. Other solutions include predictive condition analytics, multi-point temperature measurement, ultrasonic flow metering, and smart commissioning.

As a result, plants achieve greater equipment efficiency and reduced emissions, reduced damage and repair cost, greater safety, improved equipment reliability, production uptime, and availability. Thus, operation runs at full capacity.

Accurate inventory management and custody transfer billing are other outcomes. Reduced commissioning time and startup delay allow tight project schedules to be managed.

ExxonMobil – Stand 2300

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xxonMobil has over 40 years of global leadership experience in LNG. The company’s global presence, combined with its ability to leverage expertise across its upstream, product solutions, and

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low carbon solution businesses enables the company to create innovative, integrated lower-emission solutions.

ExxonMobil are positioned to help meet the world’s growing natural gas and power demands.

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55

NexantECA – Stand 4283

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exantECA is the leading advisor to the energy, refining, and chemical industries. The company’s clientele ranges from major oil and chemical companies, governments, investors, and financial institutions to regulators, development agencies, and law firms.

The company’s World Gas Model projects global, regional, and national gas supply and demand balances, international gas trade by pipeline and LNG, and both contracted and spot gas prices. Contract prices are estimated based on projected prices for a basket of escalators including gas hub prices as well as more traditional oil and coal prices. Spot prices are a unique

feature of the model and are estimated with reference to the cost of supply, competing prices, and the ‘tightness’ of the market.

The company has a comprehensive database on gas production, LNG and pipeline infrastructure, trade routes, as well as long-term contracts, storage facilities, and demand projection. All data needed to run the model is supplied by NexantECA, and users are free to add or overwrite the supplied assumptions to construct scenarios of interest to their organisations.

The model currently has an outlook period to 2050 and is balanced on a quarterly basis.

Nikkiso – Stand 4850

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ikkiso Cryogenic Industries’ Clean Energy & Industrial Gases Group consists of five functional units: Cryogenic Pumps (Nikkiso ACD, Nikkiso Cryo), Process Systems (Nikkiso Cosmodyne), Heat Exchanger Systems (Nikkiso Cryoquip), Nikkiso Cryogenic Services (through 18 global facilities), and Integrated Cryogenic Solutions (providing centralised management of products and project development). For over 50 years, Nikkiso has been a leader in the clean energy industry and is leading the change to a healthier world.

Expanding its manufacturing capabilities for the marine market, Nikkiso now provide localised turnkey marine solutions in both Busan, Korea and Hangzhou, China. Nikkiso are the only company offering core

technology components completely in-house, providing fully integrated turnkey fuel system and cargo handling solutions. The company’s localised facilities are equipped to provide design, engineering, and manufacturing – full integration and assembly in-house to deliver marine skids.

This allows for greater quality control and reduced cost while providing full system marine solutions. It also eliminates the need for ocean freighting for shipment delivery, resulting in shorter delivery times.

Service capabilities have also been expanded with additional field service personnel and service offerings, such as long-term service agreements and training.

The company also provides LNG bunkering operations and LNG applications for the marine industry.

Petroliam Nasional Berhad (PETRONAS) – Stand 2900

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ith natural gas playing an increasingly important role in the shift toward a cleaner energy future, having a committed solutions partner that is willing to go the extra mile is necessary in helping a company’s business achieve progress.

PETRONAS Gas Business is a one-stop centre for lower-carbon energy solutions, enabling businesses to grow while creating value for a better and sustainable future.

Through innovation and technology, PETRONAS has developed a suite of natural gas solutions that are customisable and adaptable to meet the company’s partners’ changing needs. From flexibility in pricing

and contracting strategies, down to unique parcel size and delivery methods, PETRONAS has the capabilities and facilities to design and matchmake the right solutions for its customers.

PETRONAS has also pioneered multiple solutions that allow its customers to achieve their sustainability goals, and has implemented efforts to decrease its carbon footprint across its integrated value chain, from production to delivery.

With close to 40 years of industry experience, PETRONAS Gas Business will never stop innovating to put greener futures within reach by continuing to create sustainable value for businesses, societies, and the planet.

Picarro – Stand 4784

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icarro’s gas business enables operators to reduce emissions, improve the safety of their infrastructure, and increase capital efficiency via a patented methodology of advanced leak detection, emissions measurement, emissions reduction, pipeline

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May 2022

replacement, and the award-winning P-Cubed™ software analytics platform. Utilities around the globe rely on Picarro’s decade of detection experience and extensive data lake to provide the most advanced technology in the industry.

Pietro Fiorentini – Stand 4430

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ietro Fiorentini, founded in Bologna, Italy in 1940, is one of the major industrial companies in the North East of the country, with headquarters in Arcugnano, Vicenza, Italy. The Group have approximately 35 locations amongst its manufacturing and commercial sites, both in Italy and abroad, and employ approximately 2500 people worldwide. In 2021, the Group reached a turnover of €466 million, 17% higher than in 2020.

The Group has a solid customer base, including natural gas distribution and transmission companies, oil and gas companies, EPC, utilities, and industrial end users.

At the core of the company’s production is a wide range of

technologically advanced solutions all along the natural gas system: valves, multi-phase meters, process plants, pressure reducing stations, and metering systems.

In the context of the energy transition process, the company has enhanced its efforts to seize the new opportunities related to green energy sources such as biomethane, hydrogen, and power-to-gas. As a result of the recent acquisition of ADD Sinergy, Pietro Fiorentini Group is covering the fields of liquefaction and micro-liquefaction of natural gas and biomethane, with applications in sustainable mobility, thanks to the use of LNG and bio-LNG as fuel, and LNG transportation through virtual pipelines.

Polish Oil and Gas Company (PGNiG) – Stand 4730

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olish Oil and Gas Company (PGNiG) specialises in exploration for, and the extraction of, natural gas and petroleum. Additionally, through its key subsidiaries, the company imports, stores, sells, and distributes gaseous and liquid fuels, and produces heat and electricity. Shares of the company are included in numerous indices, i.e., the largest companies listed on the Warsaw Stock Exchange (WIG-20), entities paying dividends (WIGdiv), and companies deemed socially responsible (WIG-ESG).

PGNiG Capital Group consists of PGNiG S.A., as well as 38 entities directly or indirectly dependent of PGNiG,

including distribution and storage system operators in the gas industry, a company providing gas sale services, a heat and electricity producer, companies providing specialist geophysical and drilling services highly regarded on the foreign markets, as well as a mutual insurance company.

PGNiG S.A. is the sole owner of the Norwegian company Upstream Norway AS in Sandnes, Norway, which specialises in exploration and excavation of the reserves on the Norwegian continental shelf, and PGNiG Supply & Trading GmbH in Munich, Germany, which is involved in the gas trade.

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LNG FUELING NOZZLES*

RELIEF VALVES May 2022

*Industry-standard 18 month warranty

DIVERTERS

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Santos – Stand 4830

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antos is a global, low-cost producer of oil and gas, committed to ever-cleaner energy and fuel production, with operations across Australia, Papua New Guinea, Timor-Leste, and North America.

Santos is committed to being a global leader in the transition to cleaner energy and clean fuels, by helping the world decarbonise to reach net zero emissions in an affordable and sustainable way.

Santos is already Australia’s biggest domestic gas supplier, a leading Asia Pacific LNG supplier, and is committed to supplying critical fuels, such as oil and gas, in a more sustainable way through decarbonising projects such as the Moomba carbon capture and storage (CCS) project.

Underpinned by a diverse portfolio of high-quality, long-life, low-cost oil and gas assets, Santos seeks to deliver long-term value to shareholders. For more than 65 years, Santos has been working in partnership with local communities, providing local jobs and business opportunities, safely and sustainably developing its natural gas resources, and powering industries and households.

As customer demand evolves, Santos will grow its cleaner energy and clean fuels through CCS, nature-based offsets, energy efficiency, and use of renewables in its operations. With a strong, low-cost base business supplying oil and gas, and a clear action plan to develop cleaner energy and clean fuels, Santos remains resilient, value accretive, and at the leading edge of the energy transition.

Sempra Infrastructure – Stand 1750

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empra Infrastructure delivers energy for a better world. Through the combined strength of its assets in North America, the company is dedicated to enabling the energy transition and beyond. With a continued focus on sustainability, innovation, world-class safety, championing

people, resilient operations, and social responsibility, the company’s more than 2000 employees develop, build, and operate clean power, energy networks, and LNG and net zero solutions that are expected to play a crucial role in the energy systems of the future.

Uniper – Stand 2170

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niper is a leading international energy company, with approximately 11 500 employees, operating in more than 40 countries. The company plans for its power generation business in Europe to be carbon-neutral by 2035. Uniper’s approximately 33 GW of installed generation capacity makes it one of the world‘s largest electricity producers. The company’s core activities include power generation in Europe and Russia, as well as global energy trading and a broad gas portfolio, which makes Uniper one of Europe’s leading gas companies.

In addition, Uniper is a reliable partner for communities,

municipal utilities, and industrial enterprises for planning and implementing innovative, lower-carbon solutions on their decarbonisation journey. Uniper is a hydrogen pioneer, is active worldwide along the entire hydrogen value chain, and is conducting projects to make hydrogen a mainstay of energy supply.

The company is based in Düsseldorf, Germany, and is currently the country’s third-largest publicly listed energy supply company. Together with its main shareholder Fortum, Uniper is also Europe’s third-largest producer of zero-carbon energy.

VEGA Instruments Korea LLC – Stand 4420

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EGA Grieshaber KG is a globally active manufacturer of process instrumentation. Its product portfolio extends from sensors for measurement of level, point level, and pressure to equipment and software for integration into process control systems.

Founded in 1959, VEGA today employs more than 1850 associates worldwide. In addition to its headquarters in Germany, the company has 22 subsidiaries, one holding company, as well as 81 agencies in more than 80 countries.

VEGA is a reliable partner for all industries in both technical and economic respect. Because all of them profit

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from VEGA’s philosophy: simplify the application and increase its reliability. VEGA sensors measure the level in process and storage tanks or the pressure in vessels or process pipelines. Production processes in many sectors – in the chemical and pharmaceutical industry, in environmental engineering, in mining, as well as other primary industries, such as oil and gas, as well as in the areas of food production and water/waste water treatment – would be unthinkable without technology from VEGA. The company’s products have all necessary certificates and approvals for worldwide application.

Scott Neufeld, FortisBC, Canada, outlines why the Tilbury LNG facility is so important for Canada’s energy industry, detailing how it differs from other LNG facilities.

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or more than 50 years, FortisBC’s Tilbury LNG facility in Delta, British Columbia, Canada, has been producing and storing LNG to ensure the company’s more than 700 000 customers in the province’s coastal region have the energy they need, even during high winter demand.

Its 18-ha. site, located entirely within an industrial setting next to an international shipping route, is in the middle of an expansion designed to strengthen FortisBC’s gas system and provide more LNG for customers wanting to reduce their carbon footprint. For more than a decade, the Tilbury facility has been providing LNG as a fuel to local transportation customers. It was the first Canadian facility to produce LNG for export to Asia.

Tilbury was initially designed to store energy and deliver it to customers during times of peak demand. Operations teams were trained to jump into action at short notice to send out gas when temperatures dipped, pumping the

needed gas into the system within a couple of hours to maintain service to customers.

As the energy needs of British Columbians have changed, so has Tilbury. The Tilbury facility is now monitored 24/7 so peak shaving is not the event it once was. However, the facility remains a key component of the energy system in Vancouver, British Columbia. For example, gas from Tilbury was sent into the system for six days straight in 2021 when temperatures approached record lows over the Christmas holiday season.

The facility harnesses the strengths of the province’s gas and electric systems to provide homes and businesses across the region with a reliable and affordable supply of energy.

One of the standout features of the facility is the use of electric drives powered by the province’s almost entirely renewable electricity supply. As a result, Tilbury produces LNG with remarkably low carbon intensity.

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How Tilbury differs from other LNG facilities

Tilbury serves multiple purposes, providing a backup supply of energy to the regional gas system and providing lower carbon, clean burning LNG to local and overseas customers for various uses, including marine fuelling.

Tilbury’s LNG benefits from a hydroelectric advantage.

The site is connected to an electric grid that is more than 90% powered by renewable hydroelectricity. As a result, the greenhouse gas (GHG) emissions are approximately 30% lower than a global average for a facility on a lifecycle basis, meaning that Tilbury is producing LNG with a much lower carbon intensity than LNG produced elsewhere. This can be an important consideration for customers who are looking to switch from higher-carbon energy, such as diesel or coal. It is also why LNG from Tilbury is part of FortisBC’s target to reduce customer emissions by 30% by 2030 in support of the provincial government’s CleanBC plan.

Tilbury has had good early successes with local customers in switching to LNG. Two local companies, BC Ferries and Seaspan Ferries Corporation, have added LNG-powered vessels to their fleets with LNG from Tilbury.

These vessels have been refuelling through an onboard truck-to-ship bunkering system. Since 2017, the low-carbon LNG provided by Tilbury has allowed FortisBC’s marine

customers to reduce their GHG emissions by more than 60 000 t.

In late 2021, Seaspan Ferries Corporation became the first Canadian marine company to pilot the use of renewable natural gas (RNG) to reduce GHG emissions produced by its roll-on, roll-off LNG powered marine fleet.

Seaspan expects that data from the pilot will confirm that by using RNG, GHG emissions can be reduced by upwards of 85% vs. traditional diesel fuel.

FortisBC is also continuing to work with partners to advance LNG as a cleaner fuelling option in the Port of Vancouver, one of the largest ports on the West Coast of Canada. A third-party analysis shows that LNG from Tilbury can reduce GHG emissions from shipping by up to 27% compared to conventional marine fuel. The potential emissions reductions are significant, as LNG can also lower emissions of sulfur oxide to almost zero, nitrogen oxide by up to 95%, and particulate matter by up to 99%.

FortisBC sees LNG exports as another opportunity to support emissions reductions. Tilbury’s location on Canada’s West Coast near a deep-sea navigation channel already allows LNG exports to the US by truck and to Asia by ship, with the potential of providing bulk overseas exports in the future. Overseas customers currently take delivery by ISO container, a standard-sized shipping container that can be moved by truck.

Tilbury’s advantages in a competitive global market include closer proximity to Eastern Asia than LNG facilities on the US Gulf Coast, renewable electricity supply, colder climate, and plentiful gas reserves with lower-carbon content that can minimise carbon emissions during the LNG lifecycle. These factors also mean that the carbon intensity of producing natural gas, liquefying, and shipping it is approximately half that of an average facility on the US Gulf Coast, while being more cost-competitive.

Purpose of the facility Figure 1. FortisBC’s Tilbury facility in Delta, British

Columbia, Canada, has been producing and storing LNG for customers since 1971. The facility is located on the Fraser River, an international shipping route, making it ideally located to serve growing regional and global demand for LNG.

Figure 2. Tilbury is powered almost entirely by renewable electricity, which lowers the carbon intensity of its LNG by approximately 30% compared to an average global facility.

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Tilbury’s original purpose was as a peak shaving facility. Its 60 tpd liquefaction unit and 26 000 m3 would liquefy, store, and gasify energy for the coldest winter days when the Lower Mainland’s energy needs were at their highest.

British Columbia’s gas system was put to the test in October 2018 when gas supply was restricted to the Vancouver area for two days following a pipeline rupture in the northern part of the province, upstream of the region.

With the interruption to gas supply, Tilbury was put on notice to do send-out in case it was needed. FortisBC was able to draw on other resources to maintain supply, such as gas stored underground in the US and customers curtailed their gas use, but this emergency underlined the importance of strengthening the resiliency of the Lower Mainland’s gas supply – something FortisBC was well aware of and had already started to prepare for.

In 2014, FortisBC broke ground on a multi-phase expansion project at Tilbury to address both the need for added gas system resiliency and customers’ desire to switch to lower-carbon fuel alternatives such as LNG.

Phase one expansion

The first part of the phase one expansion project was completed in 2018. Its additional storage tank and liquefaction equipment are helping to meet the needs of

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transportation customers. The Tilbury facility currently fills more than 1000 LNG containers from its two loading bays for transport and overseas customers every year.

A CAN$18.5 million truck loading expansion that is set to go into construction will add two more loading bays to double the facility’s capacity to serve those customers.

The remaining components of the planned phase one expansion are intended to serve the growing demand for LNG as a marine fuel by further enhancing liquefaction capacity.

The Tilbury facility’s location – 11 nautical miles from the British Columbian coast, along an existing deep-sea navigation channel on the Fraser River – makes it possible

to serve marine customers interested in LNG as a lower-carbon alternative fuel to diesel or bunker oil.

Phase two expansion

The next proposed phase of expansion will serve a dual purpose. An additional, larger storage tank would provide a source of backup energy supply to the metro Vancouver region to strengthen the resiliency of the company’s gas system to withstand an emergency; and additional liquefaction equipment would produce more LNG to help both regional and international customers switch from higher carbon fuels such as diesel or coal.

If all the LNG produced by the phase two expansion was used to displace coal, the emissions reductions would be equivalent to removing 1.5 million cars off the road each year, or roughly all of the passenger vehicles in the metro Vancouver area, marine bunkering, and overseas as of 2020.

The proposed phase two tank and liquefaction expansion is currently in the environmental assessment process led by the British Columbia Environmental Assessment Office.

The marine jetty

Figure 3. In 2014, FortisBC broke ground on an expansion project to meet increasing local demand for LNG as a transportation fuel.

With Tilbury’s close proximity to the Pacific Ocean and the deep-sea navigation channel on the Fraser River, which is already used as an international shipping route, the Tilbury marine jetty – which is proposed by affiliates of Fortis and Seaspan – is the next step to prepare for marine bunkering and overseas export. The jetty would include two berths: one for loading LNG onto refuelling vessels and one for loading LNG onto carriers for bulk shipments.

The future of the facility

Figure 4. Tilbury fills more than 1000 containers of LNG each year for local and international customers.

Figure 5. BC Ferries is one of two local companies that is powering its fleet with LNG.

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The expansion of Tilbury supports FortisBC’s target to reduce its customers’ GHG emissions by 30% by 2030. Beyond 2030, FortisBC has an important role to play in helping British Columbia move to a low-carbon future. As part of the company’s vision, it is developing Tilbury so that it can serve the future energy needs of British Columbians while also meeting ambitious GHG emissions reduction targets.

The phase two expansion of Tilbury alone, if approved, would be one of the largest capital projects in the region with a capital cost of CAN$3 - CAN$3.5 billion, providing an important source of revenue for the government, as well as jobs for the industry. The expansion would also create employment and contracting opportunities during planning and construction, and approximately 110 long-term jobs once construction is complete. Economic benefits from the project will be distributed throughout British Columbia – not only in the LNG industry, but also to the industries that support it, such as manufacturing, engineering, and professional services.

But FortisBC cannot deliver projects such as these alone.

The company is seeking to build effective and long-lasting relationships with Indigenous communities. It has also been consulting with the government, the public, and other parties on the expansion of the Tilbury LNG facility since 2012. FortisBC will work with interested parties throughout the environmental assessment process, while ensuring that Tilbury meets the company’s sustainability focus of prioritising the health and well-being of customers, communities, the environment, and employees, both today and into the future.

Karthik Sathyamoorthy, President LNG Terminals and Logistics, AG&P Group, Singapore, explores how transitioning to different energy sources, such as LNG, can help emerging economies advance by providing more stable and reliable power supplies.

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he advent of flexible and scalable regasification technology has bolstered the growth of global LNG trade, providing the avenue to fast-track LNG imports across wider, more diverse geographies.

Combustion of natural gas generates approximately 30 - 45% less CO2 than fuel, oil, and coal, delivering a twofold reduction in NOX, as well as not emitting any soot, dust, or fumes. Natural gas power allows for the expansion of renewable energy on the grid by providing the needed stability that renewable power requires.

Moving towards cleaner fuels

Senegal, Indonesia, and the Philippines are fast-growing economies who are embracing regasification technologies, enabling them to accelerate LNG imports to transition away from dirtier fuels.

Recognising these environmental benefits, the government of Senegal rolled out a gas-to-power strategy in November 2018 that will see natural gas introduced into the country's power generation mix for the first time.

The strategy is part of a master plan tabled before the World Bank in 2019, which is expected to cut greenhouse gases (GHG) emitted from Senegal’s power sector by over 1 million t of CO2 equivalent.

The plan proposed to phase out the use of heavy fuel oil by 2025, displacing the dirty fossil fuel primarily by gas with a 54% projected share by 2026, followed by renewables on 31%.

The African country now strives to stabilise its power grid, having spent more than a decade aggressively ramping up its renewable power capacity. And commercially-viable storage technologies on a large scale remain elusive. Gas achieves this balance.

Figure 1. Aerial view of hybrid Philippines LNG (PHLNG) import terminal at Ilijan, Batangas Bay, the Philippines.

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This pivot towards gas-fired power generation builds on the promise of Senegal eventually being able to draw on its share of gas supply from two upstream projects that are under development – the bp-operated Greater Tortue Ahmeyim Project and Woodside Energy’s Sangomar Field. These will be the first producing gas projects that will come online within Senegal’s territorial waters.

However, Senegal cannot afford to wait on the switch to gas-fired power generation. Prior to the COVID-19 pandemic, Senegal’s economy expanded at an annualised rate of more than 6% between 2014 and 2018. To resume the pre-pandemic growth trajectory would call on the energy-hungry African nation to address rolling blackouts which afflicted its capital city, Dakar, urgently. Thus, Senegal needs to establish infrastructure to domestically transmit and distribute the gas output from the two offshore fields.

The World Bank has supported Senegal’s bid to pursue gas-fired power generation to supplement intermittent renewable power supply, with the aim to provide both clean and lower-cost energy for this vibrant, growing economy.

It came as no surprise, therefore, that Senegal has gone with a converted FSRU to accelerate the roll-out of a gas economy. The regasified LNG will go towards substituting fuel oil, firing up a floating power plant, supplying 15% of its

Figure 2. Karmol LNG carrier conversion with Gas Entec Regastainer® – the world's first modular FSRU.

Figure 3. The 26 000 m3 FSRU, Karunia Dewata, in Bali, Indonesia.

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electricity requirements, with a profound benefit to local health.

Converted FSRUs

Karmol, the joint venture between Turkey’s Karpowership and Japan’s Mitsui OSK Lines, was selected to supply a converted FSRU to regasify the imported LNG. The joint venture contracted AG&P’s subsidiary Gas Entec to convert the 125 000 m3 Moss LNG carrier into an FSRU, a project that was completed in 10 months and within budget.

The converted Karmol FSRU called LNGT Powership Africa delivered from Sembcorp Marine in Singapore arrived in Senegal in late 2021. The vessel, equipped with two GET modules of combined regasification capacity of 84 million ft3/d called Regastainers®, will be connected to the Karadeniz Powership Aysegul Sultan, enabling the 114 MW floating power plant to switch to regasified LNG from June 2022.

The overall capital outlay came in at less than half the cost of a new-build FSRU. Converted FSRUs, in general, provide a low-cost entry to develop LNG import capacity, with the flexibility of scaling up to larger, new-build regasification terminals when the need arises.

Thousands of miles away from Dakar in Bali, Indonesia, a new-build FSRU has embarked on its fourth year of operation.

The new-build FSRU, Karunia Dewata, owned by Indonesia incorporated JSK Shipping, set sail in late 2018 on delivery from the Paxocean yard in China for the Benoa port in Bali, where it subsequently replaced an FRU called the Lumbung Dewata.

JSK Shipping chose initially to bring in an FRU to speed up supply of regasified LNG to a 200 MW power plant at Benoa also converting from fuel oil.

Like Dakar, Bali grappled with power outages that were disrupting its thriving tourism sector prior to the COVID-19 pandemic.

The construction of a barge-based FRU, awarded to AG&P Gas Entec, was completed within a compressed schedule of 10 months from the time of the contract, reflecting the urgency of bringing the project online quickly to resolve Bali’s energy woes.

The FRU Lumbung Dewata started out in its early days importing cargoes shipped from the Bontang LNG plant using small LNG carriers in Indonesia’s East Kalimantan province. The Bali LNG import project is part of a larger, nation-wide virtual pipeline network being developed to supply domestically produced gas to demand centres across the sprawling archipelago made up of over 17 000 islands.

The project has scaled up rapidly, supported by visibility over supply and demand. In early 2017, JSK Shipping placed an order for the new-build FSRU, Karunia Dewata, that subsequently came online in late 2018.

AG&P Gas Entec led the design of the FSRU from scratch and played a key role in the project management of the build in conjunction with Paxocean, which was completed in 26 months.

Senegal and Indonesia have taken the stand that accelerating LNG imports is a sustainable avenue to secure energy needed for their growing economies while achieving

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important emission reductions and better health for their citizens.

Natural gas is the transition fuel that emerging economies across Asia, Africa, and South America can count on to support their net zero transitions. Globally, regasification grew 40.8 million t in 2021 – the largest increase in 10 years – and looks set to further expand with the Philippines, Ghana, Vietnam, Nicaragua, and El Salvador, among others, named as countries linking to global LNG supplies.

No one size fits all – regasification technologies must evolve to support the rapid expansion of LNG’s geographical footprint.

The first terminal coming online in the Philippines has adopted a different approach from the FSRU-based projects in Senegal and Indonesia, taking in varying operating environment and gas user profiles in the country.

AG&P, developer, owner, and operator of downstream LNG/NG ecosystem, have pursued a hybrid design, building in redundancies to mitigate disruption from frequent typhoons passing through the area. The onshore terminal in Batangas Bay, the Philippines, comes with a much larger capacity of 5 million tpy and is due to enter operation in 3Q22.

Construction is underway onshore on two tanks, each equipped to store 60 000 m3 and a regasification facility of 504 million ft3/d. These will be supplemented by a leased FSU of 137 000 m3. AG&P Gas Entec will execute the conversion of the FSU from an LNG carrier chartered from ADNOC Logistics and Services.

Development of the onshore infrastructure takes onboard the multi-sectoral profile of the end users for regasified LNG. The terminal will go beyond securing baseload supplies for

two power plants of 2500 MW at Ilijan, Batangas Bay, to meet demand from transport, industrial, and residential sectors on Luzon, the most populated island in the Philippines, and beyond. Thus, the terminal called PHLNG will cater to the re-loading of LNG in break-bulk volumes and bunkering of LNG-fuelled marine vessels.

PHLNG will ward off energy security risks stoked by Malampaya, the country’s primary gas field, which can no longer be counted on as a reliable supplier. In recent years, the drastic gas supply decline from Malampaya has compromised output from five power plants once meeting 20% of local demand.

The capacity of the Ilijan power plant was derated by 484 MW in 2020. AG&P’s PHLNG terminal is taking the lead in providing the fuel required to meet demand and eliminate brown-outs which were commonplace pre-COVID-19.

The Philippines is also counting on LNG imports to accelerate a coal-to-gas switch, as coal is contributing the bulk of power output today. This means additional clean gas projects for the country, balancing a major surge in renewables, achieving the country’s goals.

LNG paving the way to renewables

LNG is coming of age and breaking through as the fossil fuel choice for net zero transition in Senegal, Indonesia, and the Philippines, as well as other emerging economies.

The unique conditions of each market will press on the need to identify creative technical and business solutions as the LNG supply chain develops, offering new or underserved markets the opportunity to reduce pollution, expand renewables, and decarbonise quickly and responsibly.

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Margaret Greene (USA) and Tobias Eckardt (Germany), BASF, and Patrick Peters and Javed Adam (Trinidad and Tobago), EG LNG, discuss how new materials and bed designs can solve molecular sieve degradation issues and increase LNG production.

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o achieve efficient production of LNG, natural gas must be dehydrated to cryogenic dew points.

For decades, molecular sieves have been used to accomplish this critical ask. However, standard molecular sieve dehydration can cause significant challenges to operations, including increased pressure drop and short lifetimes; both of which have a negative impact on the profitability of the plant by reducing throughput and increasing plant downtime.

BASF has taken an innovative approach to natural gas dehydration for LNG production by challenging the conventional wisdom of relying on molecular sieve.

The temperature swing adsorption (TSA) process creates a harsh environment that causes regeneration reflux and retrograde condensation in some services. These conditions cause standard molecular sieve to degrade and decrease in performance over their typical service life. To reduce the rate of degradation of performance, BASF applies a more robust aluminosilicate gel material. This material is resistant to the physical effects experienced in the dehydration vessel and can remove bulk water, adding to the overall capacity of the bed.

This article will describe the first retrofit installation of Durasorb Dehy in dehydration service in LNG

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pre-treatment at Equatorial Guinea LNG (EG LNG). EG LNG was experiencing some of the common challenges associated with standard dehydration beds, including liquid carry-over and regeneration reflux. This environment caused molecular sieve degradation, pressure drop increase, and premature failure of the molecular sieve bed. To address these issues, BASF employed an innovative bed design using specially developed molecular sieves to solve these problems and double the bed life. This article will describe the innovative dehydrator bed design employed at the EG LNG plant to

Figure 1. Time-based, multi-dimensional model. Capacity of 1.0 represents saturation.

achieve this extended lifetime, which resulted in one less change-out of material over a four-year period and improved operation of the dehydration unit. Implementing the Durasorb Dehy solution establishes EG LNG as an early adopter of new technologies, willing to explore opportunities to optimise plant performance.

Operational performance

Operational availability is a key metric used by EG LNG to track its performance over time. It is a function of both planned and unplanned downtime. EG LNG’s average reliability between 2010 - 2017 had been greater than 99%, or less than 1% unplanned downtime, demonstrating performance in excess of the industry benchmark of 98%.

For the same period, the average operational availability was 97.1% once planned downtime was incorporated.

As equipment reliability was already high, EG LNG sought further improvements in operational availability through the reduction of planned downtime. One area of opportunity identified was to address the accelerated degradation of the dehydrator beds in the front-end of the plant that had been experienced historically. Free liquid carryover from upstream separation equipment and regeneration reflux within the vessels led to bed replacements after two years, compared to typical adsorbent life expectancy of four years.

With bed replacement requiring operation at half-rate, approximately 1.2% additional planned downtime and a cost of approximately US$975 000 (materials and labour) was incurred every two years. As such, EG LNG commenced an investigation into solutions to extend the life of the beds without major capital investment or having to completely shut down the plant. Extended bed life would result in less planned downtime, increased operational availability by 1.2%, more LNG production over a specified timeframe, and reduced operating expenses through less frequent replacement.

Problem identification

Figure 2. Durasorb Dehy layered bed design.

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EG LNG is supplied with lean natural gas from an upstream NGL extraction facility. The flow rate is nominally 620 million ft3/d at 71 bar, and the target H2O content exiting the dehydrator is <0.3 ppmv.

To identify the optimal solution for EG LNG, BASF performed time-based, multi-dimensional modelling of the molecular sieve bed under normal regeneration conditions to give a detailed look at the conditions inside the dehydrator during regeneration. An example of the output from such analysis is shown in Figure 1. This plot shows the theoretical capacity of the adsorbent for water under the transient conditions of a regeneration gas thermal wave passing through the bed. A capacity of 1.0 represents saturation of the adsorbent. Capacity >1.0 therefore reflects super-saturation leading to localised condensation. The results show that as the regeneration gas moves through the bed and contacts colder environments (e.g., adsorbent, vessel walls) in the middle to upper part of the bed, the ability of the upper bed to adsorb moisture from the regeneration gas becomes exceeded. At this point, condensation occurs, and liquid water is formed in the bed. The regeneration gas continues to be pushed through the bed, entraining liquid

water and leading to a boiling effect, commonly known as refluxing.

If the adsorbent would be stable under such conditions, there would be no problem, as ultimately the saturated regeneration gas will exit the adsorber, and the saturated gas is cooled to condense the water in the regeneration gas separator. However, molecular sieve adsorbents are not completely stable under these conditions. Molecular sieves, whether beaded or extruded, are typically formed with a clay binder. It is this clay binder that is attacked by the condensing water, leaching the binder from the adsorbent material and causing two main effects: zz Deterioration of the adsorbent strength. zz A caking effect as the leached binder is precipitated back onto the exterior of the bead.

A two-pronged approach

The Durasorb Dehy technology addresses the issues caused by degradation of molecular sieve in reflux environments with a two-pronged approach: bed designs and specialty materials. A Durasorb Dehy bed is a combination of two BASF adsorbents: Durasorb HD, loaded at the top of the bed, and Durasorb HR, loaded at the bottom of the bed (Figure 2). Durasorb HD is a water-resistant aluminosilicate gel adsorbent, which protects the more sensitive molecular sieve section from incidental liquid carryover. Durasorb HR is a reflux resistant molecular sieve adsorbent which has been developed to withstand harsh conditions that exist with cycling in temperature swing adsorption systems.

The bed design leverages the adsorption properties of each Durasorb product. Durasorb HD has high water uptake capacity at high inlet moisture conditions and Durasorb HR has high water uptake capacity at low moisture conditions (Figure 3). This bed design results in better overall adsorption capacity for the dehydration bed.

Durasorb HD works as both a protective layer for the molecular sieve and as an active adsorbent layer removing bulk water.

Durasorb HD aluminosilicate gel by itself is an extremely robust adsorbent with a very high equilibrium uptake capacity. However, it is not typically employed in applications in which a very low water dewpoint is required, i.e. by a cryogenic LNG unit. Therefore, the combination of the two types of materials in series has been utilised for the optimum combination of dewpoint and durability required in this service.

The advantages of adding a high-capacity adsorbent on top of a molecular sieve bed can be seen after a further model run (Figure 4). The calculated super-saturation of the regeneration gas is shown to be significantly reduced. This is not a result of lower moisture content in the regeneration gas, but rather it reflects the higher capacity of the aluminosilicate gel adsorbent. Of course, a standard silica gel would also show the same benefits of high capacity, but it is the superior physical characteristics (i.e. robustness and water stability) reducing the rate of degradation of Durasorb HD which allows such a design to be considered.

Based on computer modelling of regeneration reflux and simulation of bed performance, BASF technologists proposed a solution to the short dehydration bed

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lifetimes experienced by EG LNG, which was a dehydration bed consisting of 30% Durasorb HD in the upper section of the bed and Durasorb HR in the lower section of the bed. To minimise COS formation, Durasorb HR3 was chosen as the molecular sieve. In addition to reducing the degradation mechanisms associated with regeneration reflux, this bed configuration would provide resistance to liquid carry-over events, increasing the lifetime of the material.

The solution proposed by BASF was evaluated and accepted by EG LNG, and, after working together on an implementation plan, the new Durasorb material and bed design was implemented in January 2018. Installation was a simple exchange of adsorbents with no modifications to the internal structure of the vessel necessary.

Operation before and after bed design solution

Prior to the installation of Durasorb, EG LNG operations were on a two-year turnaround cycle for the dehydration

bed adsorbent material before water breakthrough.

The uniquely harsh conditions caused by free liquid carryover in combination with regeneration reflux led to a rapid decline in bed performance and degradation of the molecular sieve after only 500 cycles. In addition, an uneven decay of the molecular sieve in the three individual adsorber towers caused an uneven distribution of bed pressure drops and an unbalanced flow distribution, further adding to operational issues.

The current experience by EG LNG with the BASF Durasorb solution has mitigated the previous causes of accelerated bed failure. Durasorb HD provides a safe space in the bed for regeneration reflux to occur, protecting the molecular sieve. Utilising a water-stable adsorbent in the top 30% of the bed alleviates the uneven decay observed in the three beds, eliminating the uneven pressure drop and unbalanced flow distribution.

After installation, BASF technologists worked closely with EG LNG to further optimise the regeneration cycle and ramp time to ensure refluxing takes place in the water-stable Durasorb HD layer, where no damage to the adsorbent can occur. The dehydrator continues to operate on longer adsorption cycle times compared to the previous adsorbent used at EG LNG, illustrating additional bed capacity. Now at the four-year mark, the novel Durasorb bed configuration has been cycled 800 times and still has an overall bed capacity of 11 Wt% for water uptake. With this bed capacity and extended cycle times, EG LNG operations expects one more year of service and expects to replace the beds in early 2023 in conjunction with other planned activities. When replaced in 2023, Durasorb will have undergone 1100 cycles and performed to meet LNG water specifications for five years.

Conclusion Figure 3. Adsorption capacity of Durasorb HD and Durasorb HR at increasing Wt% water.

Figure 4. Time-based, multidimensional model showing reduced levels of saturation in the bed. Capacity of 1.0 represents saturation.

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BASF has developed an approach to the dehydration of natural gas for LNG production which employs superior materials and unique bed designs. This approach utilises a more robust, high capacity, water stable aluminosilicate gel adsorbent to protect the molecular sieve from the typical degradation pathways. Utilising the Durasorb Dehy approach has been shown to significantly increase bed life and decrease turnaround frequency, thereby increasing the overall throughput of the plant.

Although consistently exceeding industry reliability benchmarks, EG LNG continued to look for cost-effective ways to optimise production. Working closely with BASF allowed the two teams to develop a custom-tailored solution, optimised for the EG LNG plant, while utilising the equipment already in place and avoiding a complete plant shutdown.

Over a four-year period, EG LNG gained five full production days, improved on its operational availability metrics, and significantly reduced its operating expense by reducing the frequency of bed replacements. The bed life extension to-date has allowed EG LNG to reduce its planned downtime by five full production days, increase its 2020 operational availability from 97.3% to 98.5%, and avoid the operating expenses associated with bed replacement. Implementing the Durasorb Dehy solution further solidifies EG LNG’s reputation as one of the most reliable operators in the world.

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PETRONAS Gas Business believes in a cleaner tomorrow.

To make these aspirations a reality, we need the right partnership. Placing sustainability first is fast becoming a license to operate for many businesses and a prerequisite to remaining relevant. It is no longer just about powering operations, but also creating lasting and positive impact.

The question is, how exactly do we achieve that? The answer lies in an energy solution that meets the growing needs of today while cradling the needs of tomorrow – natural gas. Cleaner, versatile and extremely capable, natural gas is the ideal choice for businesses’ energy needs as we transition towards a lower carbon energy future.

PETRONAS Gas Business can enable that switch seamlessly, hence the need for a long-term partner to embark on this journey with us.

As a lower carbon energy solutions partner, PETRONAS Gas Business goes above and beyond to meet the unique needs of customers big and small through innovative solutions. With over 40 years of industry experience and a diverse global portfolio, we are a world-renowned liquefied natural gas (LNG) player with a track record of success.

Since then, we have forged many enduring partnerships across the globe – growing to become one of the world’s largest suppliers of natural gas, with over 12,000 shipments of cargo delivered to date.

Over the span of four decades, this customer-centric approach has led us in providing industries and businesses with a reliable supply of cleaner energy to power their growth sustainably. Our customers and their needs always come first. Be it flexibility of pricing or contracting strategy, customisation of parcel size or delivery methods, we have the capabilities and facilities to design the right solutions just for you.

What sets us apart from the rest are the various pathways and actions towards decarbonisation, particularly our production plants with hydroelectricity and delivering carbon neutral LNG to customers.

We also have our upcoming efforts including LNG Canada, which will be one of the world’s greenest LNG plants. That is why PETRONAS Gas Business will never stop innovating to put better futures within reach, by continuing to create sustainable value for businesses, societies and the planet.

#PartnerWithUs

We’re the ideal partner because we: Customise solutions to meet your unique challenges Care for the environment Help achieve a cleaner future Prioritise your needs and ambitions as our own Innovate and are technology experts Commit to long-term partnerships

We take pride in our extensive LNG solutions and technology, which include investing in exploration, production as well as innovating industry first floating LNG solutions. At the same time, we are also building on infrastructure such as LNG plants, ISO tank facilities and more to deliver added value through collaborations that reward everyone. We’ve also grown to be an established player in the clean and renewable energy space – a zero-carbon emission solution that complements LNG perfectly. These efforts collectively help businesses lower their carbon footprint, bringing them closer to achieving their own Environmental, Social and Governance (ESG) goals.

Dr Matthew Hammond, EffecTech, UK, outlines the difficulties that come with measuring LNG, detailing how the calibration of spectroscopic instruments helps to make gas measurement more accurate.

L

NG is traded on the basis of total energy, which requires the volume of LNG as well as calorific value (CV) and density, both of which are calculated from the LNG composition. Traditionally, composition is measured by vaporising a sample of LNG and subsequent analysis by gas chromatography (GC).

The vaporiser must be set up correctly otherwise the LNG sample could fractionate, resulting in a change in composition, leading to errors in the measured composition and physical properties, including CV and density. These errors propagate through to the calculation of total energy, meaning increased financial risk for both

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buyers and sellers. Spectroscopic methods have emerged as an attractive alternative to vaporiser-GC systems, as they measure the LNG composition directly without the need to sample and vaporise. However, in order to calibrate these instruments, traceable calibration artefacts that are representative of LNG are required.

EffecTech has developed and validated an LNG production facility which produces LNG of known composition with defined uncertainty that is traceable to the SI unit of amount of substance, the mole. This facility has been used to calibrate a variety of optical instruments whose measurements are now traceable through ISO 17025 accredited methods.

Table 1. EN 12838 criteria for select physical properties

Background

Property

EN 12838 criteria

Gross calorific value (GCV), continuous (kJ/kg)

9

Gross calorific value (GCV), intermittent (kJ/kg)

54

Gas density (kg/m3)

3 X 10-4

Liquid density (kg/m3)

0.15

Calculation

ISO 69766

ISO 65787

Table 2. EffecTech’s ISO 17025 scope of accreditation for LNG analyser calibrations Reference gas range (%mol/mol) Component

Minimum

Maximum

nitrogen

0.1

1.8

methane

79.0

100.0

ethane

0.1

14.0

propane

0.02

4.0

iso-butane

0.02

1.3

n-butane

0.02

1.3

iso-pentane

0.01

0.16

n-pentane

0.01

0.16

Figure 1. Temperature and pressure profile for condensation.

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Around the world, more and more countries are adopting net zero emissions targets, and natural gas is projected to play a significant role in reducing emissions. Natural gas is seen as a suitable alternative to coal or oil during the transition to renewable energy sources due to the lower emissions relative to coal and oil.

LNG is natural gas which has been processed and liquefied by cooling to -160˚C. The resulting liquid occupies 600 times less volume than the natural gas and is therefore economically viable for transportation via ships. This opens up the natural gas market, allowing gas to be traded between areas where pipelines are not feasible.

Global LNG trade volumes have grown y/y since the early 1970s. LNG trade grew marginally to 360 million t in 2020, despite the COVID-19 pandemic, and demand is projected to grow to approximately 700 million t by 2040. 1 LNG is typically vaporised again and injected into gas transmission networks for use in heating, industry, and power generation.

More recently, LNG has been used as a transport fuel as a replacement for marine fuel oil in cruise ships and ferries, or replacing diesel in heavy goods vehicles (HGVs).

Like natural gas, LNG is traded on the basis of total energy, calculated from volume (flow metering), CV, and density (both determined from composition). Natural gas composition is typically measured by sample analysis using GC. Chromatography is a well-established technique, and instruments can be maintained and

calibrated easily. Current best practice for LNG composition measurement for custody transfer applications requires vaporising a sample of LNG and analysing the sample using GC.2 Whilst the performance of the instrument itself can easily be assessed, the vaporiser must be set up correctly to ensure a representative sample is delivered to the instrument. The LNG sample must remain in the liquid phase right up to the vaporiser. If too much heat enters the sample line and/or sample subcooling is insufficient, pre-vaporisation can occur and the sample can fractionate. This means the vaporised sample may not be representative of the LNG stream, leading to errors in the measurement which propagate to the calculated physical properties including CV and density, which are used to calculate total energy.

The vaporiser can therefore lead to increased financial risk in LNG custody transfer if improperly set up.

Recently, spectroscopic analysers have emerged as an alternative solution to vaporiser-GC systems. The 2021 edition of the LNG Custody Transfer Handbook describes some of the recent testing into Raman spectroscopy for LNG composition measurement.2 The advantage of these instruments is that they offer fast response times and in situ composition measurement, avoiding the need to sample and vaporise the LNG. However, as spectroscopy is not a primary measurement, calibration of these instruments is required to ensure they are sufficiently accurate. Calibration requires traceable reference liquids which resemble the LNG process stream to be measured by the instrument i.e., similar composition and physical

state (temperature, pressure). EffecTech has developed a facility in which cryogenic reference liquids can be realised and used to calibrate direct measurement analysers for LNG, providing traceability and measurement confidence to end users. EffecTech is accredited to ISO 17025 for the calibration of LNG analysers by the United Kingdom Accreditation Service (UKAS).

Calibration of spectroscopic instruments for LNG measurement

EffecTech specialises in gas measurement, and provides high-quality, traceable calibration gases with the lowest commercially available uncertainties. EffecTech is accredited by UKAS against the requirements of ISO 17025 for calibration and ISO 17034 for reference materials.3 The calibration gases are prepared accurately by gravimetry whereby pure components are weighed individually before being added to the gas cylinder. Once all of the components have been added, the cylinder is homogenised and the composition is calculated and the mixture verified by analysis as required by ISO 6142.4 The newly prepared mixture is then calibrated using GC with traceable gases from National Measurement Institutes (NMIs) to establish traceability to the mole, the SI unit of amount of substance according to ISO 6143.5 In order to calibrate LNG analysers, a cryogenic reference liquid with known composition is required.

EffecTech has developed a facility for liquefying calibration gases in a bespoke cryostat which accepts optical probes used by spectrometers. Cooling is provided

BOG management for Maritime LNG Two concepts: Direct Reliquefaction or Subcooling

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by liquid nitrogen heat exchangers and the system is vacuum insulated to minimise heat influx from the surroundings. The liquid temperature can be controlled by adjusting liquid nitrogen flow and heating elements in the sample cell. The sample cell temperature is set to below the bubble point of the gas mixture in order to condense the gas as it is transferred into the cryostat.

A primary reference gas mixture (PRGM) is used, as these have the lowest commercially available uncertainties in amount fraction. Normally, the temperature is set to between 90 and 110 K to provide enough subcooling and ensure all components remain in the liquid phase. Approximately 450 g of gas is condensed, resulting in 1 l of liquid. Once condensed, the temperature can be maintained within 0.1 K of the target temperature (Figure 1).

The liquid composition must be verified analytically to ensure the composition has not changed during the condensation process. To do this, a small amount of liquid is sampled and vaporised then analysed using GC. However, as the liquid is subcooled, the vapour pressure is less than ambient pressure, therefore helium is used to pressurise the sample to approximately 1.5 bara. This forces liquid through the sample system. Helium is used

as it is relatively insoluble in LNG and is also used as the carrier gas in the GC so does not interfere with the measurement.

Data is collected from the spectrometer, normally over an extended period, to assess repeatability and accuracy.

Data can be collected over a range of temperatures and pressures, if required, as some customers have varying operating conditions. The average composition measured by the instrument is compared to the verified liquid composition. Additionally, various physical properties calculated by the instrument are compared to the physical properties of the reference liquid against the requirements of EN 12838 detailed in Table 1.6 This standard describes the testing requirements for LNG, sampling systems involving vaporisation of a sample. A certificate of calibration is produced which shows the difference in composition and CV. Seven mixtures covering a range of LNG compositions have been verified using the above methods, proving the cryostat is a good facility for producing accurate, stable, and traceable reference liquids for calibrating LNG analysers. The range of components to which EffecTech is accredited to ISO 17025 is shown in Table 2. The composition can be tailored to match the LNG composition that the instrument is expected to see during operation.

Summary

Since its inception, a range of different spectroscopic instruments designed for in situ LNG measurement have been calibrated using the cryostat, providing traceability and measurement confidence to end users.

The facility is also ideal for providing representative data to OEMs for development of chemometric models. In the future, a new portable cryostat could be designed which can be taken to site and used to calibrate instruments without having to send them to EffecTech’s laboratory.

References 1. Royal Dutch Shell, 'Shell LNG Outlook', 2021.

2. GIIGNL, LNG Custody Transfer Handbook, 6th Edition, 2021.

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3. ISO 17025:2005 General requirements for the competence of testing and calibration laboratories.

4. ISO 6142:2001 Gas analysis – Preparation of calibration gas mixtures – Gravimetric method.

5. ISO 6143:2001 Gas analysis – Determination of composition and checking of calibration gas mixtures – Comparison methods.

6. EN 12838:2000 Installations and equipment for LNG – Suitability testing of LNG sampling systems.

7. ISO 6976:1995 Natural Gas – Calculation of calorific values, density, relative density, and Wobbe Index from composition.

8. ISO 6578:1991 Refrigerated hydrocarbon liquids – Static measurement – Calculation procedure.

Hans-Peter Visser, ASaP B.V., the Netherlands, considers how to measure and sample LNG in a cost-effective and accurate way to make sure every Btu counts.

J

ust Google ‘LNG sampling and analysis’ and there will be a list of companies stating they can sample and measure LNG accurately. The main question is: how do you test it? And once it has been tested with a factory acceptance test (FAT) or a site acceptance test (SAT), how can it be ensured that the measuring results remain as accurate as initially intended?

Given the current global situation and energy prices, this topic has a higher financial impact than ever.

Reuters reported on 4 March 2022 that “Asia LNG spot prices hit a record high of more than US$59/million Btu, tracking a surge in European gas prices on concern over tight supply after Russia’s invasion of Ukraine.

Price agency S&P Global Commodity Insights’ Japan-Korea-Marker (JKM), which is widely used as a spot benchmark in the region, climbed to US$59.672/million Btu on Thursday, its data showed.”1

It all starts at the beginning

In general, good measurement starts at the beginning, taking a representative sample off from the process stream by means of a sample take-off probe.

Due to its cryogenic

77

characteristics, good and reliable sampling of LNG is a whole different ballgame.

It all started at the third (L)NG analytical workshop, ‘Custody Transfer And Quality Assurance’ held September 2007 in Bintulu, Malaysia, jointly organised by Shell Global Solutions and Malaysia LNG. During the workshop, the feedback from nearly all LNG end users was the lack of a reliable way of sampling and measuring LNG. During this workshop, the idea arose to create a completely new design for a combined LNG probe/vaporiser, eliminating all shortcomings and elementary errors of the existing equipment.

Meanwhile, many technical articles and lectures have been dedicated to this most important subject. In a nutshell, it comes down to the following: The natural gas which is processed prior to liquification consists mainly of methane. Depending on the source of the explored natural gas, the heavier hydrocarbons such as

ethane, propane, butane, pentane, and even hexane may vary in their composition. Often some nitrogen is also present.

During processing and liquification, LNG is produced as a liquid hydrocarbon mixture with a typical boiling point of -162˚C or -260˚F at atmospheric conditions.

During (un)loading and custody transfer of the LNG, the energy content and density of the LNG must be almost constantly sampled to dedicated cylinders and continuously measured as per most common sales and purchase agreements (SPAs). The composition of the LNG is typically measured by an online gas chromatograph (GC), derived from the composition of the physical properties such as calorific value (Btu value), density, etc. of the gasified LNG are determined. In general, an online GC gives a measurement update between 3 and 15 min.

The most crucial and critical part of the measurement is the sampling. Specifically, at the point where the LNG sample is taken from the LNG transfer line and transported to an analytical vaporiser. In the vaporiser, the LNG must be converted into a stable and homogeneous hydrocarbon gas mixture which represents the LNG at the time it passes to the transfer line.

The process of sample taking and vaporisation of LNG is continuous and instantaneous.

Often the correct measures are not taken when transporting the LNG to the vaporiser. Due to the large temperature difference between the LNG and the ambient temperature, the LNG tends to start boiling uncontrollably before it reaches the vaporiser. This is also referred to as pre-vaporisation.

Unfortunately, it is still often the case that, for commercial reasons, cheaper vaporisers are used that are not designed for LNG. This therefore results in non-homogeneous and non-uniform vaporisation, also known as pre- and partial evaporation.

Figure 1. Typical LNG production plant.

The results of pre- and partial vaporisation measured by a cyclic measurement such as a GC results in measurement trends which are all over the place or erratic reading. Examples of more than 50% outliers are unfortunately not uncommon.

Figure 1 shows a typical LNG production plant. An LNG loading line and the LNG recirculation line are both equipped with the same brand and model vaporiser, measuring the same LNG by a common GC (stream switching Figure 2. GHV trend loading. by the GC).

Next, the gross heating value (Btu content) is given of both vaporisers, represented by the dark blue and purple data points (Figure 2). The erratic character is obvious to see.

What makes matters worse is what is seen in the trend lines of both vaporisers, represented in Figure 2 by the yellow and green lines. These trendlines are completely opposite to each other. So, the real question is which result is correct or true? Unfortunately, nobody knows.

Figure 3. LNG transfer trend and uncertainty data at one of the major What is known, however, is the amount of global LNG producers.

US dollars related to such measurement

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May 2022

uncertainty. Assume an LNG cargo of 170.000 m3 against an Asia LNG spot price of US$59.67 and an uncertainty of 0.52% on the energy content. This results in a measurement error equal to US$1.2 million for each cargo (Table 1).

Table 1. Potential LNG revenue losses per year due to wrong analysis

The ultimate solution

Description

Abbreviation

Volume of loaded/ unloaded LNG

VLNG

Density of loaded/ unloaded LNG

ρLNG

Value

Unit

170.000

m3

74.659300

kg

460

kg/m3

The only way to sample and convert LNG into a 0.2 MJ/(N)m3 Gross calorific homogeneous natural gas mixture is by avoiding value losses due to pre- and partial vaporisation, create flash GCVLNG 0.287785404 MJ/kg sampling/analysis vaporisation, and good mixing. This must be done error 0.000272558 Million Btu/kg under tight and controlled circumstances where 5.37 Btu/ft3 electrical power and the heat exchange surface area are important factors.

0.52 % However, the most important step is getting a cryogenic liquid out of the process transfer line Net energy of Egas displaced 0 Million Btu displaced gas and transporting it to the vaporiser. This is the step where there can be challenges. Typically, If applicable, gas consumed by LNG Egas to ER 0 Million Btu thermal or vacuum jacketed insulation is used, but carrier that is often not enough. The amount of LNG Total net energy loss E 20.349 Million Btu sampled is extremely small compared to the mass of the wetted parts which transport the LNG. Heat Asia LNG spot 59.67 US$/million Btu ingress is inevitable and pre- and partial prices: March 2022 vaporisation will occur, resulting in incorrect 1.214222 US$ analytical results and therefore losing US dollars Value of uncertainty 0.52 % on the LNG cargo transferred.

The solution is active sub-cooling. Active sub-cooling is using the characteristics of LNG and vaporisation will occur. This results in outstanding analytical its thermodynamic properties. Active sub-cooling results repeatedly and under all circumstances. compensates more than sufficiently for the amount of heat Figure 3 shows the measurements at the LNG transfer at ingress and therefore guarantees that no pre- and partial one of the major global LNG producers. The uncertainty of

Table 2. ASaP Phazer LNG revenue losses per year due to uncertainty Description

Abbreviation

Volume of loaded/ unloaded LNG

VLNG

Density of loaded/ unloaded LNG

ρLNG

Gross calorific value losses due to sampling/analysis error

GCVLNG

Value

Unit

170.000

m3

74.659300

kg

460

kg/m3

0.001099106

MJ/(N)m3

0.001581533

MJ/kg

1.49785E-06

Million Btu/kg

0.0295

Btu/ft3

0.0029

%

It is the complete package that counts

Net energy of displaced gas

Egas displaced

0

Million Btu

If applicable, gas consumed by LNG carrier

Egas to ER

0

Million Btu

Total net energy loss E

112

Million Btu

Asia LNG spot prices: March 2022

59.67

US$/million Btu

6.673

US$

0.0029

%

Value of uncertainty

Figure 4. Energy equation from G.I.I.G.N.L 6th edition.

the Btu content measurement is unmatched so far.

This measurement has an error which amounts to US$6.673 per cargo. This is negligible compared to a measurement error of up to US$1.2 million per cargo.

The probe/vaporiser is a part of the whole analytical installation, perhaps the most important, but a chain is only as strong as its weakest link. An LNG sampling and measurement system that complies with ISO 8943: 2007 and G.I.I.G.N.L. 6th edition typically consists of the following main parts: zz Probe. zz Vaporiser. zz (Heated) sample lines. zz LNG sampler. zz Analyser (typically a GC). zz Control system.

Therefore, it is important to determine the uncertainty of the whole measurement and sampling chain from the tip of the probe till the final data used for the bill of loading (BOL). Typically, the focus was on the hardware performance but now, with dedicated software, the whole measurement chain can be monitored overall and in detail.

Monitoring can be done locally or remotely anywhere in the world.

By extending the online measurements for LNG flow and density as well as the BOG flow and composition, the whole energy equation can be done online and instantaneously.

This will eliminate the risk of human error and saves a considerable amount of time. But most importantly it makes every Btu count, hence every US dollar count as well. The equation for the BOL can be found in detail in the G.I.I.G.N.L 6th edition as shown in Figure 4.

For such a system, the typical architecture is shown in Figure 5.

Since size matters, these parts will typically be built on one or more so-called skids. Another advantage of skids is that the battery limits are clearly defined and the skids can be pre-tested and transported as one.

In conclusion, keeping a tight handle on finances is more important than ever in the energy industry. It must be ensured that every Btu and every dollar is accounted for. For LNG transfers, this can only be achieved by using the right equipment and techniques in the analysis of the transferred LNG that comply with ISO 8943: 2007 and G.I.I.G.N.L. 6th edition. As demonstrated, LNG is extremely difficult to analyse and it is of key importance to choose the right equipment and the right partner to supply it.

References Figure 5. Typical LNG system architecture.

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1.

Marwa Rashad, Reuters, ‘Asia LNG spot prices hit record high, S&P data shows’, (March 2022).

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30+ years experience in Consulting Simulation services Modelling and diagnostic software for process plants and machines

William Gielen, VIKING Life-saving Equipment, the Netherlands, discusses why investments in fire safety training and equipment are central to marine operations in the LNG industry.

A

special focus on fire safety in the LNG sector

by VIKING Life-saving Equipment was further sharpened in January 2022, when the company opened the doors to a new marine fire services (MFS) VIKING Safety Academy™ in Rotterdam, the Netherlands.

The new centre features its own simulator and real ships equipment to support a programme of eight MFS training modules for VIKING technicians, planners, and customer service staff. It is also expected to offer crew-specific training to customers in the months ahead.

Investments in fire safety have been central to the global lifesaving appliance and service provider’s path for growth over recent years, especially since the Danish company acquired the Drew Marine Fire Safety and Rescue division in 2019, merging the organisation to form the VIKING MFS division. An ongoing expansion of liferaft production facilities in Thailand also includes a second new training centre for MFS, for

83

example, with the goal of reinforcing MFS expertise throughout the organisation.

The ramp up in training expertise reflects VIKING's broadening fire safety expertise in support of the sophisticated equipment and risks involved in storing and carrying LNG cargoes. The need for high quality technical service is paramount, not just because when something goes wrong it goes really wrong, but because the risks are such that even the slightest shortcoming cannot be allowed.

The new training programme and facilities acknowledge the next phase in VIKING’s emergence as a force in LNG MFS. The LNG carrier population stood at 642 ships at the end of 2020 (according to Statista) – almost double the number active in 2010. Through organic and strategic efforts, VIKING has emerged as a main player in LNG MFS, with a market share that is estimated to have quadrupled over the last five years.

Solid foundations

VIKING started in a small way in the LNG business approximately 10 years ago and became active at a point when the overall market was in downturn and clients were putting their MFS suppliers under close scrutiny.

One of the company's tanker customers also ran LNG carriers and a pretty serious problem had developed on one of its vessels; it so happened that VIKING had a senior

Figure 1. VIKING is opening three to four MFS stations a year, expanding to 40 worldwide by 2025.

technical expert available to sail with the vessel and manage urgent repairs during a voyage.

The work provided an opportunity to showcase the team’s extensive experience in drydock planning, which had been developed in offering MFS to the chemical tanker sector. Covering the full range of owner needs, from initial surveys to documentation and reporting, these services include full scope reporting to customer drydocking teams and are supported by VIKING’s own global drydocking project teams and riding crews.

When VIKING made that first safety assessment for the planned drydocking, the customer’s technical department accepted the company's report and asked VIKING to prepare the drydocking scope. Subsequently, VIKING completed the MFS part of two LNG carrier drydocking jobs to the client’s satisfaction.

In a market where fleet managers continuously evaluate service quality and sometimes talk to each other, requests quickly followed from well-known LNG carrier operators, including from oil majors and Japanese owners.

Building a portfolio for LNG

Based on its existing MFS expertise and newly-earned LNG carrier drydocking experience, the Rotterdam-based team developed its portfolio of MFS services for LNG to support Novec inert and chemical fire suppression systems, as well as dry powder on-deck firefighting. Services include support to cover the storage, performance, and maintenance of dry powder systems.

Technician training and certification extends to a range of distinct areas of expertise to support: dry powder system inspection, service, repair, and certification; five yearly control valve inspection; 10-year HT or ultrasonic material verification; 10-year hose replacement; two-year dry powder humidity analysis; and dry powder disposal/replacement.

Where all of VIKING's MFS services are concerned, including LNG, the greatest benefit the company brings to its customers has come from its in-house and OEM trained, fully certified teams of technicians.

The availability of ‘flying squad’ services proved especially persuasive, with technicians joining an operational LNG carrier and providing services with the ship underway. All of the company’s approved technicians are qualified under certified training programmes to work within a value chain that ensures uniform service quality and documentation. The 'total package' approach to annual service, drydocking, and reporting accounts for the company’s rising market share.

Today, VIKING customers comprise the top tier of shipping names in LNG, including those companies investing most aggressively in the expansion of the LNG supply chain.

New levels of service

Figure 2. VIKING's new training centre in Rotterdam,

the Netherlands, will offer training direct to clients in the months ahead.

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May 2022

The 2019 merger of MFS resources at VIKING has created a business robust enough to grow with client needs. Service availability is imperative for ships sometimes exposed to extreme heat and cold in a single voyage, whose high specification equipment, vital valves, and cylinders come under continuous stress from vibrations.

MFS has evolved into a service VIKING offers as part of its full-scope Shipowner Agreements for marine safety

services on a fleet-wide basis. The Shipowner Agreement concept also covers liferafts, lifeboats, personal protective equipment, and more, and has seen over 1500 shipowners sign up in the past decade.

Overall, VIKING offers its firefighting equipment services at 150+ ports served by its own MFS workshops and annually audited authorised service providers. IACS Z17-compliant VIKING MFS workshops are located in more than 20 main ports, with other destinations – including for drydocking, voyage repairs, and troubleshooting – covered by the company’s service network or qualified global flying service teams. All services are offered on the basis of standardised Viking MFS Safety Certificates and globally certificated MFS equipment.

Commitment to the LNG business has seen the company opening up new VIKING MFS service stations where its LNG clients require them. The company is opening three to four MFS stations a year and, based on a review of customer needs, plans to expand the number to approximately 40 worldwide by 2025.

Investments have also been made in product and service development: rather than emptying and hydro-testing powder storage tanks, for example, VIKING now uses class-approved ultrasonic thickness measurement techniques to support certification services. As well as bringing cost and efficiency gains, the approach is environmentally beneficial.

VIKING’s broader service-based ethos has also been making an impact. Selected LNG clients now benefit from the ‘VIKING Gas Detection Exchange Programme’ – where standard gas detection equipment housed in its own suitcase is rotated out of service for maintenance and replaced by spare certified kit. VIKING also holds additional spare cylinders for Novec systems in key locations.

Figure 3. VIKING MFS is available at more than 150 ports.

The bigger picture

Where foams are used in firefighting onboard LNG carriers, VIKING recently secured a Global Partnership Agreement covering distribution of the marine-approved foam concentrates offered under the Dr Sthamer brand.

Products include IMO670 for high expansion inside air foam systems for engine rooms and machinery spaces, and next-generation, high-stability, fluorine-free foams.

In addition, VIKING has invested in its own class-approved foam testing laboratory. The facility verifies that foam samples perform in accordance with IMO guidelines and is also equipped to test other parameters, including foam surface tension and spreading co-efficient.

Meanwhile, consolidation of the two marine fire safety businesses brought the opportunity to re-evaluate systems support. Evolved in-house based on the VIKING ServiceNow and Drew Marine VIPS platforms, the VIKING digital planning system works by monitoring each ship’s supply, service, and inspection fire safety needs and co-ordinating them with VIKING’s worldwide logistics, service, and technical capabilities.

VIKING’s planning system marine fire service works by monitoring each ship’s supply, service, and inspection of fire safety needs and co-ordinating them with its logistics and technical services. Today, capabilities include automatic e-mail notification of service due dates and continuous auditing for certification needs.

Figure 4. VIKING’s planning system monitors each

ship’s supply, service, and inspection of fire safety needs, co-ordinating them with logistics.

All of VIKING's certification services are also available for inspection via the VIKING customer portal, while service engineers use iPads for reporting. This supports standardised processes, reporting uniformity for enhanced planning, and on-the-spot documentation to ensure that electronic records are available at the earliest opportunity.

However, developing MFS services that are specific to LNG will be driven by reinforcing ties with the technical teams with whom VIKING’s planners, technicians, and customer services staff work.

VIKING has built its business on being flexible on special projects and being able to respond to specific technical issues, as well as the company's skills in drydocking. That has been based on the good communications established with the technical teams and superintendents but the company can see there are still areas where more can be done, whether that is by enhancing advisory services, adding to the network, or flying squad maintenance visits.

May 2022

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Mads Raun Bertelsen, Hempel, Denmark, highlights the importance of utilising a versatile hull coating that keeps fouling at bay in all conditions, regardless of climate or geography.

T

he spot LNG trade operates at the whims of the market, and gas carriers must be ready to operate in all geographies and in all oceans. Hempel’s Hempaguard is a versatile hull coating that keeps fouling at bay in all conditions.

The LNG carrier industry is used to coping with swinging freight rates. Turbulent spot charter and regional upheavals have seen significant volumes of tonnage re-route from Asian trade routes to European waters. This is an industry that is agile and

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resilient, and which in turn requires its vessels to be responsive to changing trading patterns and regional demands.

Some of the biggest LNG exporting nations – Qatar and Australia – are based in warm climates, and the largest US LNG exporting port, Sabine Pass LNG, is located in the warm waters of the Gulf of Mexico where temperatures range between 17˚C - 26˚C. It is important not to overlook the havoc warmer waters can play on a ship’s performance.

Although hidden from view and easily forgotten, a vessel’s hull is central to its efficient operation. Constantly exposed to the corrosive properties of seawater, the hull is also laid bare to a myriad of types of micro-organisms, algae, and small animals that attach themselves to the smooth underside of the ship where they quickly form colonies. Waters of 25˚C or above are believed to provide the optimum environment for these colonies to develop.

These organisms create resistance, and so more energy is required to propel the vessel through the water, resulting in higher fuel costs – an important consideration given the increasing requirements for operators to burn more expensive, low-carbon emission fuels. They can also break away from the hull, forming new colonies in regions where they may be unwanted, wreaking havoc on local ecosystems.

Biofouling comes in many shapes and sizes – from microscopic algae to adult-sized barnacles greater than 2 cm across. But the ways to control fouling are limited, as the International Maritime Organization (IMO) notes: “Anti-fouling systems and operational practices are the primary means of biofouling prevention and control for existing ships’ submerged surfaces, including the hull and niche areas.”

Biofouling is a growing concern, as sea temperatures rise and port delays become more frequent. And the drag created by biofouling can increase ships’ greenhouse gas (GHG) emissions by up to 25%, as revealed by a new study delivered in November 2021 at the United Nations Climate Change Summit.

When it comes to reducing emissions, coatings are a good place to start. If applied correctly at new-build stage and throughout its life, the right selection of coating, and taking into account the vessel type, trading route, and passage speed can help significantly reduce the amount of biofouling that gathers on the hull. Although coatings are a long-term investment, with Hempel’s Hempaguard MaX solution, operators could achieve fuel savings that deliver a return on investment (ROI) in just three months.

Active protection

Hempaguard MaX has been developed following the success of Hempaguard X7, however, as a three-coat system, as opposed to five, and it can save up to two days in drydock. The synergy between each layer creates low average hull roughness (AHR) for less drag and more fuel efficiency at sea.

The system consists of Hempaprime Immerse 900, Nexus II, and Hempaguard X8, which together form the Hempaguard MaX solution.

First, one coat of Hempaprime Immerse 900 is applied to the hull, as opposed to two as is standard with most maintenance epoxy coats. This coating offers an extremely low AHR profile and contributes to bottom line fuel savings. A further advantage is that it can be applied to all areas that require protection, including topsides, making application management straightforward. The next layer is a tiecoat technology (Nexus II) that again contributes to the AHR profile of the hull. Nexus II also has anticorrosive capabilities and works in synergy with Hempaprime Immerse 900.

Finally, a layer of Hempaguard X8 is applied, providing fouling defence based on Hempel’s patented Actiguard technology. This tried and tested product uses hydrogel silicone

and a slow-release antifouling barrier that prolongs the vessel’s fouling-free period.

The combination of Actiguard antifouling and very low AHR technologies makes Hempaguard MaX ideal for those vessels, such as LNG carriers, that spend a significant amount of time in warm waters and often operating on the spot market, where time constraints and diverted sailings are the norm.

Importantly, the coatings system does not contain organotin compounds acting as biocides and complies with the International Convention on the Control of Harmful Antifouling Systems on Ships as adopted by the IMO in October 2001.

Performance incentives

Owners and operators will be required to look to every aspect of a ship’s operations to reduce emissions and increase their performance. The IMO’s GHG strategy is being rolled out through holistic approaches to emissions reduction, such as the Energy Efficiency Existing Ship Index (EEXI), which scores vessels for their efficiency. IMO is calling on ports and other stakeholders to offer incentives to the owners/operators of higher scoring ships.

The choice of coating on a ship’s hull could impact its overall EEXI score. The Index is just one set of regulations designed to meet shipping’s carbon emission reduction targets that call for a reduction of GHGs by at least 50% by 2050 compared to 2008, and for at least a 40% reduction in the carbon intensity of international shipping by 2030 relative to 2008. More challenging international targets could be on their way as certain IMO member states want shipping to have net zero carbon emissions by 2050. As such, at its most recent meeting in December, the Marine Environment Protection Committee (MEPC) agreed to initiate the revision of its GHG strategy.

As international regulations tighten control over acceptable levels of emissions, so must operators look to their vessels and further scrutinise their performance to maximise on any incentives offered.

Previously an expensive process, performance monitoring has in the past been available only to the few. In response, Hempel created SHAPE – Systems for Hull and Propeller Efficiency – a hull performance monitoring solution, which has been built around the principles of ISO 19030. This set of methodologies measures changes in ship-specific hull and propeller performance and defines a set of relevant performance indicators for hull and propeller maintenance and repair activities.

The SHAPE programme includes data gathering, data analysis, and interpretation from Hempel’s team of data scientists and marine biologists, advice from a dedicated analyst, and access to Hempel’s hull coatings.

Ongoing assessments

SHAPE can document Hempaguard MaX’s fuel savings in a programme of continuous improvement. The data-driven programme provides key performance indicators (KPIs) based on speed loss measurements and cost-effective monitoring, to support Hempel’s customers’ decisions about, for instance, slow steaming and route planning. Hempel establishes a vessel’s individual speed and power reference curves, amongst other parameters, and the information is fed into the system. Once gathered, this data is cleaned so precise speed loss calculations can be obtained.

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Figure 1. A versatile hull coating that keeps fouling at bay in all conditions, regardless of climate or geography.

Customers then receive a variety of KPI measurements and advice from a dedicated Hempel hull performance analyst about how decisions based on this information will impact

fuel efficiency. SHAPE can monitor long- and short-term trends on vessels of any age or operating pattern.

Hempel’s commitment to sustainable and environmentally-friendly operations does not stop with the company’s customers. The company is constantly reviewing its own commitments to the environment and has introduced a set of targets to reduce its footprint. As a company, Hempel will be carbon-neutral in its operations by 2025 and have committed to set science-based targets in its value chain in accordance with the 1.5˚C pathway. Hempel are one of only 300 companies worldwide to make this commitment.

The company have also set the challenge to reduce customer CO2 emissions by at least 30 million t by 2025.

Hempel will achieve this through a renewed focus on sustainability in its technology research programmes, and their innovation incubator, GrowHub, will be central to its future product offerings.

With these goals, Hempel will help to future-proof the industry and support its customers’ ambitions to operate their vessels in a low-/no-carbon shipping environment.

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