LNG Industry Issue August 22

August 2022

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ISSN 1747-1826

CONTENTS 03 Comment 05 LNG news 10 It's all to play for in Latin

AUGUST 2022

29 Finding the right fit

Thomas Hess, Burckhardt Compression, Switzerland, considers the range of compression technology on offer for the handling of boil-off gas in LNG storage and shipping, and provides guidance on selecting the most suitable technology for different requirements.

America

Alvaro Rios Roca, Gas Energy Latin America, the Southern Cone, analyses the current state of LNG in Latin America, providing insight on the region's market complexities as well as its opportunities for growth.

34 Transfer from A to B

Adam Sanders, STS Marine Solutions Ltd, UK, looks at the benefits of using LNG ship-to-ship transfer throughout all parts of the LNG supply chain, helping to solve the challenges that are arising as the industry evolves.

37 Delivering decarbonisation

Sven Lumber, Head of EcoTow, Group Operations, Svitzer, UK, outlines how the towage sector can improve safety and sustainability at LNG terminals, as well as highlighting the focus on decarbonising the industry.

41 Andy Foreman, Amarinth Ltd, UK, describes the challenges of designing cryogenic centrifugal pumps for LNG processing, as well as outlining how these pumps are developed to handle the industry's unique demands.

10 14 Upgraded by design

Andrew Stafford, Technical Director, Trelleborg Marine & Infrastructure, UK, describes the evolution of infrastructure for LNG transfers, focusing on how jetty designs are being readdressed so they are suitable for future applications.

17 New markets on the block

Karthik Sathyamoorthy, AG&P LNG Terminals & Logistics, Singapore, explains how downstream gas demand is being unlocked in new and emerging markets, and how factors such as the energy transition and current geopolitics are influencing the shift to LNG.

20 Thomas Klenum and Dallas Smith, Liberian Registry, US, look at how the maritime industry can reduce its carbon footprint, with options such as updating regulatory framework and assessing the lifecycle of fuels.

24 Float or sink

Carlos Guerrero, Global Market Leader of Gas Carriers and Tankers, and Jose Esteve, Global Market Leader of Offshore Gas & Power, Bureau Veritas Marine & Offshore, France, outline how floating LNG could be utilised to navigate the current climate as countries rethink their energy security and the importance of decarbonisation.

45 Fixing the cracks

Danny Constantinis, Executive Chairman and CEO, EM&I Group, Malta, outlines the integrity challenges of cryogenic storage, showing how overcoming these barriers will be integral for the LNG industry whilst supporting Europe in the transition to renewables.

49 Making delivery robotic

Liam Hanna, NDT Robotics and Scanners at Eddyfi Technologies, UK, outlines the critical factors in an efficient inspection programme for LNG tank maintenance, focusing on deployment and delivery.

52 Flexibility from uncertainty

Maximilian Rockall, UK, and Michelle Glassman Bock, Belgium, Squire Patton Boggs, detail the ongoing impact of the Russia-Ukraine conflict, focusing specifically on the impact it is having on the Asian LNG market.

ON THIS MONTH’S COVER STS Marine Solutions has been providing flexibile LNG ship-to-ship (STS) operations to clients worldwide for over 15 years, and this year was no different. With the global events of 2020 through to 2022, the global energy map has seen rapid change. Linked with market volatility and the use of LNG as a transition fuel to non-hydrocarbon fuels, is this the future of LNG shipping?

Find out more at: www.stsmarinesolutions.com

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SARAH SMITH ASSISTANT EDITOR

COMMENT S

ummer is officially in full swing in the Northern Hemisphere, and temperatures are soaring to record-breaking highs of more than 40˚C here in the UK.1 With this hot weather, it is hard to deny that the globe is warming up. Many countries are already feeling the effects of climate change, with wildfires currently breaking out across Europe due to the extreme heat. Climate change has never been so evident, and the LNG industry is ready to play its part in helping countries to curb their emissions, as moves are made to transition to low-carbon and renewable energies.

Changes to the world’s weather patterns are not the only thing shaking up the energy sector, with recent reports that Russia has cut gas flow through Nord Stream 1 to only 20% capacity.2 Europe is sure to feel the crunch, especially looking ahead as we reach the height of summer and inevitably turn back towards shorter days and colder nights.

As one of the leading solutions to the rapidly accelerating energy crisis, LNG is stepping up to the plate to help alleviate incidents shaping our world at present.

At the end of June, G7 leaders met to agree on bolstering investments in European gas projects as a way of tackling this energy crisis head on.3 In a statement, the leaders declared that “with a view to accelerating the phase out of our dependency on Russian energy, we stress the important role increased deliveries of LNG can play, and acknowledge that investment in this sector is necessary in response to the current crisis”.4 There are many countries, such as the US, that are at the ready to supply LNG to an ever-growing list of customers, as governments make efforts to obtain energy security.

That being said, it has not all been plain sailing for the US. A fire at Freeport LNG’s liquefaction facility means the plant will be shut down until at least late 2022.5 This has been

Managing Editor

James Little james.little@palladianpublications.com

Assistant Editor

a knock for US LNG, as the facility accounts for 17% of the country’s LNG export capacity.6 The US Energy Information Administration (EIA) reported that the shutdown caused an estimated 2.0 billion ft3/d drop in US export capacity, and that exports will remain below average at 10.5 billion ft3/d in 2H22, as well as Henry Hub natural gas spot prices declining. However, the EIA also projects that production levels will bounce back by spring 2023.7 This August issue of LNG Industry contains many articles covering the topics mentioned here, from ‘Setting the course for carbon neutrality’ starting on p.20 and ‘Delivering decarbonisation’ on p.37, to how the Russia-Ukraine conflict is creating contract complexities in Asia in an article entitled ‘Flexibility from uncertainty’, beginning on p.52.

It seems that world events are creating a perfect storm for the energy sector, and with all the twists and turns that this year has brought so far, who knows what could happen next. What is clear, though, is that countries are turning to LNG to help navigate these unprecedented times. Make sure to hold on tight, we are in for a bumpy ride over the next few months.

References 1.

Met Office, ‘Record breaking temperatures for the UK’, July 2022.

2.

Independent, ‘Russia cuts gas through Nord Stream 1 to 20% of capacity’, July 2022.

3.

Bloomberg, ‘G-7 leaders favour LNG investment in U-turn due to energy crisis’, June 2022.

4.

European Council, ‘G7 Leaders’ Communiqué’, June 2022.

5.

Freeport LNG, ‘Freeport LNG provides update on 8 June incident at its liquefaction site’, June 2022.

6.

US Energy Information Administration, ‘EIA forecasts U.S. LNG exports will fall 6% from the first half of 2022 to the second half of the year, following Freeport outage’, July 2022.

7.

US Energy Information Administration, ‘U.S. natural gas supply and demand balance shifts amid outage at Freeport LNG’, July 2022.

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LNGNEWS Mexico

CFE and Sempra Infrastructure expand agreements for Mexican energy infrastructure

S

empra Infrastructure and Mexico’s Comisión Federal de Electricidad (CFE) have announced several agreements to advance critical energy infrastructure projects in Mexico, including the rerouting of the Guaymas-El Oro pipeline in Sonora, the proposed Vista Pacífico LNG project in Topolobampo, Sinaloa, and the potential development of an LNG terminal in Salina Cruz, Oaxaca.

These new agreements establish the framework for a joint venture between the companies to ultimately enable the restoration of service provided by the Guaymas-El Oro pipeline.

These agreements also outline the path forward for the Vista Pacífico LNG terminal, including the definition of the project’s configuration to advance engineering and permitting efforts.

In addition, the companies are expanding the Memorandum of Understanding (MOU) signed earlier this year to jointly explore the potential development of an LNG terminal in Salina Cruz.

These development projects would allow CFE to potentially optimise the use of existing natural gas pipeline systems, provide additional sources of LNG supply for isolated markets in Mexico, and continue to expand LNG supplies to the global market.

The agreements for the development of the Vista Pacifico LNG and the proposed LNG project in Salina Cruz are preliminary and non-binding. These development projects, together with the rerouting of the Guaymas-El Oro pipeline, remain subject to a number of commitments to be satisfied, including, as applicable, feasibility studies, reaching definitive customer, construction, and partnership agreements, securing all necessary permits, obtaining financing and incentives, receiving respective board approval, and reaching a Final Investment Decision (FID).

Taiwan

Bechtel breaks ground on tank project in Taiwan

B

echtel, CPC Corporation, and MRY have broken ground on the project to design and build LNG tanks for the CPC Taichung Phase III LNG import terminal in Taichung, Taiwan.

To meet increasing demand for natural gas and to enhance the stability of natural gas supplies in Taiwan, CPC is expanding its facility to include two full containment tanks and associated regasification facilities.

Bechtel will execute the engineering procurement and construction of two 180 000 m3 full containment LNG tanks.

CPC is leading the way for Taiwan in meeting the country’s clean energy aspirations by rapidly expanding the country’s LNG import terminals to support the move from coal to natural gas as their primary transitional source of energy for the near future. “[This] marks another important step toward meeting the increasing demand for natural gas. Together with CPC Corporation and MRY, we are delivering cleaner, greener, and safer energy to Taiwan –supporting both their energy growth and security,” said Paul Marsden, President of Bechtel Energy.

“To power the needs of the world, we need LNG and storage capability, which is what we are doing here on this site today, by celebrating the start of construction on the largest storage tanks ever to be built in Taiwan”.

American Institute in Taiwan (AIT) Director, Sandra Oudkirk, expressed her support for Bechtel’s partnership with CPC on the new LNG storage facility in Taichung. Oudkirk underscored the importance of the US-Taiwan economic relationship and a commitment to reliable and clean energy that supports economic development and protects the environment.

Papua New Guinea

Milestone announced for Papua LNG project

T

otalEnergies, as operator, has announced the decision of the Papua LNG joint venture to launch the first phase of FEED studies for the Papua LNG project's upstream production facilities.

In parallel, studies for the downstream liquefaction facilities are progressing in line with the overall project schedule, and the objective is to launch the integrated FEED in 4Q22. The project is targeting a Final Investment Decision (FID) by the end of 2023, and a start-up at the end of 2027.

“The commencement of upstream FEED studies is

another significant step towards developing the Papua LNG project, which will increase Papua New Guinea’s LNG export capacity and thus contribute to its further development," said Julien Pouget, Senior Vice President Asia Pacific for Exploration and Production and Renewables at TotalEnergies. "The Papua LNG project is well positioned to contribute to growth in LNG supply worldwide, especially for customers in Asia seeking to decarbonise from coal to gas, in line with our strategy to lower global greenhouse gas emissions.”

August 2022

5

LNGNEWS Egypt

EGAS, KANFER, and LETH announce Suez LNG bunkering hub

E

gyptian Natural Gas Holding Company (EGAS), Kanfer Shipping (KANFER), and Leth Suez Transit (LETH) are facilitating an LNG bunkering hub in the Suez Canal.

The companies signed an MOU on the 3 February 2022 with the purpose of establishing LNG bunkering services in Egypt Mediterranean, the Suez Canal, and the Red Sea. The parties have agreed to collaborate and establish a joint venture (J/V) that will be chartering a bunkering ship from KANFER and manage its daily operation in Egypt.

More than 20 000 ships are transiting the Suez Canal annually, and all ships have a waiting time before the daily convoy commences. This time can be utilised efficiently by replenishing bunkers in either Port Said or Suez. There are also important ports along the Egyptian Mediterranean coast where ships will need LNG bunkering. There is an increasing number of dual-fuel ships in order (511 ships), in addition to the current fleet of 304 ships according to DNV. Even in today’s volatile energy market where oil products are favourably priced to LNG, more dual-fuel ships are being ordered and more LNG bunkering ships are required.

EGAS has initiated the establishment of a J/V with the right value-adding partners. The J/V will charter the bunkering ship, take care of the administration, including daily operation of the ship. This entity will also purchase the LNG from EGAS (or other LNG sources) and trade them to ship owners and the maritime industry. EGAS has made it clear that they are able to allocate a substantial volume of LNG to this growing segment in order to make the shipping industry, Suez Canal, and Egypt greener. “This will be an important step for Egypt, and attract more business to the Suez Canal”, said Admiral Osama Mounier Mohamed Rabie (Chairman & Managing Director) in the Suez Canal Authorities.

KANFER has a design enabling liquid gas transportation with the lowest possible environmental footprint as well as focusing on reducing the infrastructure cost.

LETH and KANFER Shipping are now primarily seeking J/V partners that have experience with bunkering and/or commodity trading and can take an active part in creating a business model for this high potential and attractive project in Egypt. The parties have in mind creating a fast-track solution, and have an ambition to have the bunkering infrastructure in operation by latest 2025.

6

August 2022

US

Delfin Midstream signs LNG SPA with Vitol Inc.

D

elfin Midstream Inc. (Delfin) has finalised a binding LNG Sales and Purchase Agreement (SPA) with Vitol Inc. (VIC). In addition to the SPA, VIC has finalised a strategic investment in the company.

Under the SPA, Delfin will supply 0.5 million tpy on a FOB basis at the Delfin Deepwater Port 40 nautical miles off the coast of Louisiana, US, to VIC for a 15-year period. The agreement is valued at approximately US$3 billion in revenue over 15 years.

Additionally, Delfin has also signed Heads of Agreements (HOAs) and term sheets that are being finalised into fully termed agreements. As a modular project requiring only 2.0 - 2.5 million tpy of long-term contracts to begin construction, Delfin is on schedule to make Final Investment Decisions on the first floating LNG (FLNG) vessel by the end of this year.

Wouter Pastoor, COO of Delfin, added: “Delfin has completed permitting work with a positive Record of Decision from the Maritime Administration with a 13 million tpy Non-FTA DoE export license. In addition, Delfin has completed DEEF with Samsung Heavy Industries and Black & Veatch which puts us on pace to execute our project this year and to commence operations in 2026.”

Carlos Wheelock, Head of LNG Americas for VIC, added: “We have seen extensive changes to the global energy landscape this year, further underscoring the importance of US liquefaction in meeting the world energy needs. Delfin’s innovative solution provides a reliable, low-cost alternative for the world’s LNG needs.”

THE LNG ROUNDUP

XX Cheniere and PetroChina sign long-term LNG SPA XX Fluxys and EIG partner on GNL Quintero XX Australia Pacific LNG announces new CEO Follow us on LinkedIn to read more about the articles

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LNGNEWS Germany

Italy

Snam and Edison to develop small scale LNG projects

S

nam and Edison have signed a Memorandum of Understanding (MOU) aimed at developing the small scale LNG market in Italy to foster the decarbonisation of land, sea, and rail transport, as well as off-grid industrial and household users.

This initiative will leverage on the development of the Italian LNG sector, also thanks to planned new infrastructure investments, to encourage the progressive replacement of diesel and simultaneously boost the use of liquid biomethane (bio-LNG).

Currently, the LNG market for heavy goods transport in Italy already accounts for approximately 4000 trucks, approximately 130 filling stations, and a consumption of approximately 200 000 tpy. Thanks to small scale infrastructure as well as the use of LNG in maritime bunkering, the market is expected to more than double by 2025 with a potential growth of up to 1.5 million t in consumption by 2030. With an increase in the usage market, the number of filling stations is envisaged to grow to approximately 300 when fully operational. The development of the small scale supply chain will also enable the progressive use of bio-LNG. Under the agreement, the parties will identify and develop opportunities for collaboration along the entire small scale LNG value chain – from truck loading services to road or ship transport, liquefaction and distribution via petrol stations or satellite depots – depending on their respective areas of expertise.

29 August - 01 September 2022

ONS 2022

Stade becomes next German FSRU site

S

tade will be the site of one of the four floating LNG (FLNG) terminals – so-called FSRUs – chartered by the Federal Government of Germany. The vessel is expected to be ready for the import of LNG in the port of the future Hanseatic Energy Hub by the end of 2023. The expansion of the existing industrial port for the land-based terminal, for which NPorts, the Lower Saxony port authority, is responsible, is already in the approval phase, and is expected to be completed by the end of 2023. A nautical simulation carried out for this purpose has shown that all the requirements for an FSRU onsite are fully met.

The Hanseatic Energy Hub site is located in the existing Stade industrial park with a direct connection to the German gas grid. The FSRU will be connected via a 2 km short connecting pipeline.

“FSRUs are important for ensuring the security of gas supply in Germany in the short term. In Stade, we have the infrastructure and the experience with liquefied gases to enable smooth operation. We are happy to provide both,” said Johann Killinger, Managing Director and Shareholder Hanseatic Energy Hub. “In parallel, we will be pushing full steam ahead with the expansion of our land-based zero-emission terminal. Because one thing is clear: Germany needs a future-flexible energy infrastructure to drive the transformation of our energy supply sustainably and reliably.” The Open Season for the land-based capacity as of 2026 is currently ongoing. Binding bids are expected by 29 July.

The Hanseatic Energy Hub is designed onshore for LNG and low carbon energy sources, such as bio-LNG. It is expected to meet approximately 15% of Germany’s gas demand from 2026 with a total capacity of 13.3 billion m3 of natural gas.

05 - 08 September 2022

Stavanger, Norway

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06 - 09 September 2022

SMM 2022

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12 - 15 September 2022

Turbomachinery and Pump Symposia 2022 Houston, US tps.tamu.edu

8

August 2022

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29 November – 02 December 2022

Abu Dhabi, UAE

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Alvaro Rios Roca, Gas Energy Latin America, the Southern Cone, analyses the current state of LNG in Latin America, providing insight on the region’s market complexities as well as its opportunities for growth.

10

ountries in Central America and the Caribbean will require relatively small amounts of LNG, with more FSRUs being installed parallel to those in the Dominican Republic, Panama, and El Salvador. These countries need natural gas, which they do not produce, to support hydropower, wind power, solar power, and to displace coal and heavy diesel generation in industry and power generation. Gas Energy Latin America (GELA) predicts that small LNG will continue to be deployed throughout the islands and in all Central American countries from the large FSRU terminals already installed.

On 2 April 2022, El Salvador became one of the LNG importing countries in the region with the purchase and arrival of its inaugural cargo at Shell’s Bilbao Knutsen. The cargo was transferred to the BW Tatiana FSRU, a conversion of Shell’s former Moss-type LNG carrier Gallina, an important step in El Salvador’s energy transition away from heavy fuel oil. The cargo was originally loaded onto Atlantic LNG in Trinidad and Tobago on 3 March 2022 and took the long route around Cape Horn, Chile, instead of going through the Panama Canal.

With regards to South America and the Southern Cone in particular, GELA acknowledges that there is availability of indigenous natural gas in several countries such as Bolivia (in decline), Argentina, and Brazil. There is also existing pipeline infrastructure to move it across borders to achieve regional integration. In addition, Bolivia can no longer be considered a long-term supplier in the Southern Cone.

Consequently, the time has come for the region and the countries of the Southern Cone to share their interests, in that it is essential to develop and use the recoverable gas resources existing in the region. In addition, it is also time to take

advantage of the extensive infrastructure of gas pipelines and facilities built between the countries (Argentina, Bolivia, Brazil, Uruguay, and Chile) to avoid costly imports of LNG from the US and several other countries in the future.

Although this is the most logical path to develop, the reality of the commercial relations of the countries is different – a region with reserves and infrastructure is ironically separated.

Bolivia does not have the production capacity to supply its export markets to Brazil and Argentina, and Brazil is reinjecting pre-salt gas while importing daunting volumes of LNG. Argentina, despite having one of the most extensive shales in the world with vast hydrocarbon reserves, is putting the national economy in trouble by importing elevated volumes of LNG from other countries to supply its mainly deficit demand in the winter months.

All of this has already been happening since the drop in Bolivia’s production capacity, which has declined by 4.4% since 2015. However, the conflict in Ukraine has aggravated this situation, and Brazil, Chile, and Argentina are passing their invoices of expensive LNG imports to their national treasuries and therefore to their economies.

To better understand the paths that the countries of the region will take, next is a review of their reserves and development.

Bolivia

In Bolivia, the few exploratory projects have not given the desired result, and the country’s reserves and production will continue to decline at an accelerated rate. Any new work or exploratory campaign will take a long time (at least eight years)

11

and is subject to discovery. This leaves Bolivia with less and less export capacity and with pipelines with idle capacity to transport natural gas to the Brazilian market, which is the important market with the greatest growth prospects in the region. Government officials have recognised this situation and have agreed on the necessity of a new set of rules in order to not become an importer by 2032.

Brazil

The natural gas market in Brazil continues to reform itself, albeit at a slow pace. It is difficult to leave behind the drying monopoly that Petrobras exercised in the entire chain, which was devastating in terms of competition and prices for end users, causing reduced demand from the industrial sector, forcing companies not to be competitive. Brazil is the most promising market in terms of demand in the Southern Cone, for which it needs reliable, diversified, and competitive supply.

The demanding Brazilian companies, from distributors to electrical and industrial consumers, must go out in search of natural gas suppliers and contracts in the short-, medium-, and long-term under the new market scheme. The options they have are the production of Petrobras and associated companies offshore, small volumes of onshore natural gas produced by private companies in Brazil, natural gas from Bolivia (increasingly less), quite expensive LNG, and gas from Vaca Muerta in Argentina, as discussed next.

Brazilian market. In addition, it will be able to access the northern Chilean market, which will continue to import LNG. Additionally, it will require less expensive LNG for its winter peaks.

The second phase of infrastructure is essential for IEASA and YPFB to stop tedious negotiations that they have been holding for two years. A bland fight in which Bolivia does not have and cannot send the volumes that Argentina needs in the north of the country.

On the other hand, Argentina wants to pay low prices to Bolivia, but pays without haggling US$40/million Btu for LNG to US companies.

The gas infrastructure in Argentina for these two phases has a cost of approximately US$3.5 billion. At current prices, the investments would be paid immediately in less than a year, substituting LNG and Bolivian imports. In addition, it would generate additional money from exporting to the northern Chilean market, and finally revenue from exporting to the Brazilian market arriving through the pipelines that are becoming empty in Bolivia.

However, macroeconomic conditions in Argentina associated with subsidies and populism continue to pose restraints in the availability of dollars to bring external investment. Not being able to take profits out of the country freely is one of the biggest restraints for getting needed foreign investment. If this continues to happen, GELA foresees limited exports to Chile and the inability to move gas to Brazil or export LNG.

The future of gas in Latin America

Using regional gas production and infrastructure is an important source for generating taxes, royalties, employment, and income.

The availability of natural gas resources from Argentina is Not producing indigenous gas and keeping pipelines empty is the immense. Due to its shale characteristics, Vaca Muerta gas option that should not happen, but may happen, and therefore is available not subject to discovery, but pending drilling Southern Cone countries will have to import and compete with and fracking, and production can be raised very quickly, as Europe for very expensive LNG. demonstrated by Tecpetrol in Fortín de Piedra, who, in just Latin America cannot be so nostalgic about continuing to 12 months, increased its production by 13 million m3/d. What import expensive LNG when natural gas exists and vast resources is needed is a massive drilling of wells to increase production are in place in Bolivia, Brazil, and Argentina, and much of the and support existing production, urgently needed infrastructure infrastructure is already built throughout the Southern Cone. to evacuate to its domestic market and neighbouring countries If the internal infrastructure is built as planned with the (Chile, Uruguay, Brazil, and Bolivia) after 2032, as well as export it Transport.ar system that will start this year, the demand for LNG in via LNG to the world.

Chile, Argentina, and Brazil will decrease. Bolivia’s idle capacity in Argentina has advanced in the purchase of pipes in order to its pipelines could easily be used in two or three years to move complete the first phase of construction of natural gas gas from Argentina to Brazil and also move gas from Argentina to infrastructure, mainly aimed at supplying its domestic market and northern Chile. lowering LNG imports until late 1H23.

While the Transport.ar gas pipeline is being built in Argentina, Argentina, its institutions, and companies must make every which will allow the evacuation of Vaca Muerta gas on a large effort to complete the second phase by the end of 2024, which scale, volumes of LNG will continue to be imported, affecting will allow it to reach the north of the country. In this way, it will national economies. free Bolivia so that it can send the scarce volumes it has to the Pipeline supply through existing gas pipelines, GELA believes, is more geared towards firm (industrial) gas and not gas for seasonal peaks, supporting renewable energy, or when rainfall is not sufficient for power generation. LNG thus provides this necessary flexible gas in Argentina, Chile, and Brazil for these conditions.

Finally, LNG in Colombia will also increase in the coming years, not only for when the rains are not enough, but also for firm supply, since gas discoveries are not being fulfilled and shale will not continue under the new administration.

LNG has arrived in Latin America and will remain for a long time, in greater or lesser volumes depending on the will of the countries to achieve regional investment in Figure 1. Gas pipelines in the region and their idle capacities. production and make gas integration work.

Argentina

12

August 2022

14

Andrew Stafford, Technical Director, Trelleborg Marine & Infrastructure, UK, describes the evolution of infrastructure for LNG transfers, focusing on how jetty designs are being readdressed so they are suitable for future applications.

F

rom the growing need for short-term storage to meet demand in order to weather the energy crisis, to the growing global climate challenges necessitating cleaner energy choices, changes in market dynamics are driving evolution and growth within LNG transfer technologies and practices. As a result, jetty design must adapt to ensure facilities are fit-for-purpose to meet not only today’s demands in a safe, efficient, cost-effective, and sustainable manner, but also those posed in the future.

Short-term storage and the redesign of energy networks

Operators are improving existing infrastructure by upgrading jetties using FSUs as semi-permanent storage structures and using ship-to-ship (STS) transfers more regularly to meet demand. However, whether upgrading existing or planning for new infrastructure, it is vital that operators consider the inclusion of a contingency that facilitates the speedy implementation of additional storage by considering the potential role of FSUs at the engineering stage of the jetty upgrade or design process. This requires the consideration of the current and future requirements for a potential STS arrangement, which may help to establish specification requirements such as stronger piles and enhanced mooring capabilities. Once the requirement to increase capacity is agreed, the gaining of permits, the building of onshore tanks, and other construction will take time.

Utilisation of the FSU model solves the immediate problem and provides a faster route to operation while more permanent solutions are being prepared.

Additionally, in the coming years there are likely to be many LNG carriers, typically steam turbine-powered, reaching the conclusion of their trading life that can be repurposed as FSUs. For example, Qatargas recently purchased 10 of its previous charter fleet to help bridge the existing supply and demand gap.1 Further emphasising the need for a more strategic approach to securing the reliable and flexible supply of gas, it is widely expected that the rise in short-term, semi-permanent, localised storage of LNG seen throughout 2021 is set to continue. For instance, Mitsui OSK Line’s Q-Max sized FSRU has found interim employment in Singapore as it awaits deployment to a long-term contract in Hong Kong.2 Gas supply networks are also being reviewed and, where necessary, redesigned due to the impact of the conflict between Russia and Ukraine. For example, while Germany receives approximately 42 billion m3 of gas from Russia, the drive for independence from Russian gas supply means this may soon be turned off and so must be sourced from elsewhere.3 There is, however, some movement already happening in terms of the redesign of some supply chains. For instance, 75% of all US LNG cargoes delivered in March 2022 landed in Europe and Turkey, compared with approximately 44% in March 2021.4 Additionally, with no LNG terminal capacity, the German government has released €3 billion to acquire FSRU charters and associated simple gas take of jetties, which includes the signing of deals for two Hoegh LNG and two Dynagas FSRUs.5

Decarbonisation through LNG

The growing global climate crisis and the need to meet sustainability goals in more mature global markets are driving infrastructure changes. As the transition towards a net zero economy gains momentum and LNG becomes increasingly cost-competitive, the demand for LNG and its related infrastructure will only increase.

What is more, many shipping lines are decarbonising their operations through the use of LNG as fuel, as it contains 24% less carbon per unit of energy than conventional marine fuels. Harvey Gulf International Marine LLC has partnered with SailPlan, an emissions monitoring and optimisation platform that combines the real-time engine, fuel, and navigational data from vessels, with the weather, mapping, infrastructure, and traffic data, to benchmark, optimise, and report 15

on fleet emissions. The result is a carbon saving of up to 29% across its LNG supply vessel fleet.6 The shipping company has also started to embrace bio-LNG (a blend of recaptured pig and dairy farm gas combined with conventional fossil LNG), running one of its platform supply vessels solely on battery power and bio-LNG.7 It is therefore essential that when looking to build new or develop existing facilities, consideration is given to local gas production to establish the potential to import other sources of gas such as agricultural or even synthetic. What is more, if a new facility intends to store hundreds of thousands of cubic metres of imported liquefied gas and wants to backload a specific volume of gas to a bunker vessel locally, it is vital that the required infrastructure is considered and put in place during terminal design.

When it comes to jetty upgrades, it is important to ensure infrastructure can also successfully accommodate smaller ships – an increasingly important option to meet the growing demand for LNG. Therefore, rather than simply look at investments across fixed infrastructure, such as fenders and specialised loading arms for larger vessels, thought must be given to how infrastructure can be flexible for smaller vessels too.

Leveraging terminals as distribution hubs It is becoming increasingly important for many terminals to export both domestically and internationally, operating as

Figure 1. It is vital that operators, whether upgrading

existing or planning for new infrastructure, look to LNG solutions that offer configurability, compatibility, and flexibility.

distribution hubs. For instance, New Fortress Energy is taking large FSUs and distributing LNG from smaller vessels to supply multiple customers in smaller quantities accordingly.8 When building a terminal, it is vital that operators look at the facility’s surrounding infrastructure to establish potential additional ways in which it can expand its network of supply, whether by marine transfer or even by loading and shipping ISO containers to different local users. For example, in ports such as Jacksonville, Florida, US, ISO containers are loaded and shipped to Puerto Rico via LNG-fuelled ships. This demonstrates how, when looking at terminal infrastructure, for many operators today it is not enough to simply establish how much LNG they can receive or even produce. The volume it can also look to export and supply to the local grid by unconventional means must also be considered.

While of course not all terminals are built to supply local grids, it is important to consider the potential ways in which LNG can be remonetised.

Optimising berth availability

Given the evolution and growth of LNG globally, the maximisation of berth availability is crucial. Therefore, it is important to identify and put in place contingencies for infrastructure downtime or even failure, to ensure optimisation of safety and performance.

Some terminals that utilise fixed-fender solutions have also completed design studies to accommodate a contingency for back-up pneumatic fenders in the event of fender damage or during maintenance. Additionally, some terminals have also considered the utilisation of hose transfer systems as a loading arm contingency. In the event of a marine loading arm failing, many do not carry a spare onsite or have the lifting capability to change out an arm, which can then take between nine and 12 months to replace. This, coupled with the fact that one loading arm failing signals the potential for others with similar operation and maintenance histories to do likewise in the near future, could have a significant negative impact on terminal efficiency and performance. Adding simple pipework tie-ins allow these hose transfer systems to be viable and keep terminals operating when ordinarily they could be out of production.

Terminals must have contingencies in place to ensure they remain operational, even in the event that substantial assets or infrastructure are not available.

Looking ahead

The global LNG infrastructure market is expected to witness significant growth in the near future. However, in order to respond to the various challenges and opportunities, infrastructure must be able to keep up with demand. Therefore, it is vital that operators, whether upgrading existing or planning for new infrastructure, look to LNG solutions that offer configurability, compatibility, and flexibility to not only meet their bespoke operational requirements today but also tomorrow.

References

Figure 2. Changes in market dynamics are driving evolution and growth within LNG transfer technologies and practices.

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August 2022

1.

Tradewind News, 2022.

2.

Tradewind News, 2022.

3.

IEA, 2020.

4.

SP Global, 2022.

5.

Reuters, 2022.

6.

Offshore Energy, 2022.

7.

Offshore News, 2022.

8.

OE Digital, 2022.

Karthik Sathyamoorthy, AG&P LNG Terminals & Logistics, Singapore, explains how downstream gas demand is being unlocked in new and emerging markets, and how factors such as the energy transition and current geopolitics are influencing the shift to LNG. he energy industry is at a revolutionary point in ensuring the efficient mobility of LNG and energy security.

LNG is an ideal energy alternative to help reduce greenhouse gas (GHG) emissions and bridge the gap

between more harmful fossil-based fuels and future sustainable technologies such as hydrogen. It is a sustainable and affordable way of meeting the power needs of developing countries while renewables continue to scale up to required levels. In this way, it can serve as a backbone

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of stable energy production while markets build their investments in renewables and a reliable base to build a long-term hybrid solution for cleaner power.

In the backdrop of these benefits of using LNG as energy, new demand centres are emerging that are challenging the traditional markets of Asia, Europe, and North America. The advent of flexible and scalable regasification technology has made it possible for such emerging markets to look for LNG imports, which were hitherto ignored, as it could not justify import facilities for having small and niche pockets of demand. Countries in Sub-Saharan Africa and Asia are embracing regasification and modular technologies that enable economical fit-for-purpose supply and distribution solutions and accelerate their transition to LNG.

Outlook for global LNG demand

There has been a spike in LNG spot prices over the last couple of months that is mostly driven by geopolitical issues associated with Ukraine and concerted efforts from various governments to push cleaner energy. As a result of this, there is an evident increase in LNG demand and price in the short-term. However, longer-term curves on LNG prices are quite stable and reflective of the anticipated increase in LNG supply from Qatar, the US, Australia, United Arab Emirates, and additional capacities uncovered across the globe that will enter into the LNG system.

There has also been a large number and diversity of LNG suppliers emerging in recent years as compared to previous decades where there were only a handful of players in this industry. This has enabled LNG importers to enjoy favourable prices and flexible contract structures aligned to metrics, KPIs, or benchmarks that are important to them.

Figure 1. 125 000 m3 LNG carrier conversion with Gas Entec Regastainer® into a modular FSRU (M-FSRU).

Companies focused on building LNG infrastructures are looking beyond the short-term and calibrating their assumptions based on logical future supply and demand balances, market offtakes, and forward price curves.

Emphasis on energy transition

LNG plays an integral role in achieving an energy transition to a decarbonised ecosystem while the limitations that are innate and associated with renewables are sorted out, such as drought, reliability, changes in weather patterns, and chemical waste pollution from batteries, among others. For example, gas-fired power plants solve the intermittent supply of renewable energy (exacerbated by climate change) that can threaten the stability of the entire power grid. Renewables thus require alternative, stable fuel capacity to support their intermittency. For most markets, natural gas is the cleanest and most commercially-preferred source of stable capacity for a power system, working hand-in-glove with renewables and complementing initiatives by governments for cleaner and greener energy.

LNG is also a practical fuel with a tight specification band that can be supplied from one source and may be received in most terminals or demand centres. This enables ease of usage and mobility that effectively guarantees a country’s energy security.

Furthermore, within the LNG system, there have been massive breakthroughs on accountability of how emissions are tracked, making the entire network or value chain as clean as possible.

A call for innovation

A lot of innovation that is being seen today is a direct result of limitations and learning derived from disasters (e.g. Fukushima, Japan) and geopolitical issues (e.g. Ukraine) in terms of pricing, commercial structures, and fit-for-purpose technical solutions. This is very interesting and encouraging for companies that are looking at options to bring gas into their markets efficiently and effectively.

Despite having a lot of LNG exports, many of these markets are either unserved or underserved, where companies such as AG&P provide that much needed proven and commercially compelling infrastructure to support the downstream ecosystem required for clean fuel – LNG terminals, logistics, and city gas distribution networks.

AG&P is one of the two known pure play integrated downstream players, where AG&P’s expertise helps terminals and downstream networks become a reality faster with economical and efficient solutions enabled by robust project development, financing, LNG supply sourcing, EPC, commissioning, and a comprehensive downstream LNG demand aggregation and supply chain and logistics solution package. These innovative solutions enable the active development of low-CAPEX LNG import terminals as gateways to new markets to access LNG and help unlock new and growing geographies in a faster and more affordable way.

No one size fits all Figure 2. KARMOL’s M-FSRU, the world’s first modular floating LNG (FLNG) regasification terminal.

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Each market exhibits unique market intricacies, local conditions, regulatory constraints, and customer capability and preferences.

Senegal, Indonesia, and the Philippines are fast-growing economies in Sub-Saharan Africa and Asia, embracing regasification technologies, enabling them to accelerate their transition from dirtier fuels to LNG. However, as their operating environments and user profiles are different, it requires customised and innovative solutions.

Senegal has proceeded with the world’s first converted modular FSRU (M-FSRU) to power the country’s cleaner energy requirements: KARMOL is a joint venture between Turkey’s Karpowership and Japan’s Mitsui OSK Lines. The joint venture contracted AG&P’s subsidiary, Gas Entec, to convert the 125 000 m3 Moss LNG carrier into an M-FSRU. The project was completed in 10 months and within the allocated budget. The converted FSRU KARMOL LNGT Powership Africa was delivered from Sembcorp Marine in Singapore, and arrived at Senegal by the later part of 2021.

The vessel was equipped with two modules of combined regasification capacity of 84 million ft3/d, and was connected to Karadeniz Powership Aysegul Sultan which enabled the 114 MW floating power plant to switch to regasified LNG by June. The overall capital outlay was less than half the cost of a new-build FSRU. Thousands of miles away from Dakar in Senegal, at one of Indonesia’s famed destinations – Bali, 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. This was a delivery from the Paxocean yard in China for the Benoa port in Bali, where it subsequently replaced a converted FRU, Lumbung Dewata.

In the Philippines, the 5 million tpy LNG import terminal situated at Batangas Bay has adopted a different approach from the FSRU-based projects in Senegal and Indonesia. This is a hybrid concept combining an FSU and an onshore storage unit, which accommodates redundancies to mitigate disruption from frequent typhoons passing through the area.

In conclusion

As the world moves towards a net zero transition, there is a lot of pressure on emerging economies to migrate from traditional but dirtier fuels to cleaner energy alternatives.

The unique conditions of each market, however, will press on the need to identify creative and innovative solutions that bridge the gap before an integrated LNG network is created in such emerging regions, or when the alternative sources of cleaner energy become accessible to all.

Such streamlined solutions for creating integrated LNG infrastructures must be supported by partners that promote innovative commercial structures, customisable and flexible offering, and serve as a one-stop-shop with end-to-end energy and infrastructure construction solutions that support the full LNG value chain ecosystem.

The long-term position of LNG in the energy mix of many countries, including those that aspire to have LNG as a fuel alternative, excites many as it promotes a decarbonised journey towards energy transition, reaffirms energy security and mobility from fuel sources, and remains a practical solution as a cleaner and less expensive fuel.

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Figure 1.The Mount Tourmaline, the first

LNG-fuelled Newcastlemax bulk carrier; owned by Eastern Pacific Shipping and Liberian flagged.

ecarbonisation is in the proverbial drivers-seat of maritime regulation and technological innovation today. The shipping industry eagerly awaits the outcome of IMO meetings on the subject; discussions around potential new regulations, requirements, and how to practically and safely implement them are discussed in great deal from boardrooms to engine rooms.

At any major shipping event, industry seminar, or conference, the drumbeats of decarbonisation can be heard across almost every panel and presentation. It is no longer the word of the future, but the present. It is time to do more than talk, and the Liberian Registry is in a unique position amongst regulators of not only acting, but doing so in a proactive way that supports shipowners and operators around the world. The Registry’s global team is continuously working on new opportunities to help remove barriers to approving new technologies, design features, and alternative fuels.

While the Liberian Registry is on the regulatory side of the industry, it is working closely with shipowners/operators, shipyards, design companies, classification societies, engine manufacturers, and other relevant key stakeholders to move the industry to a zero-emission sustainable future. A key part of its approach is to champion common sense, and fair, transparent regulations that allow and stimulate innovation at the International Maritime Organization (IMO). These regulations must ensure a level-playing field, and take into consideration the safety of the crews at sea, as well as their training.

Chief Executive Officer of the Liberian International Ship and Corporate Registry (LISCR), Alfonso Castillero, states: “We have an obligation and desire to help our partners in the maritime industry. We do not see shipowners and operators flying the Liberian flag as clients, that is too transactional; to succeed in decarbonising the industry, we need to work in partnership. Owners are required to follow the rules and conventions we are a party to, and it is our responsibility to

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ensure these rules and conventions promote the safety of life at sea and the environment; a true partnership is needed to succeed here.”

Changing the regulatory framework

Over the last decade, the Liberian Registry has been consistently advocating for change to the restrictive international regulatory framework of prescriptive rules and regulations to goal-based standards (GBS) and risk assessments because it believes they provide opportunities for innovation. A GBS and risk assessment-based regulatory model allows for analysis and approval of innovative design solutions, new technologies, and alternative fuels by demonstrating an equivalent level of safety. Although the approval process may be more complicated and time consuming, it provides the much-needed opportunity for naval architects and designers to optimise the design of ships to be the most operationally and environmentally efficient.

The Liberian Registry’s collaborative efforts are focused on analysing innovative ship designs featuring new technologies, alternative fuels, or advanced design features.

The Registry does this through formalised joint industry projects (JIPs) or joint development projects (JDPs) with the overall goal of helping to develop the ships of the future and eventually leading the way to a truly zero-emission vessel (ZEV) that is regulatorily feasible and sustainable.

Thomas Klenum and Dallas Smith, Liberian Registry, US, look at how the maritime industry can reduce its carbon footprint, with options such as updating regulatory framework and assessing the lifecycle of fuels.

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Studies have indicated that to comply with the IMO’s current greenhouse gas (GHG) emission reduction strategy, then ZEVs need to be designed, built, and in service by 2030, hence with the expected more stringent IMO strategy ZEVs should be in service before 2030.

Since 2016, the Registry has participated in numerous JIPs/JDPs with over 30 projects in the last three years and interest is growing rapidly. By their very nature, these JIPs and JDPs are groundbreaking and varied, including verification of second-generation bio-fuels, CO2 carrier designs, LNG FSRUs, liquid hydrogen carriers, new materials for gas cargos and fuel tanks, as well as verifying the effectiveness of hull air lubrication systems and other design solutions.

The maritime industry’s big environmental challenges ahead are related to the new IMO requirements of the Carbon Intensity Indicator (CII) and the Energy Efficiency Existing Ship Index (EEXI), along with the Energy Efficiency Design Index (EEDI) Phases 3 and 4. It should, however, be noted that these are just short-term measures from the IMO’s GHG emission reduction strategy to align the industry with the Paris Agreement’s temperature goals. It is expected that the IMO’s GHG emission reduction strategy will be revised in 2023 to require international shipping to fully decarbonise by 2050.

Considering the lifecycle of fuels

The lifecycle assessment of fuels is another interesting aspect that is currently being explored. This is on the IMO’s agenda in the context of GHG emissions reduction in order to apply a holistic solution to decarbonisation by considering the entire lifecycle of fuels. The latest effort from the IMO is to consider the complete GHG footprint of marine fuels in the regulatory framework through a well-to-wake lifecycle assessment approach. Draft guidelines for Lifecycle GHG and Carbon Intensity for Maritime Fuels (LCA Guidelines) are currently under development with the Liberian Registry’s involvement.

Fuels that have been extracted, developed, and processed in a sustainable way using renewable energies can potentially be bunkered onboard a ship with a negative carbon footprint.

This offers promising opportunities for biofuel blends and LNG as a fuel to play an even larger role in the transition to fully decarbonise international shipping. In fact, it could potentially be a permanent solution for ZEV if combined with the onboard carbon capture and filtering concept that is claimed to be able to capture over 90% of CO2 emissions.

Therefore, considering the entire well-to-wake assessment of fuels with a 90% capture rate onboard, a ZEV could possibly be realised in the near future.

The challenge at the moment is that the new environmental requirements for EEXI and CII do not currently incorporate the lifecycle assessment of fuels and also do not give credit for onboard carbon capture and storage. The Liberian Registry is working together with other stakeholders

to properly recognise and consider all emission reduction opportunities for the two new concepts. The Registry is currently preparing a document with proposed solutions to properly address this issue for possible submission to the IMO meeting MEPC 79.

Another related challenge in connection with the lifecycle assessment of fuels is that, according to the Intergovernmental Panel on Climate Change (IPCC), parts of the well-to-tank GHG emissions may not fully fall under international shipping. The accounting of GHG emissions is based on the IPCC principles laid out in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories that determine which emissions are the responsibility of the international shipping sector. According to these IPCC guidelines, any non-combustion emissions, including fugitive emissions, should be accounted for in the sector(s) where the fuel is explored, produced, processed, refined, transported, or distributed. The IMO’s GHG inventory for international shipping should only include GHG emissions from fuel used by ships, whereas GHG emissions from exploring, producing, processing, refining, transporting, and distributing the fuel used by ships should be accounted for in national GHG inventories. To prevent any emissions from not being counted, IMO’s GHG inventory for the international shipping sector should estimate and report all emissions from fuel used by ships regardless of the source of the carbon.

The IMO are currently developing LCA guidelines that will also address this issue in order to avoid double-counting the same emissions between IMO’s GHG inventory and national GHG inventories.

It is, however, important that the IMO’s regulatory framework provides incentives to take into account the entire lifecycle assessment of fuel, i.e., well-to-wake, regardless of whether the GHG emissions are counted on the IMO’s GHG inventory or the national GHG inventories.

Meanwhile, the Registry’s global team, comprised of engineers, naval architects, prior seafarers, and surveyors with experience in applying technical regulations to approval of alternative fuels and innovative designs, has been specifically tasked with supporting the Liberian fleet from the design phase through construction, delivery, and during the ship’s entire operational lifecycle. This team is in place to assist in the review of new vessel designs, offering insights and recommendations to mitigate risks/costs, advise on technical and safety implications, and support demonstration of compliance with applicable rules and regulations.

Conclusion

In considering the decarbonisation of international shipping, it should be acknowledged that international shipping transports approximately 90% of all global trade and contributes less than 3% of the global CO2 emissions; however, as part of the industry’s social responsibility and sustainability, all efforts must be made to fully decarbonise the shipping sector, and the Liberian Registry is dedicated to collaborating with other stakeholders in helping the industry have a sustainable and Figure 2. Generic well-to-wake supply chain. Source: International Maritime Organization (IMO). zero-emission future.

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Carlos Guerrero, Global Market Leader of Gas Carriers and Tankers, and Jose Esteve, Global Market Leader of Offshore Gas & Power, Bureau Veritas Marine & Offshore, France, outline how floating LNG could be utilised to navigate the current climate as countries rethink their energy security and the importance of decarbonisation.

he potential for floating LNG (FLNG) terminals to provide a fast, cost-effective, and flexible source of energy has received renewed attention as many nations reassess their energy security and as they recognise the benefits of LNG as a valuable part of the decarbonisation transition.

Strong demand

Given the time it takes to bring renewable power online at scale, LNG represents a potential quick win for emissions reductions, and as the cleanest fossil fuel, it is also likely to be the last to be replaced as part of the energy transition.

The supply market is currently strong as a result of forecasted growing energy demand, and although there has recently been a rise of short-term and spot contract prices to unprecedented heights, the long-term market is also buoyant.

Recent examples include the decisions being taken to develop new LNG liquefaction trains and terminals, particularly in the US, and the recent announcement that the US is to supply at least 15 billion t3 of LNG to the EU by the end of 2022.1 Moreover, US-based NextDecade Corporation announced it has executed a 15-year Sales and Purchase Agreement (SPA) with Engie for the supply of LNG from NextDecade’s Rio Grande LNG export project in Texas, US. Additionally, there is increased attention to the deployment of new FLNG, such as one in Mozambique (Coral FLNG), a second one expected shortly in Senegal

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(Tortue-Ahmeyim FLNG), and plans for others in Malaysia, Nigeria, Congo, Israel, and the US. Shipping is adding to global demand. Burning LNG in internal combustion engines produces almost no sulfur oxide nor particulate matter emissions, low nitrogen oxide emissions, and delivers greenhouse gas (GHG) emissions reductions up to approximately 25%, depending on the technology. With established global infrastructure and distribution networks, the LNG supply chain is also paving the way for carbon-neutral shipping fuels, such as biogas and syngas.

A growing fleet

The global LNG carrier fleet has grown rapidly over the last few years, with approximately 724 total LNG carriers, including units having regasification capacity (FSRU), now in service – a trend backed by a strong orderbook. As of May 2022, there were 124 active LNG carriers in the BV-classed fleet and 48 on order.

To safely transport LNG, carriers must be equipped with cargo containment, boil-off gas (BOG) handling, and propulsion systems that meet high standards of reliability. These key systems handle onboard LNG – either as fuel or cargo – and BV supports ship owners by assessing new technologies for safety and regulatory compliance. BV’s expertise includes polar-class and ice-breaking LNG carriers with safety features that are adapted to the harshest conditions.

Almost a fourth of all cargo ships above 2000 GT on order today are able to run on LNG. To comply with current regulations and set the course for reducing GHG emissions, ship owners and operators are already using LNG as an alternative to fuel oil. BV is supporting this transition, and approximately half of LNG bunkering vessels in operation, under construction, or on order are BV classed.

A characteristic trend in the shipping industry is using size for efficiency purposes, such as Dynagas’ two new 200 000 m3 LNG carriers, which set a record in cargo carrying capacity with only four tanks and have been built to BV class. These vessels, built by Hyundai Heavy Industries, have been designed to be compatible with most LNG terminals, and can transit the expanded Panama Canal. Another seven have also been ordered, all to BV class.

Floating infrastructure

The widespread adoption of LNG, on land and at sea, has been possible thanks to the development of safe, advanced infrastructure throughout the energy value chain.

Floating liquefaction facilities (FLNG) are attracting attention as an alternative to onshore terminals on the supply side, as they can be deployed faster. This is particularly true in the case of conversions from LNG carriers. FSRUs and FSUs have recently been brought into the spotlight as they are a flexible solution and a faster alternative for import terminals on the demand side. Germany, for

example, has, in less than six months, been able to contract five FSRUs for a potential import capacity of 20 million tpy, with deployment expected within one year, in order to offset reduced pipeline gas volumes from Russia.

FLNG units, FSRUs, and FSUs do not necessarily have to resemble ships. They may not have a propulsion system and may be permanently moored for a very long period of time without dry-docking either at quay side or off port limits.

Conversion vs new-builds

A key decision to be made when developing a floating terminal (be it FLNG, FSRU, or FSU) is the choice of either a new-build or the conversion of an existing LNG carrier. Conversion projects are likely to be quicker to enter operation than new-builds. Good candidates for conversion include those vessels that will be penalised with the IMO’s upcoming EEXI – estimated at 30% of the current fleet according to industry sources, these are primarily steam turbine ships. Over 20 LNG carriers are currently laid up, and most of them may also be candidates for a conversion. Conversion of exposed offshore units may take longer, approximately 18 months, due to harsher environmental considerations impacting long-lead items such as the mooring system.

A new-build brings the ability to design to project requirements, including storage capacity and sloshing-proof cargo containment systems. However, it can take a longer time to deliver,

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particularly at present, because most shipyard slots are full until 2025. A containment system’s requirements for FSRUs, such as LNG carriers, are very specific, and GTT membrane tanks are usually the preferred option, which restricts which shipyards can build them.

To date, approximately one-fifth of the FSRU fleet of 60 units, including currently trading LNG carriers with regasification capacity, and nearly one-third of the current FLNG fleet of seven units are conversions. Recent examples are BV-classed KARMOL LNG’s converted LNG carriers to FSRUs. Both vessels – KARMOL LNGT Powership Africa and KARMOL LNGT Powership Asia – have been delivered, and will operate in Senegal and Brazil, respectively. A third FSRU, KARMOL LNGT Powership Europe, is also undergoing conversion. These units will be deployed together with gas-powered electricity generation floating units, which are at quay side and directly connected to the local electrical grid, also classed by BV.

60 years of experience

In November 2017, BV published NR645, the first rules fully dedicated to FSRUs. This was followed by an update in July 2018 to address the specific requirements of FSUs and BV’s NI655 Guidance Note, which provides guidelines for the conversion of an existing LNG carrier into an FSRU or FSU. As the only class society to have developed dedicated rules and guidelines for the classification and conversion of FSRUs and FSUs, BV is uniquely positioned to address the technical and operational aspects of the conversion of vessels intended to serve as LNG distribution terminals.

BV’s role in supporting FSRU and FSU deployment is to help identify, prevent, manage, and eliminate potential risks for the crew, the environment, and the integrity of the vessels themselves, therefore protecting the entire supply chain they are part of.

BV has 60 years of experience with LNG, and classed the first FSRU in 2005 and the first operating FLNG, the Tango FLNG. The rules include a class survey regime that is applicable to permanently-moored vessels with continuous operation requirements. This involves allowing in-water surveys replacing dry docking, as well as allowing alternative inspection schemes of the hull and the containment systems to the traditional prescriptive approach.

A different operational profile

Figure 1. LNG value chain – export. Floating and fixed

offshore units extract hydrocarbons (including gas) from offshore reserves, and separate the condensate from the gas. FLNG units treat this gas, cool it until liquefaction at -163˚C, store it, and periodically offload it to an LNG carrier.

Bureau Veritas (BV) helps clients to assess the safety of all these complex assets, and ensures the compliance of all equipment, installations, and processes.

Trading LNG carriers sail either in a fully laden condition – from the export to the import gas terminal – or almost empty with a slight heel of LNG to keep tanks cool when they return to load. Cargo operations are typically performed in sheltered gas terminals where the ship and cargo tanks remain stationary throughout the operation – without disturbing the free surface during partial filling phases.

In contrast, FLNGs and FSRUs may face unfavourable weather conditions while operating with tanks partially filled.

Ship motions can cause sloshing of the cargo inside the tanks and may generate impact loads on tank bulkheads, containment system boundaries, and pump towers.

BV has developed methods and tools to analyse the risks and consequences rising from tank sloshing so the required engineering responses can be confirmed. This involves: zz Seakeeping and mooring analysis to calculate ship motions, and consequently, tank motions. zz Using the calculated tank motions, sloshing model tests and computational fluid dynamic (CFD) calculations are carried out in order to determine sloshing loads. zz The LNG containment system and the underlying hull structure are assessed under the applied calculated sloshing loads.

Figure 2. LNG value chain – transportation. Transporting natural gas safely and reliably is a key concern in the industry.

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When the cargo containment system cannot be reinforced to sustain sloshing loads, then a risk analysis can be undertaken to support the drafting of operational procedures to avoid such incidents from occurring.

For offshore locations, that is for units exposed to the open sea, BV has been developing and evolving its expertise in mooring systems for more than 30 years, supported by Ariane and HydroSTAR, the company’s advanced mooring and hydrodynamic analysis tools suited to deep and shallow waters, able to support multi-body interactions typical of side-to-side LNG offloading.

Engine power

BV classed the very first LNG carrier with a dual-fuel diesel electric propulsion system. Ever since, it has continued to ensure that engines and propulsion systems comply with the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (IGC Code) and classification rules. These rules ensure vessels’ proper design, manufacture, and installation to prevent any safety issues during operation.

Two-stroke dual-fuel engines are most commonly chosen for LNG carriers today. These engines feature reliable and known technology that offers the highest level of fuel efficiency, while upholding the traditionally high safety standards found on LNG carriers. BV also pioneered the first WinGD two-stroke, dual-fuel, low-pressure engine onboard LNG carriers in 2017, and recently approved a new low-pressure, two-stroke dual-fuel, electronically-controlled engine from German manufacturer MAN B&W. This MAN engine saw its first order placed in 2021 for four LNG carriers that are presently under construction in South Korea under BV class.

Innovation ahead

Figure 3. LNG value chain – onshore import/export.

Onshore terminals play a key role in the LNG supply chain. Import terminals receive the liquid gas from LNG carriers, store, regasify, and send it to the onshore grid for consumption. Export terminals liquify gas produced in oil and gas fields, store it, and transfer it to LNG carriers for export. BV’s classification expertise enables the efficient transport of gas across major markets worldwide, often including ship-to-shore transfers at one or both ends of the journey.

Equipment and systems manufacturers continue to pursue technological developments along the natural gas value chain.

In one example of support for this innovation, BV issued approval for the design of a cryo-powered regasification system – the first application of cold power generation technology for FSRUs. The system, based on the Organic Rankine Cycle of waste heat processing, recovers cold energy during regasification and uses it for power generation. The approval was issued to Mitsui O.S.K. Lines (MOL) and Daewoo Shipbuilding & Marine Engineering (DSME).

During the LNG regasification process, as the LNG stored at -163˚C warms up and changes to its gaseous state, cold energy is recovered instead of being dispersed back into the ocean as cold seawater. The system is targeted to reduce fuel consumption and CO2 emissions for FSRUs by approximately 50% by recovering approximately 70% of the power consumption in the regasification process at maximum rated regasification flow rate.

In another example of innovation, last year BV granted an Approval in Principle (AiP) to GTT for the use of a digital solution for sloshing activity assessment designed to optimise LNG membrane tank maintenance frequency.

A better future

Figure 4. LNG value chain – summary. For decades, the

marine and offshore industries have been an essential part of the gas supply chain, carrying out roles in the exploration, extraction, liquefaction, transportation, and delivery of natural and petroleum gas. Gas is by far the most ecological fossil fuel, and is poised to have a key economic and strategic role throughout the 21st century as part of the future net zero-carbon energy mix. BV supports the maritime and offshore industries at every step of the gas supply chain. The company helps all stakeholders involved in the creation of the global gas value chain of tomorrow.

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BV classed one of the first ocean-going ships to transport LNG, the 25 000 m3-capacity Jules Verne, in 1965. BV also classed the first Korean-built membrane LNG carrier in 1995, the first LNG FSRU in 2005, the first FLNG in 2013, in 2017, the largest FSRU ever built, and the 263 000 m3 MOL FSRU Challenger.

The organisation also classed the first LNG bunkering vessel in 2017, the 5000 m3 ENGIE Zeebrugge.

BV continues to support innovation in the LNG value chain, helping to create a new generation of future-proof vessels across the LNG value chain. This includes large and small scale LNG carriers, FLNG units, FSRUs, FSUs, and floating gas-topower units.

Yet, BV takes a fuel-agnostic approach to the future. LNG is an important transition fuel, but just one pathway available from the basket of fuels required to reduce global emissions.

This view is in-line with the wider role of class in supporting safe innovation in energy and fuels globally. By developing the standards that make safe innovation possible, class societies play a unique role in building trust between stakeholders. Thus, BV is committed to playing its part in shaping a better future for the shipping and power industries, and society as a whole.

References 1.

BLACKMAN, D., ‘Biden’s Commitment For US LNG To Supply Europe Faces Strong Headwinds,’ Forbes, (Mar 2022).

Thomas Hess, Burckhardt Compression, Switzerland, considers the range of compression technologies on offer for the handling of boil-off gas in LNG storage and shipping, and provides guidance on selecting the most suitable technology for different requirements.

ompressors are the main actors for gas handling in LNG facilities – both onshore and on ships. Handling of LNG boil-off gas (BOG) is complex, not least due to the very low gas temperatures. As the gas can be processed in multiple ways, each application has its own specific requirements. But why is gas handling required in LNG facilities at all? And what are the typical application ranges and compressor technologies available? This article provides a brief insight into the application range and the advantages of the LNG BOG compressor portfolio offered by Burckhardt Compression.

BOG in LNG storage and transportation

For storage in liquefaction plants, receiving terminals, or onboard ships, LNG is kept at atmospheric pressure under cryogenic conditions of below -160˚C. This condition is ideal for efficient storage and transportation since the liquid occupies only 1/600 of the volume of the gas.

The transportation of LNG from liquefaction plants to the receiving terminals is done by ship. Onboard modern LNG carriers, the cargo is stored in highly insulated membrane type containment systems. Since the trading of LNG is a global business, and voyages from loading terminals in the US to receiving hubs in Asia can take approximately 30 - 40 days, the handling of BOG becomes crucial in order to keep the cargo tank pressure under control.

Bunker ships supply LNG to gas-fuelled ships. Although smaller in size if compared to LNG carriers, BOG management is required to manage the cargo temperature and tank pressure.

Despite the highest level of thermal insulation on storage tanks and piping, heat ingress to the LNG is unpreventable.

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The warming-up of the LNG leads to the formation of BOG, a problem which exists in the entire LNG production, storage, and transportation chain. Efficiently managing BOG in terminals and onboard ships represents a key issue.

The amount of BOG generated is not constant and varies with the terminal or ship operation, tank filling level, gas composition, and ambient conditions, thus the volume of BOG to be managed is unsteady and fluctuates.

from 1.0 to 1.3 bar abs). Although the pressure range on the suction side is rather small, huge variations on the suction side temperatures need to be considered. Even though during normal operating conditions the compressor might be handling cold gas with typical temperatures of -120˚C to -90˚C, start-up conditions or the use of a partial reliquefaction system onboard an LNG carrier can bring the suction temperature up to 40˚C. Ideally, the BOG compressor is able to handle the incoming gas at both cold and warm conditions, without the need for extra equipment for gas temperature conditioning.

Whilst cryogenic pumps can efficiently handle the natural gas in its liquid state, compressors are required to treat the inevitable BOG. BOG management is required both onshore and on LNG ships. Accordingly, different operating conditions are specified for compressor systems depending on their application onshore or for maritime use.

Flowrates

Compressor selection

A wider selection of different compressor technologies is offered to the market for the handling of BOG. Proper selection of the type of compressor is dependent on the evaluation of many operating parameters and represents a challenge to the decision maker. Different compressor types have distinct advantages depending on the anticipated range of application.

Burckhardt Compression provides a complete compressor portfolio for BOG applications, both traditional labyrinth sealing and labyrinth sealing in combination with ring sealing on higher stages. Burckhardt Compression can therefore advise where these different designs can be best applied.

Suction conditions

Whereas there is a wide range of discharge pressures specified for compressors installed in LNG terminals and LNG ships, the requirements on the suction side are rather identical.

Since the gas is stored in non-pressurised tanks both at onshore terminals and on ships, a suction pressure level close to atmospheric conditions is specified (typically ranging

Figure 1. The Burckhardt Compression LNG BOG

compressor portfolio: small two-crank Laby® K-type compressors cover the area of smaller flowrates, typically installed on LNG bunker ships but also in small scale onshore LNG facilities. Two- and four-crank Laby® D-type compressors with a stroke of 250 to 375 mm can be found in many LNG terminals. Six-crank Laby®-GI compressors complete the portfolio, being able to handle large flows of up to 20 tph and compressing gas to 300 bar. Laby-GI compressors are designed for maritime use but are also installed onshore.

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Specified flowrates for the compressor system vary with the storage capacity of the terminal resp., the size of the LNG carrier, or bunker ship. Moreover, the quality of the storage tank insulation finally defines the volume of BOG gas which needs to be compressed during normal operation.

Burckhardt Compression offers a wide range of Laby®, Laby® K-type, and Laby®-GI compressor systems, suitable to cover the required flow capacities of the LNG industry – both onshore and at sea.

Since the flow of BOG fluctuates greatly, capacity control becomes necessary. Compressor valve unloading is an efficient way to adjust the capacity of a reciprocating compressor by deactivating individual compression rooms. This makes reciprocating compressors in general more energy-efficient and power saving as competing screw or centrifugal type compressors.

Discharge pressure range

For onshore LNG terminals, the boil-off handling usually foresees the compression of the gas for the supply into a reliquefaction unit. Typically, a discharge pressure level of approximately 10 bar is therefore specified. With the same pressure, the natural gas can also be supplied into a power plant – if applicable.

Some terminals also consider the compression and supply of gas into the connected pipeline system. Depending on the local gas network characteristics, compressors must be able to deliver the gas at pressure levels of 30 bar up to 110 bar.

Such conditions might as well be specified for so-called minimum send out (MSO) compressors installed on FSRUs. Onboard LNG carriers, BOG is used as fuel for the main propulsion system and auxiliary engines. Modern slow-speed, two-stroke, dual-fuel engines are nowadays the technology of choice for the propulsion system of new-build LNG carriers. As there are two competing engine technologies available on the market, two different discharge pressures apply: zz High-efficient and low-emission electronically controlled high-pressure gas injection engines (ME-GI, diesel combustion cycle) require gas supply pressures ranging from 270 bar to 310 bar. zz Low-pressure gas admission engine technology (ME-GA and X-DF, Otto combustion cycle) are supplied on lower pressure ranges from typically 13 bar to 17 bar.

Summing-up the above, LNG BOG compression is characterised by almost identical suction pressure conditions but a larger variety of discharge pressure requirements.

Especially onboard LNG carriers and in receiving terminals, the gas compositions change with the quality of the LNG received.

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With the expertise of more than 50 years in the handling of cold gases – both onshore and on ships – Burckhardt Compression is offering a complete range of efficient and reliable compressor solutions for the entire spectrum of compressor selection parameters.

Technology for oil-free operation

Whenever cold gases must be compressed, Burckhardt Compression relies on Laby Compressor technology.

Invented in the early 1930s, the Laby labyrinth piston technology has a proven track record in the gas compression industry for almost 100 years. If compared with other competing technologies, the labyrinth piston principle convinces with its robustness, simplicity, flexibility, and longevity.

The simple three-piece design of the labyrinth piston reduces the amount of required parts to a minimum. The contactless sealing allows a wide range of operating temperatures and reduces wear in the cylinder section due to the absence of sealing elements. Frequent start/stop operations do not cause additional wear.

The key feature of Laby Compressors for its success in the LNG industry is the fact that the compressor can be oil-free and

flexibly operated at both very cold and warm suction temperatures. The compressor is able to directly take in BOG with the lowest possible temperatures – thus there is no need to pre-heat and condition the gas before compression. The use of special materials with the lowest thermal expansion co-efficients allows the operation of the compressor at suction temperature levels down to -160˚C. At the same time, the compressor might be operated with discharge temperatures up to 200˚C when handling warm temperatures at the inlet. The Laby Compressors provide flexibility and allow gas compression without the need for pre-heating.

Dry-running ring sealing technology The use of labyrinth piston technology gets less efficient with higher discharge pressures due to the internal gas leakages across the piston skirt and the application of ring sealed pistons becomes attractive. Classic ring sealing systems require the need for lubrication. However, the presence of oil in the chain of LNG transportation is not always welcome. Originally widely applied in the area of hydrogen gas compression, dry-running ring sealing systems are nowadays successfully installed in natural gas high-pressure compressors. This technology became especially important for high-pressure fuel gas supply compressors installed on LNG carriers – the Laby-GIs.

High-pressure compressor systems

Figure 2. Labyrinth sealing between piston (skirt) and

cylinder wall: the sealing effect is created by numerous tiny throttling points. Precise alignment of the parts allows contactless sealing. Wear on the piston skirt is very limited and lifetime of the parts very long. During operation, there is no permanent friction and only slight touching of parts.

There are cases reported where piston skirts reached a lifetime of more than 100 000 operating hours.

With the introduction of two-stroke, dual-fuel ME-GI engines for LNG carriers, high-pressure compression technology became required to provide the fuel gas at pressure levels of approximately 300 bar. Five stage Laby-GI compressors, combining labyrinth piston technique and sophisticated high-pressure ring sealing technology have been designed, to serve this specific application.

As one of the advantages of these high-pressure systems, excess BOG, which is not consumed as fuel in the engines, can be efficiently and simply reliquefied in a partial reliquefaction process. This open-loop reliquefaction system works without the need of a refrigerant and additional rotating equipment.

Gas-tight compressor crankgear

Figure 3. A two-crank, two-stage Laby D-type compressor

installed in an LNG receiving terminal. Due to the low suction gas temperature, the first stage cylinder block is entirely covered by ice. Despite the compression of the gas, the suction temperature of the second stage is still below 0˚C. Ice is also covering the compressor inlet nozzle and the suction valve covers.

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All Laby, Laby K-type, and Laby-GI compressors applied in the LNG industry are of gastight and pressure-resistant design (from 2 bar up to 15 bar) and there is no need for a continuous purging with inert gas. As piston rod sealings for reciprocating compressors are not entirely avoiding gas leakages, typical compressors require these packing leakages to be sent to a vent or flare system. The leakage rates might be small for packings in new conditions but develop over time with the wear of the packing rings. Depending on the wear rate of the parts and adherence of the operator to the maintenance schedule, significant amounts of leak gas can accumulate over time. Since natural gas – despite all of its advantages – unfortunately is a great contributor to climate change, it must be addressed that the total of packing leakages of the compressors installed in the natural gas industry are representing a big environmental threat to the planet. However, the gas tightness of Burckhardt Compression compressors avoids leakages to the environment.

All leak gas is internally recycled in the compressor system.

Based on the large number of Laby and Laby-GI compressor units installed in LNG terminals and on LNG ships, several thousand of tonnes of methane emissions are saved y/y.

Maintenance aspects – benefits of reciprocating piston machinery

Vertical aligned reciprocating piston compressors are of very similar design as reciprocating combustion engines. This makes the compressor design welcome and preferred by maintenance personnel all over the world, since maintenance routines and handling of components are easy to get familiar with.

This aspect becomes especially Figure 4. Typical flow diagram of a five-stage Laby-GI high-pressure fuel gas compressor attractive for ship crews, being installed on an LNG carrier. The compressed gas can be supplied to the ship’s main and auxiliary engines but also to a partial reliquefaction system. For reliquefaction, the gas able to carry out onboard service is compressed to 300 bar and cooled down to approximately -100˚C in a cold box. The activities on the compressor by low temperature of the LNG boil-off at the inlet of the compressor system is providing themselves after a relatively short the cold energy. Due to the expansion of the gas from 300 bar to approximately 4 bar training by Burckhardt Compression (Joule-Thomson effect), the temperature of the gas is further dropped and liquid can be service experts. separated in a knock-out drum. The liquefied portion of the gas is sent back into the LNG Regular maintenance of cargo tank whilst a smaller amount of so-called flash-gas is recycled to the compressor unit. These reliquefaction systems convince with their small footprint and simplicity, labyrinth piston compressors is not requiring additional refrigerants or rotating process equipment, such as pumps and mainly limited to the compressor compressors. Accordingly, both CAPEX and OPEX for such a system are very low. valves and piston rod gland rings. The absence of sealing elements on the cylinders limits the service tasks on the piston to a simple check of clearances and pretension values – no parts need to be replaced on a periodical base.

Depending on the application and pressure range, labyrinth piston skirts can reach a long service lifetime. This, of course, is different for ring sealing systems, facing continuous wear due to friction with their counter parts.

Burckhardt Compression develops Figure 5. Piston rod gland and piston rod packing leakages are recycled inside the and continuously improves the compressor system. No gas can leave the compressor, since there is a mechanical crank available polymer sealing shaft seal installed. Thus, all Burckhardt Compression LNG BOG compressors do not materials both for lubricated and contribute to methane emissions. dry-running sealing systems. The latest generation of dry-running Laby-GI, high-pressure compressors is equipped with state-ofwithout the need for larger service interruptions before the-art ring sealing technology, providing an expected lifetime reaching the dry dock. of up to 24 000 operating hours.

Due to their flexibility and robustness, Laby compressors are the ideal solution for the efficient management of LNG Conclusion BOG onshore and at sea.

All members of the reciprocating Laby product family (Laby, For approximately 40 years, Burckhardt Compression Laby Laby K-type, Laby-GI) operate reliably both under cryogenic and Compressors have played a key role in LNG BOG handling. Over warm suction conditions. On Laby-GI Compressors, for increased 100 LNG BOG compressor systems can be found in more than discharge pressures, dry-running ring sealing technology can 30 LNG terminals all over the world. 91 high-pressure Laby-GI be applied to higher compression stages. The gas-tight design Compressor units are in operation onboard modern LNG protects the environment from natural gas emissions and carriers, managing BOG and supplying fuel gas to high-pressure, saves operational costs by avoiding gas losses. The compressor two-stroke, dual-fuel diesel engines. Smaller Laby K-type BOG systems are low in utility consumption, as there is no need compressor units handle boil-off onboard 22 LNG bunker ships for continuous purging of the crankgear or preheating of the in operation. suction gas. Maintenance routines are simple, and operators With the growing use of LNG as a fuel in the ship industry, appreciate the uncomplicated handling of service activities. the Laby K-type compressor is as well applied on gas-fuelled Maintenance intervals of 24 000 operating hours help to keep merchant vessels, such as ultra-large container ships or oil the lifecycle costs low and allow ships to operate continuously tankers.

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Adam Sanders, STS Marine Solutions Ltd, UK, looks at the benefits of using LNG ship-to-ship transfer throughout all parts of the LNG supply chain, helping to solve the challenges that are arising as the industry evolves.

ver the past few years, the use of LNG has grown significantly, with FSRU terminals becoming more common, LNG bunkering starting to be a regular occurrence, and the global emissions reduction targets seeing LNG being used more frequently as a transition fuel. To allow for these things to happen, a step away from the traditional point-to-point shipping must occur.

For many years, LNG ship-to-ship (STS) transfer has been utilised for the replenishment of FSRUs at location, but now the market is seeing traders become more flexible and creative with the approach to the movement of LNG from point-to-point.

LNG STS is not only for FSRU bulk transfers, and in this market, threre is a need to be more flexible in the approach to deliver the client’s needs whilst maintaining efficiency in shipping costs. Events between 2020 until now have created a

volatile LNG market with prices and supply facing daily changes and challenges. STS Marine Solutions have been working with clients to provide solutions to assist with this by providing expertise to the market for various operations.

As stated, the market needs to have flexible solutions to sustain the growth and the varied uses of LNG which are occurring now and look to occur in the future. Next are examples of how the more common use of LNG STS can help the market keep up with the changes in demand and provide flexible solutions to all parts of the supply and use chain. The aim always for this market is to provide not only the most cost-effective but also the most efficient and environmentally sensitive approach. This is key if LNG is

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to keep its place as the transition fuel until further devolvements occur for the large scale use of non-hydrocarbon fuels.

Increasing berth availablity

The increased output demand on LNG terminals has made berth availability and scheduling a more critical process.

Ensuring the berth is available for offloading carriers is key

to supplying the growing market, however with the increased prices of LNG and supply needs, traders have in some cases chosen to heel out vessels at the discharge port in order to supply the maximum volume of cargo. This has the downside of arrival at the loading port of a warm vessel requiring a cooldown, and with the increased demand of supply, this is not always an option for berth availability. Working closely with the traders and the port operators, LNG STS has been successfully used to increase the berth availability and maintain the supply chain efficiency for all sides. This option for cooldown has not only been used for heeled-out vessels but also for vessels out of dry dock or long maintenance periods in order to be able to present a cold vessel for loading.

Moving cargos between ship classes

Figure 1. Manoeuvring alongside whilst underway.

Figure 2. At anchorage transfer.

The growing trend for the use of LNG as a fuel has and will lead to more small and large scale LNG facilities popping up globally. This has been very evident in Europe, within excess of five new FSRU terminals in the planning and development stage. The market has grown very used to the FSRU market and the need for a more environmentally friendly fuel, when compared to heavy fuels. However, the smaller scale market is something that is set to grow, and the company will play a role in ensuring the efficiency of supply to such a project.

In line with the growth in the LNG market, the diversity of ship types has continued to grow, with more efficient vessels coming out of yards y/y. However, increased efficiency does not always mean increased flexibility – with some berths globally draft and volume restricted, there is still a need for creative trading in order to deliver the suitable vessel with cargo to the berth. LNG STS options have been used to move cargos between ship classes, allowing traders to utilise the more efficient larger vessels for large portions of the journey before transferring to a more terminal-specific vessel for the smaller section; this provides the benefit of reduced boil-off and environmental impact whilst still delivering the parcels on time to the end user.

Amalgamating small cargos

Figure 3. Cooldown complete and liquid transfer underway.

A final example of LNG STS options in the market, which is linked to the development of LNG vessels, is that as part of the drive for greater efficiency from trader and shipping companies, many LNG vessels have increased the capacity of which they can carry from point-to-point. This is great when looking at the cost of movement per unit, but can also create issues with excess cargo when looking at loading into ports with limited storage capacity. This can leave ships in the difficult position with a small parcel remaining onboard with no discharge port for such a small amount. LNG STS has been, and will be more in the future, utilised to amalgamate such parcels at strategic STS locations. This again captures the efficiency of the larger vessels bringing the cargo to a location without leaving a partially loaded vessel.

Conclusion

Figure 4. Preparing for unmooring.

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The changing LNG market presents unique challenges to manage the supply chain to ensure that not only on-time deliveries occur, but also safe, efficient, and suitable methods are used. In this article are just a few examples of how LNG STS can be utilised to provide the solutions to traders to ensure LNG continues its growth to bridge the transition from fuel oil through to non-hydrocarbons fuels on a large scale.

Sven Lumber, Head of EcoTow, Group Operations, Svitzer, UK, outlines how the towage sector can improve safety and sustainability at LNG terminals, as well as highlighting the focus on decarbonising the industry. ince the shipping industry first engaged with the LNG sector, the two have worked closely together to mutual benefit. Early LNG tankers used boil-off to power their vessels, making use of what may otherwise have been inefficient waste. As both industries focus on the challenge

of decarbonisation, they stand to benefit once again from shared innovation.

Organisations and governments around the world are now taking air pollution and climate change seriously.

Shipping’s contribution to these pressing global challenges

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is increasingly coming into question, as the maritime industry is responsible for emitting approximately 1076 million tpy of CO2e, which totals approximately 2.89% of total global greenhouse gas (GHG) emissions.1 Shipping faces the difficult task of decarbonising while remaining profitable and powering the world’s economy.

Understandably, entire conferences are now dedicated to these efforts, as maritime companies, ship owners, and regulators pledge to act and ensure the industry reduces emissions and meets its climate targets – all while working out how to stay financially viable.

The International Maritime Organisation (IMO), the UN body that regulates the shipping industry, has set a target to reduce the carbon intensity of all ships by 40% by 2030 when compared to the baseline of 2008 levels, with the eventual aim of eliminating them altogether.

In Europe, even more ambitious decarbonisation goals are being set.2 The EU is targeting a reduction of GHG emissions by at least 55% by 2030 and aims to become climate neutral by 2050, which will require a 90% reduction in all transport emissions – including maritime.

In early March, the UK government also announced a new unit at the Department of Transport, which was specifically created to tackle shipping emissions and advance the UK towards a more sustainable maritime future.3 Companies now find themselves complying with varying regulations depending on where they are in

the world. This multi-speed regulatory approach has led to a fragmented landscape, with no clear-cut set of rules by which organisations must abide, or action plan they must take.

Other key barriers to decarbonisation in the shipping industry involve the sector’s reliance on fossil fuels, and the fact that assets last for decades. Decarbonisation must also be commercially viable for businesses, as most organisations simply do not have the capacity to completely and immediately replace their fleets based on speculative technologies. Equally for towage, there are not that many shipyards that can build tugs. This means change ends up being slow and hard to achieve in the timescale needed – especially as technologies that create alternative, zero-emissions fuels are still in development.

An immediate, intermediary solution Despite these challenges, the journey to decarbonisation must begin now. Regulatory pressure has outlined a need for speed, which has led ship owners and operators to look to LNG as an immediate solution. LNG enables the shipping industry to begin decarbonisation faster, without spending exorbitant amounts on new infrastructure. Companies can begin working towards meeting regulatory targets today, as opposed to waiting for technologies to develop and a future perfect solution fuel to be created. As a result, LNG-fuelled vessels now amount to approximately 13% of the current new-build order book,4 with 2021 shown to be a record year for LNG-fuelled new-building orders.5 Promising alternatives such as LNG need infrastructure to support them, and expertise to ensure that the fuel is bunkered safely and optimally. This has spurred the development of LNG-dedicated terminals which accommodate the large carrier ships that load, carry, and unload LNG before it is regasified for uses across the residential, commercial, and industrial sectors. LNG terminals will continue to have a key role to play in facilitating decarbonisation across many industries, and towage is essential to ensuring carriers can make their deliveries, embark safely, and that the import and export of LNG is not interrupted.

Figure 1. Svitzer’s fleet at work at an LNG terminal in Australia.

Figure 2. Svitzer’s fleet in action.

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As with any marine fuel infrastructure, safety is always paramount. However, LNG terminals have additional safety and environmental considerations when compared to traditional oil terminals. While natural gas is benign and will not explode or combust, when it is cooled it can be dangerous to handle, and requires skilled operators to handle it. Due to its extremely low temperature, there are cryogenic risks. LNG could injure people or damage equipment, for example, causing cold burns if it comes into contact with skin. LNG is also made up of 90% methane, which has high global warming potential, and so those handling it must be extra careful to avoid any spills or leakages.

As the shipping industry continues to decarbonise, LNG terminals will continue to grow in number and scale. Towage is a key part of the supply chain that helps move LNG from vessels to ports and on to its next destination. As such, operators must be well-trained to ensure that the

service for all your LNG needs

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Through our parent owner we seek opportunities to make capital investment in your LNG project for mutual, profitable collaboration.

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regulations are met when handling the LNG, but also take the necessary steps to ensure crews remain safe and that accidents are kept to a minimum.

It is due to LNG’s extra safety implications that the common practice at LNG terminals is to award towage contracts to a sole operator for an extended period of time – normally between five and 10 years. The tendering criteria for winning these contracts is how safely the operator can keep operations running. In the past 12 months, Svitzer has signed two 10-year contracts to service FGEN LNG Corporation’s LNG import terminal located in the Philippines,6 and Woodside’s LNG export operations in Western Australia.7 There are additional benefits for towage operators that do meet the higher threshold of safety requirements required and win long-term contracts to service LNG terminals. The stability of operating at these terminals gives towage operators the time, space, and opportunity to make positive commercial decisions that have a long-lasting effect on the safety, efficiency, and sustainability of the operations.

In a normal port, the competitive atmosphere of towage can create situations that could be characterised as a race to the bottom. Innovation is stifled as operators must compete on price point and worry if there will even be jobs for them to carry out tomorrow. However, with contracts awarded to a single operator at LNG terminals, they have the time, freedom, and ability to plan and provide robust training and professional development programmes for members of the local workforce operating the tugs, as well as develop strategies that drive innovation contributing to wider sustainability aims.

While health and safety and costs are key considerations for towage operators delivering services at LNG terminals, decarbonisation is always part of the conversation. In its latest Gas Market Report, the International Energy Agency projects global LNG trade will increase by 5% this year.8 As towage steps up to support the growing LNG market, the sector also faces an increased responsibility to match the decarbonisation efforts of the wider shipping industry. Towage operators need to begin considering how to improve their carbon footprint while continuing to safely and efficiently deliver their service.

There are great examples of operators delivering towage services that are championing decarbonisation and showing how it can also be possible for others. Svitzer has begun taking decisive action to use biofuels at the LNG terminals where the company operates. With the benefit of long-term contracts at these terminals, Svitzer has the ability to continue servicing the growing demand for LNG, while also finding new ways to decarbonise the supply chain.

The company currently has five tugs serving the Isle of Grain LNG terminal in Medway, UK, which has been running entirely on hydrotreated vegetable oil biofuel since November 2021.9 Alongside the obvious environmental upsides of using biofuel in this way, the EcoTow project has also confirmed that it is operationally and commercially viable to use biofuels in the towage sector. Following this pilot, Svitzer made the decision to convert its whole fleet of 10 tugs in London, UK, and Medway; all are now powered by marine biofuel.

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In tackling decarbonisation, Svitzer benefits from being a global organisation. This has enabled the company to pilot different schemes out of different ports and see what works best. Through the company’s global network, Svitzer has also been able to offer customers the opportunity to use EcoTow to inset fossil-free towage even if they do not call at London or Medway.

The future of the sector

The environmental question dominates the agenda of the global industry discussion and is no longer something that can be left to a later date. The process of decarbonisation will not be easy for any part of the shipping industry. Difficult decisions will have to be made, timelines brought forward, and investments made in order to reach climate targets.

Decarbonisation must also consider emissions from ports, as well as at sea. As in the rest of the shipping industry, what has now become abundantly clear is that tug owners and operators need to take action to reduce their carbon footprint.

While the towage sector certainly has unique challenges to overcome, there are steps that can be taken to not only decarbonise but ensure safety, especially in LNG terminals.

LNG terminals will continue to play a key role as organisations across all industries begin to transition through fossil fuels to eventually use the net zero carbon alternatives currently in development. As a result, LNG terminal activity is set to continue growing. And so long as ships need to enter and leave ports across the globe, towage operators will always be part of the equation. Robust training programmes for tug crews that meet the additional safety requirements at LNG terminals are key, as are efforts to make these fleets more environmentally sustainable.

The good news is that there are positive examples of success in the towage sector when it comes to using biofuels.

This is largely thanks to the contract stability and focus on excellent safety standards at LNG terminals that help to create an environment in which operators can pursue wider innovation. However, it is critical that more of these initiatives are put in place to remove carbon from supply chains across the wider shipping industry in order to meet the 2050 carbon emissions target set out by the IMO.

References 1.

International Maritime Organization, ‘Fourth Greenhouse Gas Study 2020’, (2020).

2.

European Commission, ‘Proposal for a regulation of the European parliament and of the council on the use of renewable and low-carbon fuels in maritime transport and amending directive 2009/16/EC’, (2021).

3.

Department for Transport, Courts MP, Robert, and Shapps MP, the Rt Hon Grant, ‘DfT launches UK SHORE to take maritime ‘back to the future’ with green investment’, Gov.uk, (March 2022).

4.

Sea-LNG, ‘2021 Outlook for LNG A View from the Bridge’, (January 2021).

5.

Wold, Martin Christian, ‘2021 – what a year for #LNG contracting!’, LinkedIn, (January 2022).

6.

Svitzer, ‘Svitzer Amea signs 10-year contract with FGEN LNG corporation’, (July 2021).

7.

Svitzer, ‘Svitzer awarded Western Australia LNG terminal contract with Woodside’, (January 2022).

8.

IEA, Gas Market Report, Q2-2022, (April 2022).

9.

Svitzer, ‘Svitzer introduces carbon neutral towage services’, (November 2021).

Andy Foreman, Amarinth Ltd, UK, describes the challenges of designing cryogenic centrifugal pumps for LNG processing, as well as outlining how these pumps are developed to handle the industry’s unique demands.

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he global demand for energy is growing again, and natural gas, the cleanest burning fossil fuel, is forecast to play a vital role in balancing economic growth and environmental responsibilities, with a projected growth in demand for LNG of 30% by 2040. Despite the short-term reduction in energy demand caused by the COVID-19 pandemic, the US Energy Information Administration (EIA) predicts that global energy demand will rebound to its pre-crisis level in early 2023 whilst also taking advantage of cleaner technologies than traditional coal and oil.

Cryogenic pumps

The production of LNG requires robust and reliable pumping solutions to move the gas through the necessary processes, often in challenging and hostile environments.

At the front end, there is separation of gas and liquids, including mono ethylene glycol (MEG), from the raw gas feed. The separated gas then goes through steps to remove acid gases (such as CO2 and H2S), water (from the amine solvent used to remove the acid gases) before it is ready for liquification. Initial gradual cooling removes heavy liquids (such as benzene and other aromatics), and then the gas is finally liquified at atmospheric pressure by cooling down to -165˚C, which reduces it to approximately 1/600th of its original volume. From this point, any further processes and transfers including storing in tanks, bunkering, and loading and offloading onto vessels for transportation around the world, requires pumps that can operate dependably at this extremely low temperature. These pumps are termed

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cryogenic pumps, as the cryogenic temperature range is defined as anything below -150˚C. Amarinth designs and manufactures centrifugal pumps for the oil and gas industry and can deliver the duties demanded by the LNG industry, including many of the world’s LNG plants and floating LNG (FLNG) vessels. In addition to oil and gas, Amarinth’s expertise extends to cryogenic pumps used by other industries working with liquified gases such as oxygen, hydrogen, carbon dioxide, and nitrogen, some of which require temperatures down to -190˚C, even colder than for LNG, and so the company brings a wealth of knowledge and expertise to the LNG industry in the design of cryogenic pumps.

The cryogenic pumps for LNG are specialised and are specified for the unique demands of the industry, which includes submersion pumps in LNG at -160˚C, cooling down and warm-up procedures, low NPSH operation, condition and vibration monitoring, safety features, and specialised testing.

Specifications for LNG pumps

The design and manufacture of cryogenic pumps is tightly regulated, and so close attention must be given to published standards to ensure that the pumps operate reliably. The main specification for LNG centrifugal pumps, along with the rest of the oil and gas industry is: zz API 610 – Centrifugal pumps for petroleum, petrochemical, and natural gas industries.

Reference is also made to several other directives due to the cryogenic operating temperatures, including: zz NACE MR0103 – Petroleum, petrochemical, and natural gas industries – metallic materials resistant to sulfide stress cracking in corrosive petroleum refining environments. zz NACE MR0175 – Petroleum and natural gas industries – materials for use in H2S-containing environments in oil and gas production – part one: General principles for selection of cracking-resistant materials.

In addition, reference is made to the following industry, international standards, and directives: zz European directives – ATEX, EIGA/IGC/CGA guidelines. zz Marine class certifications – ABS, DNV, BV, LR. zz International electrical standards – IEC 60034, 60079.

However, manufacturers must also make sure that their pumps meet operators’ hydraulic requirements, which may include duties such as low NPSH operation, and that they operate cost-effectively and are easily maintainable over their lifetime to minimise costs, and this is where the knowledge, skills, and ingenuity of a pump manufacturer successfully delivering pumping solutions to the broader oil and gas industry are very relevant.

Hydraulic specifications

Cryogenic pumps, like any other pump, must be well matched to the hydraulic requirements of the application to deliver reliable, long-term, cost-effective service. Design considerations include the required flow rates, suction pressure, and NPSH available and required (which will determine, for example, the usable and non-usable volume of a storage tank).

In some applications, such as where headroom is restricted, cryogenic pumps may operate at low NPSH and so special consideration will then need to be given to low NPSH pump design and high-efficiency impellers to prevent impeller cavitation occurring, which could have disastrous consequences.

Materials

Figure 1. Pump materials must be carefully selected for cryogenic use.

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The pumps are in direct contact with the LNG (usually submerged in the LNG) and so are operating at cryogenic temperatures. The pump, and associated equipment such as valves, must be therefore manufactured in suitable materials for these conditions.

For most pump applications in the oil and gas industry, the materials are selected for corrosion resistance, and certain compromises must be made. However, within LNG applications there is not the same issue with corrosion (as LNG is non-corrosive), and it is therefore possible to manufacture in a range of materials more based on their suitability for the specific functions of the cryogenic pump service.

The duplex stainless steels frequently used for oil and gas pumps become brittle as the temperature is reduced and so the primary selection for cryogenic services is stainless steel 316. This is an austenitic stainless steel and does not exhibit an impact ductile/brittle transition but a progressive reduction in Charpy impact values as the temperature is lowered and so it is much more suitable for cryogenic temperatures. Alternative materials such as

aluminium can also be used due to its stability, excellent thermal conductivity, ductility at low temperatures, and smaller variance in size with large temperature variations. Wear rings and bushings are often manufactured in bronze (and sometimes graphite) for their thermal characteristics in the required temperatures.

However, it is of the utmost importance that any materials selected can be cooled from ambient to temperatures between -150˚C and -190˚C and then warmed back to ambient temperatures without detriment to the build and integrity of the pump equipment.

Within the LNG industry, material traceability is also crucial to product integrity. API 610 sets out traceability requirements, and so pumps for cryogenic application in the LNG industry will often be 3.2 certified, or as a minimum of 3.1 certified.

Equipment

The greatest challenge is to maintain optimum temperatures of each element of the equipment so that it runs efficiently over the long-term to reduce lifetime costs for the operator.

Motors

The induction motors in cryogenic pumps are integral to the pump equipment, and so many of the usual challenges of matching motor shaft bearing loads to the pump is eradicated and the whole motor is optimised for the required pump application.

Although fixed speed pumps have their place, to vary performance the pump is mechanically throttled utilising discharge control valves, severely impacting pump

efficiency (reduction). The efficiency and range of operation for pumps in cryogenic service can be significantly improved using variable speed controls. Adjustment of the speed allows for accurate control of the operating characteristics of the pump over a greater range with better overall efficiency. The efficiency of pump operation at flow points that are off design can be improved by varying the pump speed to a point on the pump hydraulic curve which matches the best efficiency point (BEP, the point at which the pump operates at peak efficiency) for the desired flow. This provides reduced operating costs, a higher level of control of the loading/offloading processes, and allows the pump to always operate at its optimum.

Seals

In LNG applications using submerged cryogenic pumps, LNG is allowed to enter the motor. This eliminates the need for seals, and in addition is used to cool the motor. Static seals would therefore only be required for the electrical and instrumentation elements. For cryogenic applications in general, there are a range of shaft sealing solutions should these be required for any reason. These include gas face technology single mechanical seals with purging outboard of the seal to ensure liquified gases do not escape into the atmosphere (due to their flammable state). Alternative solutions can utilise labyrinth seals with alternative containment measures.

Instrumentation

Careful consideration must be given to the instrumentation.

These are best mounted within environmental heated enclosures, for example within heated cabinets.

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Some pressure gauges can also be silicon oil filled, allowing them to operate at much lower temperatures than normal, but in general, instrumentation will need to be isolated from the extreme cold environment.

Condition monitoring

Cryogenic pumps usually function within what is defined as a hazardous area, and so it is of the utmost importance that these pumps maintain a high integrity. Therefore, the pump is closely monitored for mechanical vibration with the use of accelerometers within the pump housing and resistance temperature detectors (RTDs) to ensure no hotspots occur within the motor arrangement. These monitoring devices all need to be intrinsically safe (i.e. designated IS devices within the International Standards) to operate within the defined hazardous area.

As with any pumping scenario, parameters such as pressure, flow, and motor amps will be monitored as indicators to pump running performance compared against new parameters. These also provide early indicators of other potential failures, such as presence of vapour should LNG start converting to its gaseous state.

Cooldown and warm-up procedures

Before operating with LNG, pumps (along with pipelines, tanks, and other ancillary equipment) must be pre-cooled to prevent stress on their materials from overly rapid cooling, or the LNG converting to gaseous form. Similarly, warm-up procedures are also an important consideration, particularly when pumps and equipment are being prepared for inspection or maintenance. Cooldown and warm-up procedures therefore need to be carefully considered when specifying the pump so that the pump manufacturer can model the thermal expansion properties of the equipment to minimise stress and possible separation of components.

Figure 2. 316 stainless steel is frequently used for cryogenic pump casings.

Testing

As a result of the unique design of cryogenic pumps and the very low operating temperatures required, they cannot be tested with water in the usual way. Cryogenic pumps for the LNG industry must be tested with LNG to verify their performance, in so far as possible, under the conditions of actual usage. This will verify, for example: zz Performance of the motor and its ability to start in the cryogenic environment. zz Pump performance characteristics operating in the cryogenic fluid, which is also crucial for NPSH testing, particularly for when the pumps will be used in low NPSH environments. zz There is no internal leakage due to differential shrinkage and expansion when all the components are working at their actual operating conditions and temperature and during cooldown and warm-up.

Summary

Figure 3. Comprehensive condition monitoring equipment ensures cryogenic pumps operate safely and reliably.

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The unique requirements of moving LNG at cryogenic temperatures mean that the pumps must be specifically designed for the required application, meeting an extremely high standard of durability and reliability. As a result, a broad range of skills and expertise are required in the specification, design, material selection, manufacturing, and testing of these pumps which needs to be drawn from the demands of the oil and gas industry as a whole and specialist cryogenic experience. This ensures that the pumps will meet the required duties and operate reliably and efficiently over their lifetime in extreme conditions.

Danny Constantinis, Executive Chairman and CEO, EM&I Group, Malta, outlines the integrity challenges of cryogenic storage, showing how overcoming these barriers will be integral for the LNG industry whilst supporting Europe in the transition to renewables.

NG will be critical during the transition to renewables and to ensure supplies to Europe, so adequate and efficient strategic storage facilities to cope with disruptions will be required.

Over the past few years, the LNG market has changed significantly from its traditional model of long-term, fully integrated supply contracts, whereby the field developer would produce and liquify the LNG onshore, transport it using the specialised LNG carriers, and supply a fixed volume of LNG to a single entity, such as an energy provider, to more versatile models, which include spot trading, bunkering, and development of independently owned and operated floating LNG (FLNG) production facilities and FSRUs. In the original model, the raw gas was piped to a land-based reliquefication plant where it was converted to LNG. An LNG carrier, with insulated tanks to maintain a temperature of approximately -163˚C, transported the LNG to a shore-based storage facility where it was then delivered to a regas plant and later sent to a pipeline for domestic consumption or directly to a power station for conversion to electricity for domestic supply. This model worked well, especially for hydrocarbon-starved nations who preferred gas as their main source of energy.

Next came the large near-shore or land-based gas fields where new infrastructure transported the gas produced across national boundaries, over long distances, generally by pipeline, to feed power stations in places such as Europe, the US, etc.

However, as has been seen with recent events, over-reliance on pipeline gas supplies can create problems when a political situation threatens to interrupt the security of supply. Considering the current situation in Ukraine, trading patterns have been redrawn to make up for any interrupted supply in the future. Countries who relied upon pipeline gas as their primary source of gas supply are now rethinking those strategies. For instance, more LNG is being shipped from the US to Europe. Countries with available coastline are now looking at the provision of independent floating storage and regasification facilities to be the main source of supply for domestic consumption.

Coupled with this security of supply issue, the original model also changed when local regulations made it more difficult for new facilities to obtain permits to build LNG storage tanks onshore, especially near built-up areas. Lack of LNG storage onshore meant that gas cavern storage acted as

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an acceptable method of storing gas (as opposed to LNG). Gas storage under pressure has been used since 1917, so it has a long track record, and there are currently several such storage areas in Europe and the US where gas is stored in salt caverns, salt domes, or aquifers. Even this method of storage comes with limited capacity and strict regulations, especially if the cavern is located near an urban area.

The beginning of the FSRU

In order to resolve not only the regulatory issues but also some potential credit issues for countries who have a sub-optimum credit rating, the regasification plant was integrated with the LNG carrier and the FSRU was born.

These connected a floating gas storage/regasification unit to a jetty or buoy for significantly longer periods than traditional gas carriers, while either all or part of their cargoes were discharged ashore. The need for continuous send-out depended on whether they were base load (providing the main supply) or peak shaving facilities (when they supplemented the existing energy provision during high demand periods). More and more of the world’s FSRUs are becoming a primary source of energy for power plants. This model is likely to continue as the world transitions to greener energy.

On the production side, stranded gas fields were being developed using independent floating production facilities, much like in the past when remote oil fields were monetised where no pipeline infrastructure existed before. Production and supply became a possibility once the offshore conditions could be managed to permit the safe transfer of oil offshore to visiting offtake tankers.

New technology came along which enabled discharge of the oil via floating or aerial hoses, either in a tandem configuration (where the visiting tanker was tethered to the after end of the floating facility using a station keeping tug), or when the visiting tanker kept station a fixed distance off the floating production facility using dynamic positioning (DP) technology (where use is made of the offtake tankers engines, power plant, and GPS or transponder-enabled positioning systems).

New technology opens up opportunities

Once the technology transitioned to the LNG world, it was not long before the FLNG regasification and production facilities became a reality. FLNG comes in many forms, e.g., non-land-based facilities, which could be either at shore (e.g., alongside a land-based jetty in an enclosed harbour), near-shore (where the facility is connected to a semi-exposed jetty or moored by using an integrated turret/buoy), or offshore (where the facility is exposed to more open-water weather conditions).

All three varieties are relevant to both FLNG production facilities and FSRUs, and there are many examples of these in the world today. Newer variations are coming to the market every day, with the LNG power barge being the latest arrival, which stores LNG and generates power directly on the floater, to connect directly into the local electricity grid.

One thing all these LNG facilities have in common is that they float. But once on location, and depending on the type of contract in place, there is a possibility that these floating Figure 2. Integrity class remotely operated vehicle (ROV). facilities will never see a dry dock for the entire duration of their contracted lives. So, much like their Table 1. Containment systems oil-producing FP(S)O cousins, these facilities must adopt a different type Membrane type Independent type of inspection and maintenance regime to continue operating in a GTT Mark III GTT No. 96 Moss IHI-SPB safe and efficient manner.

Al alloy (A5083) Ni Conventional trading LNG carriers Invar (36% Ni) Al alloy (A5083) Tank wall thickness SUS 304L 1.2 mm 9% steel SUS304 0.7 mm 50 mm are subject to regular inspection 10~25 mm regimes by recognised classification Reinforced societies, usually involving spending Plywood box + Polyurethane Polyurethane Insulation thickness polyurethane perlite 530 mm foam 250 mm foam 250 mm periods at wet berths or dry docks. foam 270 mm These involve detailed internal and Gross tonne (138 K) 92 900 (100%) 95 500 (102%) 111 000 (118%) 103 000 (110%) external inspections of the hull

Figure 1. NoMan laser scans of LNG membrane.

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(including tanks) and machinery, tail shaft, etc., and include activities such as hull painting, when necessary.

So, what happens when this option is no longer available?

Classification societies have already adapted their rules for the construction and inspection of FSRUs and core elements of the offshore rules already provide a strong foundation to be applied to these and the LNG production facilities. This can then be supported by class with specific guidance for the unique project type.

Safety protocols

Safety has always been paramount in the LNG industry, and it is founded on an excellent historical track record. Every LNG operator is keen to maintain this record and they are constantly looking at ways to maintain or improve current safety performance levels. Enclosed space entry and underwater activities are probably the two highest risk areas and biggest causes of fatalities or serious injury in the offshore industry.

Safety protocols can be put in place to mitigate or manage the risk, but the easiest way to remove this risk is to remove humans altogether from these tasks and to replace them with more modern technology. For instance, instead of rope access personnel hanging from heights, carrying out inspections in tanks, or divers used to carry out underwater inspections in marginal conditions, new technologies can be used as a safer, more efficient, and more importantly, approved alternative.

Operators in the offshore oil and gas sector are already making this technological transition and are adopting their inspection and maintenance regimes to lower the risks to humans, while at the same time embracing new technologies to develop more remote methods of inspection such as laser scanning, X-ray inspections, use of drones, use of remote operated vehicles (ROVs), and the use of cloud-based systems to store and access this digitised information. In fact, the whole digitisation piece is gathering momentum across the board. Internet of things (IoT) and offshore technologies (OT) are improving the way companies are able to monitor and learn how systems are operating, and allows them to manage and interpret information in a more efficient way. The opportunities are endless as more innovative methods of maintenance and inspection continue to be developed.

Figure 3. LNG membrane test piece and NoMan optical inspection.

The main LNG storage tanks

LNG storage tanks come in three main types: spherical, membrane, and self-supporting prismatic shape IMO type B (SPB). For the FLNG industry, SPB technology is still some way off, so it is important to focus on the two most popular storage methods currently in use. Spherical tanks (Moss tanks) and membrane tanks are the two most common containment systems. Moss tanks are robust and are perfectly suited for all environments, i.e., at shore, near-shore, and offshore. They are more resistant to sloshing risk (due to their shape), and can store the LNG at a slightly higher pressure (approximately 3.2 psi).

Membrane tanks have come a long way since the original designs. Reinforced membrane tanks are now more resilient and can also be used in all three environments.

Carrying out tank inspections

LNG tanks do require regular inspection (as per classification society rules) to ensure the integrity is being maintained

Figure 4. Real-time radiography for detecting corrosion under insulation (CUI).

and everything is as it should be. Early warning of a problem developing is always the best way to manage it, and data-driven inspection and survey is perhaps the next evolution which supports both prescriptive regimes and risk-based inspection (RBI) philosophies.

But how can this be achieved without tank entry? A recent FloGas JIP workshop reviewed all the classification societies’ inspection requirements. It was recognised if the tanks were warmed to approximately 10˚C or above, purged, and gas freed, the risk levels of dangerous fluids being present is so low that by adopting an ALARP approach, it would still be safe enough to enter the tank to carry out inspections, provided that working from heights could be avoided.

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Trying to carry out inspections without any man-entry is possible, but the benefits of so doing may be marginal, especially considering the challenges of getting robots into the tank via the vapour dome or pump tower.

To explain further, the biggest difference between a standard tanker’s oil tank and an LNG tank is that there are little or no residues in LNG tanks, i.e., no requirement to tank clean, no sludge or scale build-up which could trap hydrocarbons, and no complex internal structures which could prevent optimum drainage. LNG tanks are big, open, cathedral-like structures, and the only residues tend to be a slight dust. So, the risk in LNG tanks is likely to be significantly lower. Nevertheless, it is still an enclosed space entry so great care must be taken when putting personnel inside.

Even when there are inside membrane tanks, because of the way they are built, the areas of physical inspection are

Figure 5. Digital radiography for detecting CUI.

limited to the bottom (C wall), lower sloping walls at the sides (G and K walls), and the lower section of the end walls (B and D walls), so it is incredibly difficult to truly measure any anomalies, especially higher up on the vertical side walls, where sloshing damage is most likely to occur.

One possible way to carry out a thorough tank inspection would be to use optical and/or laser scanning. This would entail setting up a camera on an extendable tripod and to carry out a 360˚ scan of the tank. The optical inspection (general visual inspection (GVI) and close visual inspection (CVI)) is fully accepted by class, and a recent piece of work carried out by EM&I on a membrane test piece using laser scanning systems proved to be very effective at identifying anomalies of various sizes on the membranes at distances of 10 m. As a matter of fact, the camera used in the test still had optical and digital zoom capability, so the tested 10 m will be extended significantly to enable the tank to be inspected from one, or a maximum of two, locations. This would allow even the inaccessible parts of a tank to be scanned in a few hours, and the results digitally processed, to provide an accurate status of the membrane and to set a datum for future trending.

With methods such as optical or laser scans, a comparison model can be developed from a baseline scan taken at the construction yard. This way, any changes in the tank surface can be quantified from construction and early action can be taken, such as altering the loading and discharge strategies in order to mitigate the risk of more serious damage and to avoid having to remove one of these valuable assets for lengthy periods from their terminals to be repaired at a shipyard.

UAV technology can also be used to provide an additional tool for surveys and inspections, noting that they have somewhat limited duration and the potential to act as a dropped object.

Other advanced technologies will also benefit floating gas operators when inspections and maintenance of valves or hulls are needed subsea.

Advanced methods do not only apply to pressure systems and structures: ex-equipment integrity assurance is every bit as vital a barrier to catastrophic incidents.

The ExPert technology, comprising advanced NDT and intelligent risk-based software, has been developed and is now being applied across many assets to provide additional safety protection with lower human risk and costs.

Advanced methods of inspecting for corrosion under insulation (CUI) without stripping insulation off are also available.

The need to put people inside pressure vessels is also rapidly diminishing with the introduction of remote but high-performance cameras whose ability to detect even minor anomalies has been validated independently.

Conclusion

Figure 6. ExPert optical camera.

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New inspection and data management technologies have created a revolution in how a company can assure the integrity of gas storage and transportation in a safer and more cost-efficient way.

The offshore LNG industry has so far been at the forefront of this development, and this will likely continue as these new processes and technologies become well-established and open the doors for even newer energy sources, such as hydrogen.

Liam Hanna, NDT Robotics and Scanners at Eddyfi Technologies, UK, outlines the critical factors in an efficient inspection programme for LNG tank maintenance, focusing on deployment and delivery.

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eing able to do more with less is especially applicable when it comes to better LNG tank maintenance programmes. The modern-day smartphone is an excellent example of this, with its ability to enable so much more than simple verbal communication functionality. In the non-destructive testing (NDT) world, the same concept of getting the most out of the inspection technology has seen product advancements that have pushed the boundaries of what is truly possible today. This is not unique to process plants, as any industrial manufacturer understands the need to reduce downtime for maximum productivity. The LNG industry has witnessed the shift towards risk-based inspection (RBI) to minimise shutdowns and take advantage of available resources during planned outages. Of course, using the right NDT method is imperative to increase efficiency, but delivery and deployment are a key factor for success.

Developing new technology

The LNG industry presents a multitude of challenges. When considering commercially available products, it is important to understand what engineers and product teams ask themselves in the development of the solution. Does it enhance safety? Improve environmental performance? Increase operational efficiency? Aid in cost reduction or even avoidance? From transportation, treatment, refrigeration, liquefaction, storage, loading, and back to transportation again, the LNG industry is a perfect example of how NDT solutions can increase safety and performance and protect the environment at every stage throughout the process.

Whether operating in oil and gas, power generation, energy, nuclear, maritime and shipping, defence, utilities, or another critical industry, key applications repeat themselves: pipeline inspection, surface inspection, and

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vessel inspection. Given the capital infrastructure that makes up LNG plants and the closely integrated individual systems, for example a pipe or a vessel, these systems always remain as pipes or vessels. It is understood that the inspection requirements may change, as may the technology being deployed. Eddyfi Technologies can offer diverse inspection solutions spanning multiple technologies, from ultrasonics such as conventional ultrasonic testing (UT), phased array UT, total focusing method, time-of-flight-diffraction (TOFD), or electromagnetic techniques, including alternating current field measurement (ACFM®), eddy current, eddy current array, pulsed eddy current, and magnetic flux leakage.

However, the glue that holds everything together and allows for a truly remote, unmanned inspection solution is the delivery and deployment method.

Whether that is a simple NDT scanner to aid in repetitive or awkward placement of probes for specific LNG equipment inspections, more automated crawlers for weld and corrosion mapping, or robotic solutions for ad hoc, hard-to-reach assessments in areas where a human cannot or should not be sent. Within the LNG market, these solutions are available to solve problems, reduce downtime, and increase efficiency in multiple areas along the chain.

LNG inspection improvements

LYNCSTM is an advanced modular ultrasonic inspection scanner designed to provide phased array

Figure 1. Phased array ultrasonic testing (PAUT) corrosion mapping data, showing reliable results delivered.

Figure 2. The multi-functional LYNCSTM scanner by

Eddyfi Technologies addresses LNG PAUT inspections across multiple assets.

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ultrasonic testing (PAUT), corrosion mapping, and PAUT or TOFD weld integrity assessments. The versatile system allows users to interchange between weld inspection and advanced corrosion mapping in under one minute. Onboard scanner controls allow for one-man operation, with seamless integration to the portable Gekko® and MantisTM phased array instruments. When the device is in weld inspection mode, operators can start and stop a scan. When it is in corrosion mapping mode, operators can increment or stitch together data without touching the PAUT instrument.

LYNCS, and other crawler and robotic solutions offered by Eddyfi Technologies, supplement decreased downtime and increased operational efficiency by: zz Reducing the time an LNG plant is shut down for. zz Allowing solutions for in-service inspection. zz Performing inspections where multiple data sets and maintenance can be carried out in unison.

When faced with confined spaces, heights, and other hazardous areas, robotically deploying probes offers a better solution, such as using the ACFM electromagnetic testing technique. It offers distinct advantages for the inspection of the gas storage spheres, or Horton spheres, commonly found among LNG facilities. It requires minimal surface preparation, meaning that the protective layers found on support vessels, piping, etc. remain unscathed.

Without the need for consumables to detect surface-breaking cracks in metals, which would normally be used in conventional methods, ACFM works through coatings and can be used as a screening tool ahead of significant surface cleaning to prevent unnecessarily preparing LNG assets without cracks. It provides depth sizing to establish thresholds for inconsequential cracking, which in turn prevents any unnecessary grinding. When compared to wet fluorescent magnetic particle testing (WFMT), ACFM has proven to be approximately 60% faster – and this was evaluated with the older, slower legacy ACFM technology. Three times faster than magnetic particle inspection (MPI), and even quicker when report writing is considered, a Petrobras gas storage sphere ACFM inspection found twice as many crack indications as MPI.1 Today’s SENSU®2 compliant array technology is NDT crawler adaptable and offers a wider coverage with spring-loaded sensors. Moreover, the technology allows scan speeds of 50 mm/sec. for data acquisition, regardless of remote-controlled operation.

This is just one example of the importance of delivering the right NDT technique alongside the right deployment and delivery for higher productivity. Expanding on this, the MaggTM Enabled allows for a standardised approach for multi-sensor robotics, remotely deployable up to 100 m, and operable subsea up to 60 m (depending on supplementary NDT technique chosen), with tool-free probe mounting for ultrasonic testing, phased array UT, eddy current array, and ACFM. This configuration affords a modular, deployable solution that is easy to use, with training readily available remotely through the Eddyfi Academy. In general, the Magg is a proven and reliable remote inspection crawler designed to withstand the harsh conditions and industrial environments found in LNG production. The technology can quickly and easily navigate

critical restricted access areas, whether the surface is clean or close to unpractical. The unique combination of raw power, agility, and magnetic downforce allows the NDT robot to accomplish LNG inspections that most wheeled vehicles and crawlers simply cannot.

Costs can be reduced or avoided by limiting or removing the expensive actions and operations associated with scaffolding, cleaning, taking the asset offline, and human entry to confined spaces. Cost drivers overlap with other drivers. For example, an inspection robot that is capable of carrying out multi-sensor NDT enables reduction in overall downtime, further reduced human entry, lower environmental impact through crawler mounted tooling operation, and improvement in safety as maintenance personnel no longer need to enter the LNG tank, vessel, or other confined spaces.

So, while the NDT techniques may be tailored and vary for LNG tank maintenance, the delivery and deployment are a key factor in quite literally being able to do more with less. Whether performing corrosion mapping on the outer shell, assessing T-joint attachments, or checking out a tank roof, NDT scanners and robotics that provide multiple inspection technologies and applications are visibly making a difference in terms of increased productivity at LNG process plants worldwide.

Conclusion

NDT is at the heart of monitoring LNG tanks and other critical assets for their structural integrity to help ensure

The premier source of technical and analytical information for the renewable energy industry, covering solar, wind, bioenergy and storage.

the prevention of any potentially catastrophic failure resulting in environmental contamination and loss. A strong risk management programme will go beyond meeting relevant regulations to further optimise the inspection and maintenance activities designed to improve reliable performance and profitability of terminals. This is achievable, in part, through RBI methods and the implementation of inspection robots and scanners for in-service remaining life asset integrity assessments.

These in-service assessments are necessary to identify potential areas requiring an update, repairs, or routine maintenance for current and future needs during planned shutdowns. It is imperative that the NDT device performing non-intrusive inspection and/or remote internal inspection collect repeatable, actionable, meaningful, and preventative inspection results; moreover, it should be capable of collecting multiple datasets in real-time to provide a complete picture of current conditions. This enables better forecasting and better decision making, due to a code compliant and permanent record of inspection. In an industry that cannot afford for things to go wrong, innovative technology takes the guesswork out of choosing the right technique at the right time and delivery by the right deployment method.

References 1.

TREMBLAY, C., ‘More Productive Process Plant Inspections with ACFM®,’ https://blog.eddyfi.com/en/ more-productive-process-plant-inspections-with-acfm

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Maximilian Rockall, UK, and Michelle Glassman Bock, Belgium, Squire Patton Boggs, detail the ongoing impact of the Russia-Ukraine conflict, focusing specifically on the impact it is having on the Asian LNG market. hile energy markets are designed to sustain periods of volatility and uncertainty, the past 24 months have sought to test their elasticity and durability. Even though markets evolve and react to bouts of uncertainty over time, the Russia-Ukraine conflict has impacted not only the European gas market, but has also caused significant upheaval in the Asian gas market. Indeed, its effects are being felt in all major import markets around the world as market players assess their portfolio volumes and contractual flexibility and prices in an effort to develop commercial and legal strategies to best confront the multiple issues arising out of the conflict.

While the spotlight has primarily focused on events in European gas markets, serious issues have also arisen for importers in Asia on the back of the conflict in Europe.1

52

The impact of the conflict is enhanced by the fact that it arises directly on the heels of the COVID-19 pandemic. Taken together, the following issues can be seen in the Asia Pacific gas markets: � Upstream project operators extricating themselves from certain Russian LNG export facilities.2 � Concern regarding the potential impact of Russia’s Decree No. 416 of 30 June regarding the assignment of the rights and obligations of Sakhalin Energy Investment Company to a newly created Russian entity.3 � Certain Asian banks and financial institutions imposing restrictions on US dollar-denominated payments being made to Russian or Russia-linked banks/companies in connection

with currency conversions made through US financial institutions to protect their reputational positions in the market.4 � Uncertainty as to whether Russia’s Decree No. 172 regarding payment for gas by importers from ‘unfriendly’ countries (to be made in roubles rather than US dollars) will, in fact, be imposed on Asian importers purchasing gas under US dollar-denominated Sales and Purchase Agreements (SPAs).5 � Spot market prices becoming a source of attractive arbitrage opportunity for sellers who, as a result of the demand spike, tendered limited available excess short-term volumes for lucrative spot trades in preference to requests from long-term customers for additional JCC/Brent price linked cargoes. � Market price spikes prompting missed cargo shipments or partial loads from sellers that are then not subsequently rescheduled. � Concern about the sanctions regime against Russia causing operators to avoid using Russian DES vessels (meaning delivery ‘ex-ship’, i.e., the seller provides the shipping), used to supply LNG cargoes to local Asian buyer markets.6 � Russia levelling sanctions against some of its own former affiliates involved in supplying and shipping gas in Asia.7 � Fire damage to the US Freeport LNG export plant, causing it to go offline for an extended period.8

While these arguably constitute the most recent events impacting the Asian gas market, they represent the sequel to a steadily evolving market landscape in Asia in the past few years, which has witnessed cultural shifts in the approach to dispute resolution, a decline in long-term LNG prices since 2012, market liberalisation, and a global pandemic impacting demand. As a consequence, there has been a crucial behavioural change among buyers in the Asian market. In order to grapple with the changing market horizon, buyers are increasingly considering what contractual tools they have at their disposal to confront these issues. An ever-increasing number of contractual negotiations has enhanced the understanding of how valuable certain contractual provisions can be, and, by consequence, has removed any hesitation in seeking to invoke them. One resulting example has been a sharp rise in the number of price review negotiations and arbitrations in the region.

In each of the major Japanese, Korean, Taiwanese, and Chinese (JKTC) markets, buyers under long-term take-or-pay contracts are now moving forward with price review negotiations and arbitrations in an effort to secure contract prices that better reflect prevailing market prices to provide some financial security moving forward in these highly changeable times. Equally, buyers have taken to their contracts to commence negotiations with sellers regarding key non-price terms, seeking amendments to volume and destination flexibility provisions to accommodate supply/demand stresses and tensions in the market.

This article briefly examines the practical impact of some of these various market events, and explores some potential contractual mitigation steps to strategically combat these issues.

53

Practical impacts

In late February 2022, the G7 developed a range of economic sanctions against Russia and Russian banks. At that time, the market considered how SWIFT sanctions could meaningfully impact the operation of certain LNG contracts, including restricting the access of Russia’s major banks to the SWIFT financial network, making it difficult for Russian companies to make and receive payments.

As a G7 member, Japan signalled its support for these sanctions and announced that it would limit the ability to carry out transactions with Russia’s central bank. That announcement prompted questions from Japanese LNG buyers – purchasing LNG from various Russian LNG projects, such as Sakhalin II – regarding the potential impact these sanctions may have on their ability to make payments for LNG cargoes under their contracts with Russian sellers. More specifically, genuine concerns emerged regarding (i) a buyer’s ability to take, but potentially not pay for LNG cargoes; and (ii) the certainty of future long-term supplies from those projects that could impact a buyer’s wider supply portfolio.

When a buyer can take LNG without the corresponding certainty as to whether its payment will be effected

As sanctions were levelled against various Russian entities, the question increasingly arose for Asian buyers as to how to comply with their take-or-pay obligations under their long-term contracts. Many buyers were ready to make payment to fulfil their contractual obligations, but, depending on the terms of their SPAs, it was not clear how their payments could be effected.

Many of the Russian-Asian LNG SPAs are denominated in US dollars. As a preliminary matter, Russia’s President Vladimir Putin announced at the end of March 2022 that Russia would continue exporting gas under previously concluded contracts, but that gas exports to ‘unfriendly’ countries would change their payment currency to Russian roubles. The Russian government had previously identified Japan as an ‘unfriendly’ country. On 31 March 2022, Russia issued Decree No. 172, which outlined a new payment procedure for gas importers from ‘unfriendly’ countries, and involved a multistep mechanism through specialised Gazprombank accounts.1 News reports immediately appeared that Gazprom had asked its European counterparties to change the mechanism by which gas was paid for under those contracts. Asian buyers, however, waited to see whether the same would happen for their US dollar-denominated contracts. Thus far, to Squire Patton Bogg’s knowledge, Gazprom has made no such demands of its Asian counterparties.

Nevertheless, once gas was taken under these US dollar-denominated Asian LNG contracts, the gas still needed to be paid for to avoid a breach event. Even where certain Russian banks were not specifically subject to sanctions by Japan, many of the US dollar-denominated cargoes were paid for via Japanese banks that undertook their currency conversions through third-party US banking partners. Certain major financial institutions began imposing restrictions on payments being made to Russian or Russia-linked banks/companies to avoid coming close to breaching restrictive measures and/or to protect their reputational position in the market. As the situation was rapidly unfolding, it was not clear whether any of the several banks in this chain of financial transactions would actually process the money transfer. Thus, depending on the language of their SPAs, many Asian buyers were in the unappealing situation

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of having a take-or-pay obligation for cargoes that they were able and willing to take, and having money with which to effect payment for these cargoes, but without knowing whether they would actually be able to effect the payment.

In such an event, could a buyer’s payment obligation be excused on grounds of force majeure? If not, was the buyer potentially in breach of the take-or-pay obligation in the contract? The rapid onset of these events prompted various players to actively consider exercising force majeure over scheduled LNG cargoes. However, questions of force majeure are rarely straightforward, and their meaning and effect will, of course, depend on the contractual language in issue and the applicable governing law of the contract. What, then, should parties to a long-term LNG or natural gas contract do in response to these financial sanctions? The answer is to carefully study the terms of the contract and consult with legal counsel regarding the precise scope of the application of restrictive measures.

In the first instance, it is important to look at the specific contractual terms and determine what a particular contract contemplates as properly constituting a force majeure event and whether it can be applied to the present payment and/or shipping sanction situation. If so, what other requirements under the contract and applicable law will need to be met to make a valid declaration? For example, a party may be required to notify the counterparty of a force majeure event within a particular timeframe, or to take specific steps to mitigate the event and its consequences. In this regard, it is important to consider what other provisions the parties included in the contract to address periods of difficulty. For example, diversion rights to unaffected terminals or other markets, downward flexibility options, and adjustments to cargo delivery schedules (e.g., moving volumes to later in the same or next contract year) are all common contractual mechanisms that a court or tribunal may expect a party to have explored before declaring force majeure. This is particularly the case where a party has a duty to mitigate under the contract and governing law.

Using flexibility rights to acquire LNG cargoes now

With regard to current and future supply security, broader commercial strategies may be required. Uncertainty regarding the reliability and availability of Russian LNG exports has become a topical discussion point in Asian markets – both in the short- and longer-term. The withdrawal of operators ExxonMobil and Shell from the Russian LNG export facilities at Sakhalin I and II prompted a wave of uncertainty concerning the future operation and reliability of those projects. More recently, this has been exacerbated by the newest Russian Decree of 30 June assigning the rights and obligations of Sakhalin Energy Investment Company to a newly created Russian entity. The sanctions regime has also created operational doubts on the usage of particular Russian DES vessels, used to supply LNG cargoes to the JKTC markets, and a consequential impact on production at affected facilities. Put simply, if production continues but ships are unable to arrive and load cargoes, the facility will hit tank-tops, and production may cease. Equally, as the sanctions may impact Russian-owned oil and condensate vessels, the production of oil and condensate might also cease, prompting associated gas production to also stop, thereby impacting LNG deliveries.

Many power utilities and gas companies in Japan and South Korea purchase LNG from these facilities. The scale of the potential issues now, and in due course, will naturally vary from

buyer to buyer. However, the extent of the disruption may be influenced by the size of annual take-or-pay volumes, the prescribed delivery mode, the availability of alternative shipping arrangements (and the associated cost), the frequency and timing of deliveries, and the volume of Russian supply in the relevant buyer’s portfolio. The applicability of these issues will undoubtedly have a material bearing on the strategic response, both commercially and contractually.

As one would expect, a good comprehension of the contract is the key foundation block for commencing dialogue between the parties on how best to address the present crisis, including a possible discussion regarding delivery mode changes, deferring volumes (if applicable), and other commercial options to help ease the impact of these problems. Does a buyer have the right under its contract to accelerate any deferred volumes? Does it have UQT rights that it can exercise? If so, what does the contract require in terms of timing for the exercise of these rights? Must a buyer exercise such rights during the development of the Annual Programme, or can it do so at a later time? If at a later time, is there a prescribed lead time for such additional nominations under the contract? Does the contractual language provide a firm right to additional volumes or only the ability to ask for them and for the counterparty to use reasonable endeavours to provide them? The bottom line for Asian market participants facing Russian supply insecurity is to utilise available contractual flexibility to acquire additional cargoes at prices below JKM, and to maximise pipeline nominations as much as possible where applicable.

However, as for seeking to secure as much supply as possible outside of long-term contract pricing, in light of the sharp

volatility of supply in the market, it may be more prudent to wait and see how the situation ultimately develops. Likewise, sellers in the midst of price review negotiations are likely to use the current volatility regarding supply as a factor to reach early resolution of price review negotiations or better commercial terms, and LNG buyers should evaluate the impact of such an approach, factoring it into their price review negotiation strategy to avoid harmful concessions early on in the negotiation window.

However, in Asia, in particular, where buyers can secure supply within the framework of long-term contract pricing, it makes economic sense to do so. Further efforts to secure supply should be used with caution when considering the specifics of a buyer’s contractual entitlements, the economics of a contract, and the leverage that sellers may bring to the negotiation table.

References 1.

‘Gas payment issues in Europe: what are the next steps?’, Global Arbitration Review, (May 2022).

2.

‘Shell intends to exit equity partnerships held with Gazprom entities’, Shell, (Feb 2022).

3.

‘Russia seizes control of Sakhalin gas project, raises stakes with West’, Reuters, (July 2022).

4.

‘Major Japan banks to halt dollar transactions with Russia’s Sberbank’, Kyodo News, (Mar 2022).

5.

OBAYASHI, Y., and YANG, H., ‘Asian gas buyers puzzle over Putin’s demand for payment in roubles’, Reuters, (Mar 2022).

6.

STAPCZYNSKI, S., ‘Shell Idles LNG Ships Owned by Russia to Avoid Sanction Risk’, Bloomberg, (Apr 2022).

7.

‘Russia allows gas flows to Gazprom Marketing & Trading for 90 days’, The Business Times, (May 2022).

8.

‘Factbox: Freeport LNG plant shutdown and main buyers at risk’, Reuters, (June 2022).

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15FACTS

LATIN AMERICA

...ON While the gas

pipeline is being built in Argentina that allows the

Haiti is one of the most densely populated countries in the world, with 1000 people occupying every square mile

development of Vaca Muerta gas on a large scale, LNG will continue to be imported

Argentina has advanced in the purchase of pipes in order to complete the first phase of construction of natural gas infrastructure

Bolivia’s idle capacity in its pipelines could easily be used in two or three years to move gas from Argentina to Brazil, and also move gas to northern Chile

Argentina is one of the largest producers of wine.

El Salvador is known as the Land of Volcanoes due to its frequent earthquakes and volcanic activity

Cuba has won the most

Sloths are a national symbol of Costa Rica GELA predicts that small LNG will continue to be deployed throughout the Caribbean islands and in all Central American countries from large FSRU terminals that are already installed

Easter Island, located 3600 km west of Chile, is known for its

Olympic medals out of any

Brazil has won the FIFA

Latin American country,

World Cup five times

with 241 medals as of 2022

Peru is home to one of the New Seven Wonders of the World, Machu Picchu

On 2 April 2022, El Salvador became one of the LNG importing countries in the

stone statues that are scattered

region with the purchase and arrival of its

around the island

inaugural cargo at Shell’s Bilbao Knutsen

LNG in Colombia will increase in the coming years, since gas discoveries are not being fulfilled and shale is still a big problem

56

August 2022

If infrastructure is built as planned with the Transport.ar system that will start this year, the demand for LNG in Chile, Argentina, and Brazil will decrease

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