LNG Industry November 2022

November 2022

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ISSN 1747-1826

CONTENTS 03 Comment 05 LNG news 10 The return of the long-term

NOVEMBER 2022

33 Advanced asset condition monitoring and analytics

Michael Hastings and Jonathan Fox, B&K Vibro, detail how a typical condition monitoring and diagnostic solution can be enhanced using a data historian in the LNG industry.

LNG SPA

Rob Butler, Baker Botts, UK, looks at the data behind LNG contracting activity over the last five years in order to establish whether there has been a resurgence in long-term LNG contracts, and considers what is driving change in LNG contracting behaviour during this period.

37 Multi-purpose pumps for performance

Stefano Calandri, Vanzetti Engineering, Italy, studies the response to the technological evolution of engines with a view to greater efficiency and intensified deployment of LNG structures.

40 Enhancing pump performance

Enver Karakas PhD and Robert Mollath, Elliott Group, USA, describe how to enhance cavitation performance in cryogenic centrifugal pumps, using a case study as an example.

46 Small scale but mighty

Karthik Sathyamoorthy, President, AG&P LNG Terminals & Logistics, analyses how small scale LNG technologies and transportation models are shaping the future of natural gas, whilst providing emerging countries with an uninterrupted supply of clean energy.

49 Coatings that don't cost the earth 17 Learning the ropes for

10

mooring safety and sustainability Veronika Aspelund, Wilhelmsen Ships Service, Norway, considers how investing in better and higher-durability ropes promotes safety in vessel mooring operations, as well as lowering environmental impact and reducing the cost of replacement.

21 Bring in the energy

Kjell Ove Ulstein and Per Helge Madsen, Wärtsilä Gas Solutions Norway AS, examine the development of water glycol heated regasification systems for use on FSRUs and offshore jetties.

25 Tanks Q&A

LNG Industry asked several companies to discuss some issues regarding LNG tanks.

30 Designing tailored solutions for the LNG supply chain

Sunil Biswas and André Jäger, ION Commodities, explore how technology can integrate and streamline the LNG market.

CBP006075 LNG Industry is audited by the Audit Bureau of Circulations (ABC).

An audit certificate is available on request from our sales department.

Tony Collins, EonCoat, USA, explains how the shift towards sustainability has seen an increase in support for LNG storage assets protected by non-toxic coatings.

51 Strong storage solutions

Edo Vonk, VSL International, highlights the basic guidelines for inspection and maintenance of pre-stressed concrete tanks for LNG and LPG storage, emphasising the differences between the various systems.

54 Designed to perform and protect

Romuald Machac, Hutchinson, South Korea, outlines high-performance solutions for the LNG industry in terms of insulation, protection, and barriers.

ON THIS MONTH’S COVER Atlantic Gulf & Pacific (AG&P) is building a global network for clean energy, country by country. AG&P develops and runs LNG and gas logistics and distribution solutions, providing the infrastructure to access natural gas safely and easily in new and growing markets worldwide. The company acts as an owner and service provider, covering the development, financing, engineering, procurement, project management, and construction for onshore and offshore gas infrastructure, linking suppliers to downstream customers.

Copyright © Palladian Publications Ltd 2022. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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JESSICA CASEY DEPUTY EDITOR

COMMENT T

here was a lot to celebrate during the Summer of 2022 here in the UK: England’s lionesses won the Women’s Euros, the Queen marked 70 years on the throne, and the 2022 Commonwealth Games took place in Birmingham where, collectively, the UK accumulated a total of 273 medals.1 With less cause for celebration, the Summer of 2022 also saw a number of climate disasters. The UK experienced two heatwaves, with temperatures hitting a record-high of 40.3˚C, and there was also extreme heat in India and Pakistan earlier this year. In August, severe flooding in Pakistan (following eight weeks of non-stop rain), resulted in over 1000 deaths and millions losing their homes.

Bangladesh was also subject to flooding – in June, the worst floods for 100 years hit north-east Bangladesh and parts of India, killing over 100 people and stranding more than 9.5 million people across both countries.2 Ahead of COP27, the climate crisis is at the forefront of everyone’s mind, and this is no different for the LNG industry. With the topic of sustainability and concern over emissions ever present, positive actions are being taken in the fight against climate change, and multiple different approaches are being utilised in the hope of reaching this goal.

For example, as part of the company’s continued commitment to increase climate transparency and data-driven actions that address methane emissions, Cheniere has joined UNEP’s Oil and Gas Methane Partnership 2.0, the United Nations Environment Programme’s flagship oil and gas methane emissions reporting and mitigation initiative.3 Meanwhile, ABS has awarded approval in principle to Daewoo Shipbuilding & Marine Engineering Co. Ltd for its hybrid power system to aid large LNG carriers. The system’s configuration includes a battery energy storage and generator within an existing power source that will allow the carriers to access hybrid power when needed most.

Managing Editor

James Little james.little@palladianpublications.com

Senior Editor

Another approach that appears to be picking up speed is the development of bio-LNG, which is derived from renewable sources (such as biogas). This makes it 100% sustainable, and it also has the potential to provide both economic and environmental benefits. For instance, supplementing bio-LNG to existing LNG value chains could significantly reduce carbon dioxide emissions.

We have seen a number of news stories emerging on this topic: Wärtsilä has recently been chosen to supply a bio-LNG plant in Latvia, with the plant expected to become fully operational by the end of 2023, and will also supply a biogas upgrading and liquefaction solution for a new biogas plant in Sweden.

In addition, Titan is to build the world’s largest biomethane liquefaction plant in the Port of Amsterdam, the Netherlands, to enable supply to ships and trucks. The first liquefied biomethane production is expected in 2025.

Across the globe, CycleØ and HAM Group are to build the first bio-LNG plant in Chile, with a capacity to process between 7500 – 16 500 m3/d of biogas. You can find more on all these stories in the news section, starting on p.5.

It is clear sustainability remains a key topic, and the November issue of LNG Industry also includes articles that touch on the importance of improving this across the different sectors of the LNG industry. Starting on p.17, Wilhelmsen’s article considers how higher-durability ropes can lower environmental impact while EonCoat explores how non-toxic coatings for storage assets can aid with the push for sustainability (starting on p.49).

References 1.

‘Medal Standings’, Birmingham 2022 Commonwealth Games, www.birmingham2022.com/medals

2.

‘You’re not imagining it – there really were a lot of climate disasters this summer’, Greenpeace, (2022), www.greenpeace.org.uk/news/climate-disasters-summer-2022/

3.

‘Cheniere Joins UNEP’s Oil and Gas Methane Partnership 2.0’, Business Wire, (2022), www.businesswire.com/news/ home/20221017006027/en

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LNGNEWS the Netherlands

Titan to build the world’s largest biomethane liquefaction plant

T

itan, an independent supplier of low and zero-carbon fuels, has announced its liquefied biomethane (LBM) production project for 200 000 tpy of LBM. Titan will build and operate the LBM plant at its strategic location in the Port of Amsterdam, the Netherlands, allowing supply to ships and trucks. Important milestones for the project include two recent contract signings: with biogas producer, BioValue, for the exclusive off-take of all on-site produced biogas, and with Linde Engineering, who will perform the basic engineering based on Linde’s proprietary liquefaction technology.

BioValue, one of the largest biogas suppliers in the Netherlands, will supply a significant part of the biogas required for the total LBM production. For this, BioValue will construct a new biogas plant adjacent to the LBM plant. The remaining biogas will be sourced from other production installations throughout Europe that are connected to the existing gas grid. This hybrid sourcing setup enables the scale required for impactful decarbonisation of the marine industry.

The bulk of the LBM volumes produced by the plant will be supplied to the LBM-powered vessels of Titan’s launching customer.

For the remaining volumes, truck refuelling stations and industrial customers are also within scope. The LBM will substitute fossil fuels, avoiding approximately 1 million tpy of carbon dioxide equivalent emissions. The plant will be located adjacent to Titan’s berth in the Port of Amsterdam, from whom the land will be leased. The first LBM production is expected in 2025.

The project will only source biogas from sustainable feedstocks that are compliant with the latest EU Renewable Energy Directive, and are International Sustainability and Carbon Certification certified.

Chile

CycleØ and HAM Group to build first bio-LNG plant in Chile

C

ycleØ and HAM Group have been awarded the contract for the construction and operation of the first bio-LNG plant in Chile, with the works being carried out through HAM Chile and FNX Liquid Natural Gas. The plant will be located in the Ñuble region, with a capacity to process between 7500 – 16 500 m3/d of biogas. In the heavy transport industry, this represents reducing more than 19 000 tpy of carbon dioxide, 96% of fine particle emissions, and 85% of nitrogen oxide and sulfur emissions, compared to other fuels.

This bio-LNG plant will be possible due to Lipigas’ commitment for an efficient and 100% renewable energy solution. The biogas comes from an anaerobic co-digestion plant for waste from a MaxAgro pig farm, where HAM Chile Spa will build and manage the processing facilities. It will also have upgrading equipment developed by FNX Liquid Natural Gas, which will purify the biogas (containing 50 – 60% methane,) increasing its quality and obtaining a methane purity of over 99%.

Grupo HAM and CycleØ believe that bio-LNG must play a prominent role in the energy transition, reducing greenhouse gas emissions, thanks to its negative carbon footprint. This project reinforces the companies’ commitment to biogas, which has led the companies to develop several projects related to bio-LNG and bio-CNG, such as those in Girona, Spain, where they have opened the first 100% vehicular biomethane plant in the country, and in Faenza, Italy, where they are going to put into service one of the largest European bio-LNG plants.

Latvia

Wärtsilä to provide biogas upgrading and liquefaction in a single turnkey solution

T

he technology group, Wärtsilä, will supply a bio-LNG plant in Tervete, Latvia. The order was placed by AS Agrofirma Tervete, who will utilise the plant to upgrade, polish, and liquefy biogas from agricultural waste into bio-LNG. The order was included in Wärtsilä’s order intake in September 2022.

Wärtsilä will provide its Puregas CA50LBG for removal of carbon dioxide (CO2) and hydrogen sulfide, followed by an MR10 (mixed refrigerant) technology for the liquefaction stage.

The installation is designed for production of 10 tpd bio-LNG.

The delivery also covers the supply of spare parts and service agreement.

Wärtsilä’s Puregas CA50 LBG process recovers more than 99.9% of the biomethane present in raw biogas by separating CO2 from the biogas through chemical absorption. Furthermore, Wärtsilä’s mixed refrigerant technology is extremely reliable and offers the lowest operating costs for liquefying biogas.

The plant is expected to become fully operational by the end of 2023.

November 2022

5

LNGNEWS South Korea

ABS awards AiP to DSME for more sustainable operations

A

BS has awarded approval in principle (AiP) to Daewoo Shipbuilding & Marine Engineering Co. Ltd (DSME) for its hybrid power system to aid large LNG carriers, a configuration previously limited to smaller vessels in the maritime marketplace.

The hybrid power system configuration includes a battery energy storage system and Saft generator within an existing power source that will allow the LNG carriers to access hybrid power when needed most, such as spinning reserve or peak shaving.

With DSME’s test facility for ship research and development, the hybrid system, already in use in the industry to support smaller vessels, such as ferries, was successfully applied to large LNG vessels. With the AiP from ABS, it is now possible to reduce dependence on the generator engine and improve fuel efficiency by including a solution that can improve the performance of the DSME shaft generator. The approval process included review of the ship's internal arrangement, function, risk analysis, and operation scenarios reflecting actual electrical loads.

Germany

Gasunie takes new step in development of LNG terminal in Germany

G

erman LNG, a subsidiary of Gasunie, has taken a new step in the development of the LNG terminal in Hamburg, Germany.

CS Gas North S.A. will build the terminal. As initial customers, contracts have been signed with ConocoPhillips, INEOS, and RWE Supply & Trading. In addition, the licensing proceduce has now started.

The terminal is expected to be operational in 2026 and will have a throughput capacity of at least 8 billion m3/y of natural gas, with a possible expansion to at least 10 billion m3/y. Gasunie will operate the terminal after completion of construction work.

The construction of this LNG terminal will help reduce dependence on gas from Russia. In addition to this terminal, Gasunie has built a new floating LNG terminal in Eemshaven, the Netherlands, and optimised the existing capacity of the Gate terminal on the Maasvlakte in Rotterdam, the Netherlands, allowing more LNG to be realised.

6

November 2022

Global

Cheniere joins UNEP's Oil and Gas Methane Partnership 2.0

C

heniere Energy, Inc. has joined the Oil and Gas Methane Partnership (OGMP) 2.0, the UN Environment Programme's (UNEP) flagship oil and gas methane emissions reporting and mitigation initiative.

OGMP 2.0 is a comprehensive, measurement-based reporting framework intended to improve the accuracy and transparency of methane emissions reporting in the oil and gas sector.

Cheniere joins OGMP 2.0 as part of its continued commitment to increased climate transparency and data-driven actions that address methane emissions.

Joining OGMP 2.0 is consistent with and enhanced by Cheniere’s climate strategy initiatives, including the company’s collaborative programmes to quantify, monitor, report, and verify (QMRV) greenhouse gas (GHG) emissions across the supply chain with natural gas suppliers, midstream companies, shipping companies, and academic institutions. Cheniere has initiated the QMRV programme to begin measuring GHG emissions at its Sabine Pass and Corpus Christi liquefaction terminals, as well as natural gas transmission facilities, consistent with the OGMP 2.0 reporting framework.

Cheniere also announced it has begun issuing cargo emissions tags to its customers, which estimate GHG emissions associated with each cargo produced by Cheniere, underpinned by the company’s peer-reviewed GHG life cycle analysis.

THE LNG ROUNDUP XX Shell selected as partner in the North Field South LNG project XX Eni provides additional deliveries of LNG to Panigaglia terminal XX QatarEnergy Trading to offtake and market 70% of LNG produced by Golden Pass Follow us on LinkedIn to read more about the articles

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LNGNEWS Qatar

USA

Sempra Infrastructure announces final EPC contract with Bechtel for Port Arthur LNG

S

empra Infrastructure, a subsidiary of Sempra, has announced that Port Arthur LNG and Bechtel Energy have amended and restated the fixed-price EPC contract for the proposed Phase 1 liquefaction project under development in Jefferson County, Texas, the US. The amended contract includes an updated price of approximately US$10.5 billion.

Under the EPC contract, Bechtel will perform the detailed EPC, commissioning, start-up, performance testing, and operator training activities for Phase 1 of the project.

The Port Arthur LNG Phase 1 project is permitted and is expected to include two natural gas liquefaction trains and LNG storage tanks, and associated facilities capable of producing up to approximately 13.5 million tpy of LNG under optimal conditions. A similarly sized Phase 2 project is also competitively positioned and under active marketing and development.

Earlier this year, Sempra Infrastructure announced the substantial completion of marketing for Phase 1 of the proposed Port Arthur LNG Project with the signing of a series of non-binding agreements with the Polish Oil & Gas Company, RWE Supply & Trading, INEOS Energy Trading Ltd, and ConocoPhillips.

Development of Phase 1 and Phase 2 of the Port Arthur LNG project is contingent upon completing the required commercial agreements, securing all necessary permits, obtaining financing, and reaching an affirmative final investment decision.

WinGD's technology to power QatarEnergy newbuilds

W

inGD’s latest generation of X72DF-2.1 engines will power 25 vessels as part of the QatarEnergy’s North Field East project, the biggest LNG carrier newbuilding project in history. The 50 dual-fuel engines, which feature the new on-engine intelligent control by exhaust recycling (iCER), were selected by multiple shipyards and shipowners, highlighting strong confidence in WinGD’s proven and reliable low-pressure dual-fuel engines.

The new on-engine configuration of WinGD’s iCER was released in May 2022 and has been met with swift uptake, providing improved fuel efficiency in both gas and diesel modes and a 50% reduction in methane slip compared to the first-generation X-DF. One order as part of the Qatar NFE programme is for two 174 000 billion m3 LNG carriers to be built for TMS Cardiff Gas at Daewoo Shipbuilding & Marine Engineering (DSME). The two vessels will be the first ships built by DSME to feature on-engine iCER. The advantages of X-DF low-pressure dual-fuel engines include low CAPEX, low maintenance costs, and ultra-low air pollution, reaching IMO Tier III NOX limits without aftertreatment. Since its debut in 2015, the entire X-DF fleet has grown to more than 350 engines in operation, lending the deep in-service experience to the technology advancements available today.

QatarEnergy has secured approximately 60% of the global LNG shipbuilding capacity through 2027 to cater for its growing LNG carrier fleet requirements, which could reach more than 100 new vessels. A wide range of ship owners have tendered to build gas carriers that will be operated under long-term charters to QatarEnergy. The vessels will be delivered between 2023 and 2027.

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November 2022

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10

Rob Butler, Baker Botts, UK, looks at the data behind LNG contracting activity over the last five years in order to establish whether there has been a resurgence in long-term LNG contracts, and considers what is driving change in LNG contracting behaviour during this period.

I

n early March 2021, the Marketing Director of a state-owned LNG buyer declared that “the era of the long-term contract is over.” Whilst hindsight is a wonderful thing, it is clear that the world has changed significantly since that statement was made. Many reports and commentators are now declaring the ‘return’ of long-term LNG contracts.

LNG contracting trends

Data from Poten & Partners LNG Contract Intelligence Service shows that 2021 saw a steep rise in both the number of long-term1 LNG sale and purchase agreements (LNG SPAs) that were entered into and the total LNG volumes contracted for under such LNG SPAs (Figure 1).

This trend has continued in 2022, with the total number

of long-term LNG SPAs signed in 2022 at the time of writing already exceeding the total number of long-term LNG SPAs signed in the whole of 2021.

Whilst this shows that there was an increase in the number and volume of long-term LNG sales contracted for in 2021 and 2022, this could have simply been due to an increase in LNG contracting activity during those years. It therefore needs to be determined whether this represented an increase to the share of long-term LNG sales of the global LNG market.

Data from the annual reports published by the International Group of LNG Importers (GIIGNL) shows that the long-term LNG SPAs2 signed in 2021 represented 64% of the total volume of LNG sales contracted for in 2021.

This was an increase from the 47% share that long-term

11

LNG SPAs had in 2020, but was still nowhere near the 93% share that long-term LNG SPAs had in 2019 (Figure 2). The GIIGNL data only goes up to 2021, however, so does not show whether this trend has continued through 2022.

Looking specifically at 2022, the data from Poten & Partners LNG Contract Intelligence Service shows

that the number of mid-term3 LNG SPAs signed in 2022 dropped off significantly from prior years (Figure 3). As of 11 September 2022, only three mid-term LNG SPAs had been signed in 2022, as compared to 20 mid-term LNG SPAs in 2021 and 12 mid-term LNG SPAs in 2020. This therefore represents a significant move away from mid-term LNG sales towards long-term LNG sales.

The data therefore supports the claim that there has been a resurgence in long-term LNG contracting, but what is driving this change?

COVID-19

Figure 1. Long-term LNG sale and purchase agreements signed.

Figure 2. Contracts signed by duration.

Figure 3. Mid-term LNG sale and purchase agreements signed.

12

November 2022

In order to look at why long-term LNG sales increased in 2021 and 2022, it is first necessary to look at the situation prior to this increase.

Even before the onset of the COVID-19 pandemic, during 2019 and early 2020 the LNG industry was experiencing a period of over-supply and historically low prices. The COVID-19 pandemic greatly accelerated these issues. In 1H20, with governments across the world imposing lockdowns on the public and on businesses, global demand for natural gas dropped by an estimated 4% y/y;4 this was the largest fall on record. This demand destruction resulted in a significant decrease in LNG production, as buyers scrambled to cancel or reschedule cargo deliveries, and global LNG exports fell by 17% between January – June 2020.4 The resulting over-supply in the LNG market led to huge drops in LNG and natural gas spot prices, with spot prices hitting record lows in April and May 2020. The Japan Korea Marker (JKM), the LNG benchmark price assessment for spot physical cargoes delivered ex-ship into Japan and South Korea, dropped to a record low of US$1.80/million Btu on 28 April 2020. This was down from US$5.26/million Btu at the start of 2020. Spot natural gas sales at the Dutch Title Transfer Facility (TTF) fell to a record low US$1.13/million Btu on 28 May 2020, down from over US$5.00 at the beginning of 2020.

Lockdowns resulted in delays to LNG projects already under construction, with project developers forced to reduce the number of workers on site to the bare minimum. In addition, even once workers could return to site, the knock-on effects of delays throughout the global supply chain further pushed back the expected start-up dates for new LNG export projects.

COVID-19 also delayed the taking of a final investment decision (FID) on a number of proposed LNG export projects. In 2019, six LNG export projects took FID on nearly 71 million tpy of additional LNG production capacity – a record year for the approval of new LNG export projects. A similar number of FIDs was predicted for 2020 but, due to the effects of the pandemic, Sempra’s Energía Costa Azul

project in Mexico was the only LNG export project to take FID in 2020.

The drop in LNG contracting activity in 2020, and the pushing back of FID on all of these delayed projects, has contributed to the increase that has been seen in long-term LNG contracting activity in 2021 and 2022.

Despite not having taken FID, project sponsors had invested heavily on these projects and, for many of these projects, it was a question of ‘when’ not ‘if’ they would proceed to FID once market conditions improved.

Buyer opposition to long-term contracts

Due to historically low spot LNG prices in 2019 and 2020, and the resulting price differentials against traditional long-term LNG SPA contract price formulas, many LNG buyers had begun to rely heavily on spot LNG purchases for an increasing share of their LNG demand.

Whilst some LNG buyers saw an opportunity to lock-in low-cost LNG supplies during this period, many LNG buyers were reluctant to commit to long-term LNG SPAs, which they viewed as inflexible and expensive (as against then-current spot LNG prices). This can be seen in the decline in the number of long-term LNG SPAs signed in 2019 and 2020 (Figure 1), and in the increase in spot

cargo sales as a share of the global LNG market over the same period (Figure 4). The statement quoted in the opening paragraph of this article was made against this backdrop of historically low prices and relative over-supply.

Even amongst the long-term LNG SPAs signed in 2019 and 2020, it can be seen that there was a growing tendency towards shorter contract terms. Data from GIIGNL shows that the weighted average duration of the LNG SPAs signed in 2019 and 2020 was far shorter than those signed in 2018 (Figure 5).

Historically, long-term LNG SPAs had tended to be for terms of at least 20 years, as stable long-term revenues were required to support the high capital costs involved in developing LNG liquefaction projects. In addition, project lenders would typically require that the term of each LNG SPA covered the full tenor of the project loans plus a ‘tail’ of 10 – 50% of the term. This tendency for shorter duration LNG SPAs can be demonstrated by the Mozambique LNG project, which managed to secure approximately US$15 billion in project financing in July 2020, backed by LNG SPAs for 75% of its total production with terms of just 13 – 15 years.

Figure 4. Share of spot and short-term vs total LNG trade.

Figure 5. Volume weighted average duraton of long and medium-term contracts in years.

14

November 2022

Price recovery and volatility

Following the record-low LNG and natural gas spot prices in April and May 2020, prices gradually recovered. Cancellations of cargoes from US liquefaction projects initially helped to balance the market and, as the world slowly emerged from lockdown, energy demand slowly recovered and US LNG cargo cancellations had all but disappeared by the end of 2020.

This price recovery was further driven by a number of production issues at LNG export projects around the world in 2H20. This included shut-ins at US LNG export projects between August and October 2020 due to hurricane activity; the long-term shutdown of Norway’s Hammerfest project in September 2020 following a fire; and production issues in Qatar, Malaysia, and Nigeria in November 2020. Adding to the supply constraints, extreme cold weather in North-East Asia in December 2020 and January 2021 led to increased gas consumption, and JKM hit a new record level of US$32.5/million Btu on 13 January 2021.

Whilst LNG spot prices quickly fell off after this record high, spot prices gradually rose during 2021, and JKM hit a new record high of US$56.32/million Btu on 6 October 2021. This was driven on the supply side by unplanned shutdowns at LNG export facilities, including the continued shutdown of Hammerfest LNG in Norway. This was also driven on the demand side by droughts in hydro-rich countries, such as Brazil, increased demand in the Asia-Pacific region, and competing demand in Europe due to reductions in Russian pipeline deliveries.

By the end of 2021, spot LNG prices were at historically high levels and were in excess of Brent or Henry Hub-based long-term

contract formulas. This pricing differential, as well as the volatility of an 18-month period that had seen both record highs and record lows in LNG spot prices, provided a strong incentive for buyers to look to lock-in long-term LNG supplies.

Russia accounted for 7.9% of global LNG supply in 2021, so this move away from Russian LNG by many buyers has further added to the tightening of the global LNG market and has led to many buyers looking for new long-term LNG supplies from alternative sources.

Russian invasion of Ukraine

Energy security

Even prior to the Russian invasion of Ukraine on 24 February 2022, the LNG market was expected to remain tight throughout 2022. Spot LNG and natural gas prices were also at historically high levels, with both JKM and TTF well in excess of US$20/million Btu immediately before the invasion. The Russian invasion exacerbated these issues, and has resulted in LNG and natural gas spot prices remaining both high and volatile throughout 2022. JKM and TTF hit record highs in March 2022, with JKM peaking at US$84.76/million Btu on 7 March 2022.

The Russian invasion resulted in an immediate response from the UK, the US, and the EU, with the imposition of a wide range of sanctions targeting Vladimir Putin and his allies. On 8 March 2022, the EU also announced its ‘REPowerEU strategy’, which aims to reduce the EU’s demand for Russian gas by two-thirds by the end of 2022 and to make Europe independent from Russian fossil fuels by 2030. Given that the EU received roughly 40% of its natural gas from Russian pipelines in 2021, this is an ambitious goal.

2022 has therefore seen countries across Europe, in particular Germany and the Netherlands, accelerating plans for new LNG import capacity. A number of these are utilising pre-built FSRUs, which allow for extremely quick start-up of operations. Two FSRUs commenced operations in September 2022 at Eemshaven in the Netherlands. Two further FSRUs are expected to commence operations in Germany, and one FSRU is expected to commence operations in Finland/Estonia, before the end of 2022.

In connection with this ramping up of LNG import capacity, 2022 has seen European energy companies and utilities seeking long-term LNG supplies in order to replace Russian gas volumes. Whilst the long-term LNG SPAs signed in 2019 and 2020 were for the most part entered into by Asian buyers, the long-term LNG SPAs signed since February 2022 include a number of European buyers. In September 2022, Uniper entered into a 16 year LNG SPA with Woodside, and, in June 2022, EnBW entered into two 20 year LNG SPAs with Venture Global for supply from its Plaquemines and CP2 LNG export projects. Most noteworthy is the entry by ENGIE in May 2022 into a 15 year LNG SPA from NextDecade’s Rio Grande LNG export project. This deal had reportedly been cancelled back in October 2020, as US LNG was viewed as “not aligned with France’s environmental project and environmental vision”.5 The fact that this deal was subsequently entered into following the Russian invasion of Ukraine means that either the environmental concerns of the French government had been addressed, or those priorities had shifted (or perhaps a bit of both). Either way, LNG supply to France became relevant once more.

Whilst the sanctions imposed by the UK, the US, and the EU do not currently prevent the purchase of Russian LNG or natural gas, many countries and buyers outside of the EU are no longer willing to purchase LNG from Russia.

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Recent events have led to energy security, and in particular security of gas supply, becoming much more of a concern for governments, gas suppliers, and gas buyers alike. A long-term LNG SPA provides the certainty of stable supplies of LNG at an agreed contract price formula. Prices under long-term LNG SPAs will still vary in accordance with changes to global oil and gas reference prices (depending upon the applicable pricing basis), but they protect buyers from the extreme volatility that has been seen in the LNG spot market over the last few years.

However, energy security is not simply a concern about the ability to obtain affordable supplies of LNG/gas, but often more critically about the ability to actually procure sufficient supplies of LNG/gas to satisfy demand. During 2022, both Pakistan and Bangladesh repeatedly failed to procure any offers in respect of their LNG tenders. Both countries had to subsequently introduce gas rationing in order to address the resulting shortfall in supply. When markets are tight, LNG supplies will go to the highest (and most creditworthy) bidders. For many countries, long-term LNG SPAs may therefore be the only means of guaranteeing stable supplies during periods of volatility.

Cyclical nature of LNG market

Whilst all of the matters discussed above have contributed to the increase in long-term LNG sales entered into over the last two years, such a ‘return’ to long-term LNG sales was inevitable to some extent due to the often cyclical nature of LNG markets. 2019 and 2020 represented a period of over-supply and low prices in the LNG market, and the market was bound to tighten eventually.

The events discussed above, in particular the Russian invasion of Ukraine, have clearly led to a significant increase in LNG prices, but such an increase was likely in any event given the inevitable tightening of supply after a sustained period of under-investment in LNG export facilities. These events can therefore be seen as the catalyst, rather than the cause, of this increase in long-term LNG contracts.

References 1.

Except as provided in Footnote 2, for the purposes of this article, ‘long-term’ is defined as contracts having a supply period of 10 years or more.

2.

Please note that, solely for the purposes of this GIIGNL data, ‘long-term’ was defined as contracts having a supply period of 11 years or more.

3.

For the purposes of this article, ’mid-term’ is defined as contracts having a supply period of four years or more but less than 10 years.

4.

‘Global Gas Security Review 2020’, International Energy Agency, (12 October 2020).

5.

WHITE, S., and DISAVINO, S., ‘France halts Engie’s U.S. LNG deal amid trade, environment disputes’, Reuters, (2020), www.reuters.com/article/engie-lng-franceunitedstates-idUSKBN27808

Veronika Aspelund, Wilhelmsen Ships Service, Norway, considers how investing in better and higher-durability ropes promotes safety in vessel mooring operations, as well as lowering environmental impact and reducing the cost of replacement.

S

afety is many companies’ top priority, and Wilhelmsen believes that a more holistic regulatory approach to mooring equipment and practice would help reduce risk to both crews and assets. It will also help buyers better understand which ropes they can and should use. Holistic guidelines should guide their choices not only for optimal operations, but also to promote sustainability as far as possible.

Setting the standard

Up to the present, the Oil Companies International Marine Forum (OCIMF) Mooring Equipment Guidelines 4th edition (MEG4) has come to be regarded as the industry ‘gold standard’ for vessel mooring equipment and operations. Although aimed primarily at tankers and

LNG carriers, they are applicable to most other ship types. Multiple other guidelines offered by diverse stakeholders, including terminals, also look to MEG4. From 1 January 2024, the International Maritime Organization’s (IMO) revised SOLAS regulation II-1/3-8 and associated guidelines (MSC.1/Circ.1175) and development of new guidelines (MSC.1/Circ.1619 and MSC.1/Circ.1620) to prevent unsafe work situations during mooring operations come into force both for new buildings and existing vessels. These cover the design, inspection, and maintenance of mooring equipment, including lines and tails.

Rightship also urges vessel operators to implement MEG4 recommendations across their fleets under its RISQ 2.0 Section 10 Mooring Operations.

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Bulk carriers, for example, will have to comply with Rightship requirements from 1 October 2022.

Terminals getting increasingly strict On the terminals side, Wilhelmsen is in contact with leading terminal operators worldwide that are looking to adjust their guidelines based on MEG4.

Terminals are primarily concerned with ensuring the safety of port workers and preventing expensive accidents, such as a vessel drifting following a line breakage and blocking an approach channel. In their notices to ships’ masters, terminals typically insist that mooring ropes are in good condition. They focus mainly on inspections on board or request photos of ropes. Ships with ropes in poor condition, or ropes that do not comply with the terminal requirements, run the risk of being refused.

Most bulk terminals now specify that ropes should be used for five years only, to reduce the risk of breakage.

However, Wilhelmsen is of the opinion that if a vessel selects high-end rope products designed for 8 – 10 years of use, it is a waste of money to replace them after only five years.

Thorough understanding of individual products and optimal line management can avoid penalising good performers.

Durability and usability

With regard to LNG carriers, investing in more durable ropes with better usability is key for mitigating risk in mooring operations. Rope longevity is also an important factor in reducing waste and materials usage in rope production, while reducing overall cost of ownership.

High-performance mooring ropes made from high modulus polyethylene (HMPE) offer the best strength-to-weight ratio in the market. At equivalent strength, an HMPE rope is seven times lighter than steel wire and three times lighter than a polyester rope. This increases its usability while reducing the total time spent by crew members on mooring operations and fuel consumption.

HMPE ropes are more expensive than most other fibre ropes, although prices can vary significantly between manufacturers. However, when evaluating what investment to make, operators should consider not only differences in price but also in performance and expected lifetime, which has a lot to say in terms of the global ecological impact of rope production and total cost of ownership.

Rope performance and sustainability indicators When it comes to selecting a HMPE mooring rope, vessel operators should consider the following factors: abrasion resistance, linear density and diameter, and strength-to-weight ratio.

Rope abrasion Rope abrasion is one of the most common issues that affects rope longevity. Abrasion can be identified by the visible fraying on the rope, which will ultimately lead to breakage if the process continues. The ability of a rope to resist abrasive damage from rubbing against mooring equipment is critical to prolonging its usability. Abrasion also leads to the release of particles into the ocean, which is harmful to marine life.

A rope with better abrasion resistance will release less material over time, reducing its environmental impact.

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In addition, quality ropes with high abrasion resistance will not need to be replaced as often. This allows operators to avoid complex recycling and disposal processes while reducing waste and damage to the environment.

Linear density Linear density is the measure of the weight of the rope per unit of length (g/m). Ropes with a lower linear density are much easier for crew members to handle on deck and require less material to manufacture, reducing their overall resource footprint.

While some variation from the nominal diameter is to be expected, vessel operators should note that a large variation from the nominal diameter is likely indicative of a higher amount of material used to achieve the desired rope strength.

This results in a larger diameter, and consequently a higher linear density and higher product footprint.

Strength-to-weight ratio In regards to strength-to-weight ratio, the breaking load of a rope is the maximum force under tension the rope can withstand until it breaks. The higher the breaking load, the greater the force the rope can withstand. At equivalent strength, ropes with a lower linear density require less materials to produce, which means less materials going to waste. Again, it is also lighter in weight and easier for the crew to handle.

Practical implications

Abrasion resistance and the amount of material used in the manufacturing of each rope affect long-term costs and environmental impact. It is thus important for shipowners to consider the performance of ropes very carefully before making a purchase decision.

There is a large variation in unit cost of the ropes. The company’s own analysis shows that the most expensive rope is twice as expensive than the cheapest alternative, but larger variations are possible. However, in order to evaluate the total cost of ownership of the ropes, it is more relevant to look at the total cost of ropes over a longer period of time. Ropes with a longer lifespan usually offer the lowest cost of ownership.

Importance of rope maintenance

Constant wear and tear impacts the life of all types of ropes.

A rope is chosen from strength when new, and the effect of use on that rope is often not taken into consideration. Taking proper care of long-lasting, high-performance ropes serves to enhance their longevity.

Equipment on new ships should also be designed to help ropes last longer. There are some unfortunate examples of designers and builders trying to save money by cutting corners, resulting in equipment that can weaken ropes more quickly. To this end, Wilhelmsen collaborates not only with customers but also ports and terminals, unions, and class on rope design.

Long-term mooring partner

Wilhelmsen does not stop at delivering high-quality ropes, however. The company offers a total solution including service, inspection, and testing, as well as its dedicated Line Management Plan (LMP) software. The LMP

Making clean energy network a reality.

logs everything a vessel operator needs to show terminal inspectors in one place, including inspection data, certification, documentation, and mooring hours. Users can also add data on ropes produced by any manufacturer in addition to Wilhelmsen. Regular inspection and testing, in combination with info from the LMP, provides optimal oversight and a foundation for better decision making. Even though it is impossible to know the full load history of the rope in detail, good decisions are based on all the information available.

It is also important to bear in mind that rope management is unique to each individual vessel, considering the different forces acting on lines in different situations, such as being moored at a terminal in bad weather. And even if operators/terminals invest in sensor technologies that sound an alarm when there is high tension on a line, they can still snap on low loads with no alarm sounding due to previous overload. In those cases, there is no forewarning of an accident, which makes proper management essential.

In the LNG context, requiring the highest standards of compliance and safety documentation, it is even more important that mooring lines be tested regularly and hold MEG4-compliant certification. Wilhelmsen has 40 service engineers in ports around the world to carry out inspections.

One particular challenge for LNG carriers is elongation of lines on exposed moorings. Ropes or parts of ropes can be sent to the company’s test laboratory for further destruction testing to test the residual strength of those ropes. As recommended by MEG4, the company advises ropes should be replaced if they are found to be below 75% of their original strength.

Investing in new technology

Wilhelmsen can also step in to address key challenges on ropes and mooring operations generally such as when operators are using a certain terminal for the first time and require back-up expertise on regulations and products. Its conclusions are underpinned by a strong R&D heritage and it is also involved in creating ISO standards, Cordage Institute (CI) standards, and work on technical and sustainability issues as a member of Eurocord and the CI. Wilhelmsen is also investing in a new technology project leveraging artificial intelligence and machine learning to

simplify rope inspection. The application will enable vessel crews to submit photos of ropes on board and get insight on the severity of damages observed on the ropes, reducing the risk of conflicting subjective judgments and providing an independent assessment of their condition.

Striving towards circularity

While the company’s focus is on investing in and producing ropes that last for longer, it is also tackling the problem of dealing with end-of-life ropes. Today, there are no good sustainable solutions for reuse or upcycling. The best case is that retired ropes are returned and incinerated, but many are discarded and end up as part of the growing sea of marine plastic litter.

As a responsible producer, Wilhelmsen is working, firstly, on a model for return of ropes, and secondly, piloting a circular solution for retired ropes through its Circular Rope Project, which is part of a joint project between the Norwegian government, IMO, and UN Food and Agriculture Organization (FAO) called GloLitter Partnerships. The initiative involves identifying applications that do not use too much extra energy in the recycling process. If it can be shown how retired ropes can be reused or upcycled, a path can also be shown for reusing other types of marine litter. If the pilot succeeds, the company aims to be able to bring 10 000 tpy of retired ropes into circular solutions.

Quality ropes that last

Wilhelmsen takes its impact on the environment very seriously, and is constantly taking steps to design high-quality, long-lasting products to reduce waste and environmental damage.

The company’s Timm Acera mooring ropes can offer significant cost savings over long periods and, thanks to their abrasion resistance and strength-to-weight ratio, will have a lower impact on the environment and a lower long-term cost of ownership compared to other HMPE ropes on the market, making them well-suited in the LNG carrier context.

The Timm Acera solutions for LNG carriers also includes its proprietary Snap Back Arrestor (SBATM) technology designed to significantly reduce the risk of rope ‘snap back’, which poses serious dangers for both vessel crew and quayside workers. The MEG4 guidelines were created based on the learnings from the accident on the LNG carrier Zarga while it was alongside at the South Hook LNG terminal in the UK in March 2015. That was a snap-back accident following a mooring line failure where a deck officer was badly injured, so the SBA fulfils an urgent need to improve mooring safety.

Conclusion

Figure 1. Timm Acera ropes with the Snap Back ArrestorTM safety feature.

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Wilhelmsen’s key value proposition for customers is producing high-quality, durable ropes that facilitate safe mooring operations in line with MEG4 while offering optimal cost of ownership over time. By striving to minimise materials wastage during the production process and exploring novel ways to reuse and upcycle retired ropes, the company also aims to promote circularity and reduce marine plastic pollution, thereby contributing directly to customers’ own sustainability targets.

E

urope’s demand for LNG has increased significantly during the past year. Normally, LNG is imported via conventional shore-based regasification plants. This involves transferring the LNG to terminals for storage in tanks before it is regasified and pressurised with vaporising equipment, prior to it being delivered to the distribution networks. Such terminals, however, require a lengthy construction time, and the current instant demand for LNG in Europe clearly requires quicker solutions.

During the past 15 years, alternative solutions have been developed that are faster and which, by extension, are also less expensive. Among these are Wärtsilä’s regasification modules designed for use onboard FSRU vessels, as well as shuttle and regasification vessels (SRVs).

The increasing global demand for LNG in order to ensure energy security is in turn increasing the pressure for chartering FSRUs and is supporting investments in new units. To cover the new demand in Europe, several FSRUs have been chartered by different countries. These FSRUs have all been available on the market, either built on speculation and not yet under charter, or available following the end of a charter. At present, the surge in demand has resulted in virtually no more FSRUs being available. Thus, in order to cover Europe’s energy gap, the options are either to convert old LNG carriers to FSRUs or build completely new FSRU vessels.

For these vessels, having the regasification (regas) equipment onboard allows high-pressure gas to be delivered to land-based networks, either via a floating buoy and a submerged pipeline system from offshore, or via loading arms on a jetty. Both FSRUs and SRVs provide greater flexibility than conventional land-based regas facilities, and the time from investment decision to start-up is relatively short.

By offering a fast-track means for opening energy markets, supply diversity is increased, costs are reduced, and environmental benefits are enhanced. A further advantage of utilising an FSRU, rather than a fixed, land-based regas facility, is that it can be moved to a new offshore location should the business environment change.

Kjell Ove Ulstein and Per Helge Madsen, Wärtsilä Gas Solutions Norway AS, examine the development of water glycol heated regasification systems for use on FSRUs and offshore jetties.

A seawater heated regas system During the period from 2006 until mid-2020, Wärtsilä has developed and delivered 23 regas systems for FSRUs and one for an offshore jetty.

The first two systems were steam heated using a water-glycol mix as the intermediate medium, but subsequently 11 deliveries were made using seawater as the heating medium with propane utilised as the intermediate medium.

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These systems were delivered as complete modules for easy integration into LNG vessels, both for new-build vessels and for conversion projects to existing ships. The system depicted in Figure 1 has an intermediate loop of propane, where the propane evaporates against the seawater in plate heaters (PHEs). The propane condensates towards the LNG in printed circuit heat exchangers (PCHEs). By using the latent heat in the propane, only small amounts of it need to be circulated, while its low freezing point allows the use of PCHEs that are very compact

and efficient. As a result, the entire system is rather compact and suitable for installation on board ships with limited availability of space.

Switching to water glycol

Subsequent to these deliveries, Wärtsilä developed seawater heated systems using water glycol instead of propane as the intermediate medium. Propane is a very suitable fluid for this application, since it will not freeze and has good thermodynamic properties. However, the use of hydrocarbons in the deck area is restricted by some of the industry’s major operators. With water glycol, the heat exchangers need to be larger, but the use of hydrocarbons as the intermediate fluid is eliminated. Since 2017, Wärtsilä has produced and delivered nine systems of this type.

As shown in Figure 2, the system has an intermediate closed circulating loop of water glycol which heats the LNG in two stages. The initial heating stage is in a shell and tube heat exchanger taking the LNG to a minimum heat of -15˚C, and the second stage is in a printed circuit heater, taking the temperature up to approximately 10˚C below that of the seawater.

The water glycol is circulated at a constant speed Figure 1. A seawater heated system with propane (right) used as the regardless of the LNG capacity, making control of the intermediate medium. system very simple. The system can be arranged in such a way that the water glycol is channelled down to sea level, with the seawater/water glycol heater located there. This eliminates much of the power needed to lift the seawater to deck level. Furthermore, since the water glycol loop is operated at a higher delta temperature than the seawater temperature in and out, the flow typically contains one-third of seawater. This means that the piping required to bring the water glycol up and down is much less than it would be for piping the seawater up and down.

The major benefits Figure 2. A seawater heated system with water glycol used as the intermediate medium.

Wärtsilä’s regas systems are delivered as complete modules, with all the engineering, component procurement, and construction of the module carried out entirely by the company’s execution team (Figure 3).

This makes integration of the modules very easy. All the interconnection work and intercommunication activities with the required utility systems is similarly very simple and straightforward.

In addition to those already mentioned, other benefits of the systems include: a fast delivery time; the compactness and flexibility of the plant configuration; the ease of operation and maintenance; and the fact that all equipment can be serviced or repaired on board the vessel.

Challenging European winters

Figure 3. A Wärtsilä water glycol regas module ready for shipment. All connection co-ordinates are clearly marked.

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During summer, all heat for the regasification is normally supplied from the seawater (open loop).

However, during winter, seawater temperatures in most European waters are low. When the seawater is below approximately 10˚C, other heat sources are needed to support the seawater heating (combined loop).

This supporting heat is usually supplied by steam, but other sources – hot water, for example – could also be used. When seawater temperatures are below

approximately 3˚C, all heating needs to come from sources other than seawater (closed loop).

Some FSRUs are already equipped with steam heating equipment, and some are not. For those without that are likely to operate in cold seawater locations, the regas systems must be modified in order to allow utilisation of an alternative heat source.

Heating the seawater with steam

For heating the seawater with steam, Wärtsilä can supply complete steam heating modules. When requirement for steam heating, heating the seawater are normal on regas systems with intermediate vaporising fluids, such as Wärtsilä’s propane-based regas system, and for systems heating the LNG directly with seawater in large shell and tube heat exchangers. Since heating the seawater and introducing high temperatures can expose the steam/seawater heaters to possible corrosion, high grade materials such as titanium must be used. Furthermore, it is normal to have the seawater operating on a fixed flow, regardless of the regas flow. The fact that the seawater must be heated to a certain temperature means that these systems are not always operated in a cost-efficient way.

Heating the water glycol loop with steam

With the new intermediate water glycol (WG) system, it is possible to heat the WG loop directly with steam. Since WG and steam are not corrosive, a standard material such as SS316 can be used to avoid corrosion in the steam heaters. Also, since the heat is transferred directly to the WG loop, the required steam supply will be according to the actual regas capacity, contrary to the above seawater case where the seawater flow is constant regardless of the regas flow, and the seawater must be heated to a certain temperature.

The steam heater is installed in a slipstream to the water glycol loop, downstream of the seawater heater. To avoid possible freezing when the seawater temperature falls, a bypass (BP valve) is arranged around the seawater heater. This restricts the amount of WG passing through the seawater heater, so the seawater out cannot reach freezing temperatures.

The BP valve arrangement also extends the amount of heat possible to take from the seawater when the seawater temperature is below the limit where steam has to be added.

For a system with steam-heating of the seawater, based on a minimum 10˚C seawater temperature, and a max allowed seawater cooling of 7˚C, which is quite standard, approximately 28.5% of the heat would need to be supplied by steam when the seawater temperature is 8˚C, since it would have to be heated from 8˚C to 10˚C. A similar system with WG loop heating can take more heat from the seawater when its temperature is 8˚C. This is because the seawater can be cooled to 1˚C on the outlet, and the only support from steam would be to increase the WG flow by 2˚C in order to give the required WG temp to the LNG heaters. When the seawater temperature falls further, a portion of the WG must bypass the seawater heater in order to keep the seawater outlet above freezing point. It is, nevertheless, more efficient than heating the seawater.

Figure 4 shows steam-consumption as a function of the seawater temperature for seawater heating and WG heating.

The graph represents a regas train operated at 100% capacity.

In cases where the regas capacity decreases, the seawater

Figure 4. Steam consumption for seawater heating (blue) vs water glycol heating (red) as function of seawater temperature.

heating case will be even steeper, since the same amount of seawater is still heated regardless.

Conclusion

Wärtsilä Gas Solutions has a complete offering of regasification modules for easy integration into vessels. The company provides fast and secure deliveries, regardless of whether it is for a newbuild, conversion of an LNG carrier into a FSRU, or the retrofitting of an existing FSRU. Supporting steam systems can also be delivered for different types of regas plants. They can be delivered as modules, or as loose items for integration by the yard. Again, these are available for newbuilds, conversions, or the retrofitting of existing FSRUs.

WÄRTSILÄ REGASIFICATION SOLUTIONS Wärtsilä’s portfolio of LNG regasification technology represents an industry benchmark in terms of energy efficiency, robustness and operational flexibility.

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LNG Industry asked several companies to discuss some issues regarding LNG tanks.

Chris Desjardins, Bechtel Energy, Tanks General Manager

Chris Desjardins is the General Manager for the Tanks business line in Bechtel’s Energy global business unit. In this role, he has overall responsibility for the development and delivery of all Bechtel’s ongoing and prospective tanks projects across the globe.

Desjardins has over 30 years of experience in management and business development in the EPC industry, and holds a Bachelor of Science in mechanical engineering from the University of Ottawa, Canada.

He is currently leading the team on the ground at the CPC Taichung project in Taichung, Taiwan. He is deeply dedicated to process and digital improvements that achieve increased worker safety and productivity.

Mark D. Butts, CB&I, McDermott’s storage business line, VP Engineering

Mark Butts leads global engineering for McDermott’s CB&I business line, including engineering project execution, storage product line strategy, and business and technical development initiatives. He has 29+ years industry experience with CB&I. The product lines he is responsible for include: LNG storage tanks, LNG peak shavers, refrigerated gas storage and facilities, pressure vessels, atmospheric tanks, water storage, and special structures.

Q1. What factors are considered when designing and selecting storage tanks?

Chris Desjardins, Bechtel Energy

As more countries around the world commit to ambitious energy transition initiatives, Bechtel is ready to assist them in meeting their emission reduction goals and building a greater energy economy for the global community. Customers’ goals are the company’s goals, and Bechtel can provide innovative solutions, experienced teams and personnel, and industry-leading experience to help deliver its partners’ projects.

Finding the ideal storage solution starts with building a one-team relationship early on.

By maintaining strong communication, the company is able to truly leverage its experience to develop a unique solution tailored to the customer’s needs.

There is a vast difference in designing and executing LNG export, import, and peak shaver storage facilities depending on regulatory requirements, land availability, seismic and geological conditions, LNG liquefaction and/or vaporisation requirements, and potential LNG shipping constraints.

For more than 60 years, Bechtel has continued to partner with customers all over the world to advance progress towards cleaner, greener, and safer energy security.

Mark Butts, CB&I, McDermott’s storage business line

The first consideration is the product being stored. The company’s structures store bulk liquid, such as: water, oil and refined products, chemicals, and refrigerated gases such as LNG, liquid hydrogen, and ammonia. Each require unique design and storage configurations offered by CB&I.

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The company also designs for geographic location, including local seismic (earthquake) and soil conditions. Plot size available for construction and siting of the facility are important factors for engineering design and constructability.

Process design requirements, such as flow rates, operating pressures, etc., must also be considered, as well as local regulations established by the Jurisdiction Having Authority, the community, state, or country.

Finally, industry codes and standards establish important requirements for any project.

Q2. How are storage solutions being made more cost-efficient?

Chris Desjardins, Bechtel Energy

Late engagement often results in additional cost and longer schedules because the opportunity to influence early decisions that shape the project development and execution is missed.

Being involved early and working collaboratively opens more opportunities to explore innovative approaches to material selection, supply chain, construction methodologies, and commercial models in partnership with customers. This is more important than ever with the recent rising global costs impacting all aspects of projects.

By prioritising early engagement, Bechtel supports its customers by providing a low cost and short time to market on storage solutions, which is achieved by using its EPC execution

model with optimised designs that produce lower quantities to minimise material and field hours.

Additionally, to support the LNG storage market, Bechtel has: zz Established a facility to research advanced materials and welding techniques at its Welding and Applied Technology Centre in Houston, Texas, the US. zz Opened its Global Tanks Detail Engineering Centre of Excellence in Taipei, Taiwan, that focuses on storage tank detailing. zz Digitalised its core EPC processes, tools, and systems to make them more efficient through its Digital Enterprise Program. zz Introduced 3D modelling and laser scanning to improve design and constructability to eliminate rework.

Mark Butts, CB&I, McDermott’s storage business line

CB&I’s project delivery model ensures high quality and cost-effective solutions for its customers and customers’ projects. This model de-risks customers’ projects by ensuring on-time and on-budget project delivery. The company offers a range of small and large scale solutions, so it is able to offer ‘economies of scale’.

The company has a broad geographic footprint with a local presence in markets around the world, enabling CB&I to access local resources and labour. Its global supply chain offers access to diverse markets for materials, equipment, and subcontractors.

Economies of scale, coupled with its global supply chain, aid the company greatly in areas of cost. CB&I maintains long-term technical and commercial relationships with the world’s largest steel plate suppliers, as just one example.

Q3. How important is insulation, and how is this achieved?

Bechtel Energy: Together with CPC Corp. and MRY, Bechtel is delivering cleaner, greener, and safer energy for Taiwan, supporting the country’s energy growth and security.

Mark Butts, CB&I, McDermott’s storage business line

Very important, as the right materials must be chosen for the right applications. CB&I includes an insulation technology team with its own fleet of proprietary equipment to install specialised insulation systems. The company can control all aspects of the insulation system design, supply chain, proprietary construction equipment and field operations to execute the insulation scope of work on a global footprint. This is an important aspect of CB&I’s project delivery model.

Q4. What new technologies and developments in LNG storage tanks can we expect in the future?

Bechtel Energy: The water treatment plant at

Shell Polymers Monaca repurposes water from the Ohio River to generate steam and provide cooling onsite in Beaver County, northwest of Pittsburgh, Pennsylvania, USA.

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November 2022

Mark Butts, CB&I, McDermott’s storage business line

Smalll scale modular tank designs, as well as large scale tank designs for baseload import and export terminals. CB&I is

Addressing Energy Transition, Security, and Affordability

Cheniere Energy, Inc. in Corpus Christi, Texas, 2018

For more than a century, Bechtel has helped customers navigate shifts in energy consumption. By partnering with LNG industry leaders, we are building projects around the world and optimizing existing designs to deliver energy efficiency while providing sustainable solutions for generations to come.

Visit bechtel.com/energy to learn more.

optimising project delivery across the entire scale of project type and size.

zz EN 1473 – Installation and equipment for LNG – Design of onshore installations.

Q5. Numerous types of LNG storage tanks exist. Can you detail the technology behind one of your most popular tanks?

Q7. Can you detail a critical infrastructure project where your company overcame some challenges with regards to its storage solutions?

Mark Butts, CB&I, McDermott’s storage business line

One of CB&I’s most popular tank designs is full containment concrete, with an inner tank manufactured with cryogenic grade steel, and an outer tank constructed with reinforced post-tensioned concrete.

CB&I also recently pioneered the world’s first full containment double steel tank, with the inner and outer tanks both manufactured from cryogenic grade steel.

Q6. With standards and regulations frequently revised and updated, how does this impact tank designs and quality?

Mark Butts, CB&I, McDermott’s storage business line

CB&I actively participates on the main Code Committees.

It helps shape the requirements and stay current with code changes as they happen, including the codes listed below, which minimises any adverse impacts to tank designs and quality: zz API STD 625 – Tank Systems for Refrigerated Liquefied Gas Storage. zz NFPA 59A – Standard for the Production, Storage, and Handling of LNG. zz EN 14620 – Design and manufacture of site built, vertical, cylindrical flat-bottomed stell tanks for the storage of refrigerated, liquefied gases.

Chris Desjardins, Bechtel Energy

Every project with the magnitude and complexity of an LNG tank faces many challenges that the one team – consisting of Bechtel, customer, and sub-contractors – works together to overcome.

When presented with complex challenges, the company is able to draw upon the wealth of knowledge and unique experience of the Bechtel Fellows and Distinguished Engineers to quickly execute a solution.

CPC Taichung, the company’s active LNG tank construction project in Taiwan, involves executing the EPC of two 180 000 m3 full-containment LNG tanks that, when completed, will become the largest storage tanks ever built in Taiwan. The project is in an active seismic zone, which presents unique design challenges. The LNG tanks and surrounding sub surface were specially designed to ensure the design addressed the seismic criteria specified. Additionally, seismic events may cause increased LNG sloshing waves, which called for a specialised roof design not often seen outside Southeast Asia.

Mark Butts, CB&I, McDermott’s storage business line

The Tacoma LNG facility at Puget Sound Energy in Tacoma, Washington, the US, is a dual use facility, operating as an LNG peak shave and a bunker fuelling station.

In addition to the dual nature, the storage tank is designed with seismic isolators due to its location in the high earthquake zones on the West Coast of the US.

CB&I, McDermott’s storage business line: Full containment tank system, including: steel primary container, concrete secondary container, and concrete roof.

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Sunil Biswas and André Jäger, ION Commodities, explore how technology can integrate and streamline the LNG market.

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T

he ongoing energy crisis in Europe has put natural gas, particularly LNG, in the spotlight. Set against the backdrop of long-term trends towards decarbonisation and cleaner burning fuels, LNG has been playing an increasingly important role as a transition fuel on the path to net zero emissions. Significant global infrastructure investments over the past decade across the supply chain, from liquefaction facilities to carriers and regasification terminals, have enabled the market to develop and solve a classic supply and demand dislocation problem. Buyers – primarily Asian countries, including China, Japan, and South Korea – have dominated the demand side of the market for the relatively cheap energy source from suppliers across the world – primarily Australia, Qatar, and the US. The war in Ukraine and resulting gas shortfall in Europe, which previously sourced 40% of its natural gas from Russia via pipelines either over land or undersea, has now thrust European demand for LNG to centre stage. This has led to a bidding war emerging between the East and the West for the supply of LNG that is constrained by existing infrastructure. Published in August 2022, Rystad Energy research projected that investment across the LNG value chain is set to grow to an annual total of US$42 billion by 2024.1 This staggering increase, which is nearly 20 times the US$2 billion spent in 2020, is due in no small part to a massive rise in European demand, and stands as clear evidence of the market’s growth potential.

As the energy crisis deepens, LNG market participants, including producers, traders, and utility consumers, are posed with several key questions: Is there visibility into key operations across the supply chain? Are they prepared for supply and demand changes in the LNG market? What protections do they have in place to insulate core business operations from price volatility?

Is there visibility into key operations across the supply chain?

The LNG supply chain is complex, spanning natural gas production, liquefaction, cargo trading, vessel management and logistics, regasification, and natural gas delivery. Additionally, there is the complexity of gas and LNG storage. The supply chain supports many participants: upstream LNG suppliers, downstream LNG consumers, LNG cargo traders, and end-to-end supply chain operators. Irrespective of their role, participants need visibility into the supply chain. They need to know their contractual commitments to supply and deliver LNG, their storage and movement of LNG, and the full accounting of their inventory along the supply chain.

Without a consolidated solution to manage and report inventory on a near real-time basis, the ability to navigate a supply chain disruption becomes even more challenging and can lead to scheduling and logistical constraints. For participants that operate liquefaction and regasification plants, it is imperative to model these processes in a solution that supports inventory transformation to ensure obligation fulfilment.

Furthermore, managing stored gas and LNG inventory within a solution presents opportunities for asset optimisation. Operators that align storage levels to supply and demand are rewarded with revenue opportunities that remain locked to others.

Are LNG market participants prepared for supply and demand changes in the LNG market?

Until recently, demand for LNG was driven almost entirely by Asia. But, against the backdrop of the current war in Ukraine,

energy security has become an overriding concern for European governments seeking to replace Russian pipeline gas, with dramatic effect on global natural gas prices. The new swell in demand for LNG has fuelled an extreme shift to a sellers’ market that is in a severe supply deficit. Given the challenge of producing additional supply volumes – a feat requiring billions of dollars of infrastructure investment and years to get the facilities online – it is fair to expect that the current shortfall is here to stay.

Increased demand, prior to the Ukraine war, had already led to a substantial rise in CAPEX in exporting facilities, particularly in the US and Qatar, as well as increased regasification capacities in Europe. The rise of LNG has resulted in much more interconnected global gas markets, where events local to a specific gas market impact the prices of gas markets on opposite sides of the world.

As a result, in the past year, the historical trend towards higher volume spot LNG markets has largely reversed, due to the rise in long-term sales and purchase agreements (SPAs). Long-term contracts are pivotal for improving the supply outlook as they reduce the investment risk in large scale CAPEX projects, ultimately leading to more final investment decisions.

What protections are in place to insulate core business operations from price volatility?

So far, 2022 has witnessed record price spikes, dramatic volatility, and evaporating liquidity across global energy markets as demand recovers above 2019 pre-COVID levels, despite recession fears and rising interest rates. Beyond this, European gas markets have been traumatised and decoupled from the rest of the global energy markets. The supply-chain disruption due to the Ukraine war constrained the Russian commodities ‘super-store’ and sent the EU gas benchmark into the stratosphere. The price dislocation has been so severe that there is a knock-on liquidity squeeze in derivatives markets as prices and volatility have surged for a sustained period. Consequently, transaction and hedging costs rose, and many participants faced outsized margin calls with cashflow implications.

While the current EU gas situation is extreme, these black-swan market events seem to be occurring more frequently – consider global demand destruction with COVID-19 and negative WTI prices in 2020.

To navigate through these challenges, participants need software solutions for price exposure and risk management.

Software solutions need to calculate commodity price exposure on underlying transactions, associated hedges, and stored and in-transit inventory. With the exposure of commodity positions defined, participants can then monitor and manage their portfolio level risk. Market risk, including value-at-risk, profit-at-risk, and earnings-at-risk, are directly related to commodity prices, while credit risk is related to a counterparty’s delivery ability.

With the ability to calculate and report these different types of risk on a macro and a micro scale, market participants can make more informed decisions to protect their business. This is especially important during times of supply disruption, when the risk of failing to supply rises in step with the supply replacement cost, as it is directly related to commodity prices. Furthermore, during times of extreme market structure stress, liquidity management comes to the forefront as participants look to optimise their cashflows.

Monitoring success and potential downfalls requires sophisticated risk metrics. When combined with position transparency, end-to-end supply chain coverage, and operational

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excellence, it enables better decision-making and profitable utilisation of contractual and logistic optionality in a portfolio.

Elevating operations with technology

Technology providers innovate to create solutions that simplify complexity. During challenging times, the LNG industry needs technology systems that are flexible, scaleable, and specifically address the issues of today’s market. This includes modelling disrupted natural gas delivery with LNG, managing gas and LNG across the end-to-end supply chain, and accommodating new market entrants and instruments, including contracts such as SPAs. To help companies simplify and automate critical processes, technology providers are bringing new innovative enhancements to their solutions for better management of risk and logistics throughout the gas and LNG supply chain. For example, utilising machine learning models for applications such as predictive pathing on natural gas pipelines. This is backed by market leaders that have already been experimenting with these solutions and seen significant benefits.

One such company – a US$10 billion joint venture by oil and gas market leaders focused on North American LNG exports – has experienced the drag of outdated legacy systems incapable of dealing with the sheer volume of its processes. To realise its ambitions (adding further liquefaction and export capabilities into an existing LNG terminal) this company concluded that it needed to substantially upgrade its portfolio management, optimising not only its liquefaction terminals, but also its related export business.

The mission was clear: implementing a commodity management solution that could create a highly automated transaction processing backbone and provide advanced decision support to the business’ commercial personnel.

Working towards this objective, the company replaced its outdated system landscape with a solution that could be scaled to support anticipated business growth in the years ahead. The result? The company’s tailored solution was designed to accommodate the evolving business needs of traders, risk managers, physical operators, and financial accountants. They are now able to manage and monitor positions, contracts, risks, and optionality throughout the supply chain, including the modelling of liquefaction and regasification processes. More than ever, businesses need real-time risk analytics and reporting to not only minimise supply chain risks, but also automate critical business processes so they can make faster, more informed decisions.

This trend can be seen at countless commodities intensive corporations, such as another integrated global company, which wanted to future-proof its trading ambitions and streamline operations across five continents. The road to realising these

objectives began with establishing a single software backbone: a layer of integration and a source of ‘truth’ across front office (physical and financial trading), logistics, operations, risk management, back office, and accounting – combined with dedicated integration for market prices, exchange trades, vessel charting and operations, and general ledger postings on enterprise resource planning.

By building this backbone for its current LNG portfolio, this company took advantage of current and future market situations, moving from outdated manual systems to modern automated technology that can manage the risks and challenges it faces today. Like many others, this company chose to utilise Cloud-based managed services and Software-as-a-Service solutions to prioritise higher revenue opportunities, rather than be encumbered by managing its IT infrastructure.

Unlocking profitability for the future While LNG is expected to be in undersupply for at least the next two years, those dealing in this sector will need to adapt to operating across more complex logistics. Above all, it is going to be crucial to react quickly to changing prices and costs by having complete position and operational transparency. Key questions need to be answered in real time: Where is it hedged and what is the open exposure? What are the physical positions and what embedded flexibility can be utilised to the company’s favour?

What capacities for shipping, liquefaction, and regasification are available? With additional levels of transparency, traders and operators can adapt their strategies and related logistics quickly and take advantage of market changes as they occur.

Replacing gas obtained through Russian pipelines remains the primary focus of most European governments and businesses.

But other drivers – such as IMO 2020 – are elevating perceptions of natural gas and LNG as ‘clean’ fuels and ‘transition’ commodities that could replace higher-emission fuels during the switch to a completely renewable energy mix. For example, IMO 2020 regulations are expected to drive an increase in LNG-driven ships in the coming decade. IMO 2020 has placed a cap on sulfur emissions from ships, and due to low sulfur content, LNG has been highlighted as an alternative to high sulfur fuel oils, which has traditionally been the main fuel for the shipping industry.

Beyond this, there is no question that more industry change is to come. New trading hubs will expand and deepen spot markets, enabling liquidity in physical and financial trading. Novel financing options and floating technologies could also lead to more flexible contracts with shorter durations and creative pricing.

It is clear that LNG supply chain management favours businesses that utilise sophisticated commodity management solutions. Technology providers have a significant role to play, servicing the LNG industry with solutions that meet both current and future needs.

Conclusion

In summary, commodity management solutions with innovative technology that integrates end-to-end supply chain coverage and improves business efficiency through automation will dramatically benefit companies operating in the evolving LNG and wider commodity markets.

References Figure 1. Global LNG CAPEX by facility type 2013 – 2022.

Source: Westwood.

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1.

‘Spurred by the energy crisis, global LNG investments will now peak at $42 billion in 2024, a 50% jump from current spending’, Rystad Energy, (2022), www.rystadenergy.com/news/spurred-by-theenergy-crisis-global-lng-investments-will-now-peak-at-42-billion-i

Michael Hastings and Jonathan Fox, B&K Vibro, detail how a typical condition monitoring and diagnostic solution can be enhanced using a data historian in the LNG industry.

T

he LNG industry is a good potential user of a data historian-based condition monitoring and analytics platform since there are so many machines being monitored, sometimes by several different systems. There are a number of processes in making LNG, but the specific areas where critical machines are monitored include the liquefaction process, the LNG storage and loading process, and power and utilities at the end of the process.

B&K Vibro has been a proprietary condition monitoring solution system supplier for more than 23 years. During this time, up to six LNG plants have been monitored, which altogether provide 18% of the world’s LNG production capacity. There are many machines that have been monitored in these LNG plants, both balance of plant and critical. From the company’s experience, a historian-based condition

monitoring solution in the form of PI-based condition monitoring analytics has been proposed, which is relatively new to the LNG industry, but has proven to provide improved benefits.

The standalone proprietary monitoring system vs data historian-based solution

In the beginning, there were only standalone proprietary systems available for condition monitoring; however, with the development of a historian-based condition monitoring analytics solution, new and better monitoring opportunities have been opened up.

For those plants that have installed a historian that is also capable of condition monitoring and analytics, chances are

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that there is already a traditional proprietary condition monitoring system on site that has its own standalone server.

This means IT must review two systems for security, storage, network access, and many more tasks. With a condition monitoring system based on a historian, much of this work will be reduced. Once the historian has already been deployed, it just needs to be extended to also serve the condition monitoring needs. The advantages of doing it this way is that the IT department only needs to maintain one system and can generally do this in house, without relying on multiple vendors. A modern historian, such as the PI system, can support more than 1 million writes/sec., which is more than sufficient to support a condition monitoring system. The PI system itself already has the necessary tools to run the condition monitoring functionality and even perform analytics. The focus of this article will be about the analytics

portion of the data historian-based condition monitoring solution and how the PI system can be used to provide an open architecture solution to enhance LNG operations.

Conditional monitoring visualisation in the data historian

Figure 1 is the visualisation screen of the PI system, which is called PI Vision. Here, the measurement values and the alarm status for all the process and vibration measurements monitored on a LM6000 gas turbine genset are demonstrated. This particular gas turbine is from a different project, but it can be used as an example for the gas turbines monitored in the power utilities portion of the LNG plant, or any of the gas turbines used in the plant for that matter. Interactive icons can be clicked to receive more information on sensor measurements, calculated values, and diagnostic plots. Clicking the icon enables the user to, for example, do a deep dive to find out why the accelerometer measurements are an alarm situation (Figure 2).

KPI analytics based on the maintenance performance of the machine

Figure 1. Alarm status visualisation showing process, performance, and vibration

data. Four icons (white circle with blue signal) are shown for opening up diagnostic plots. These icons include one for performance monitoring (upper left), analytics (lower left), forward-end vibration (middle), and aft-end vibration (right side). This is a PI Vision display.

Figure 2. Vibration diagnostic plot visualisation for the aft-end of the gas turbine (opened by clicking the aft icon shown in Figure 1). This is a proprietary condition monitoring system display.

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The analytics icon shown in Figure 1 displays gas turbine calculated key performance indicators (KPIs) when clicked. An example of KPIs for incident and service metrics for any machine type can be meantime to failure rate, meantime between failures, etc. Other calculated maintenance KPIs can be specific for gas turbines, such as forced outage factor, service hours per start, etc.

These are general asset maintenance metrics for this particular gas turbine. These calculated KPI values can be correlated with ‘and/or’ displayed next to the normal condition monitoring functions displayed on the visualisation system. Users are notified when KPI or condition monitoring alarms occur. For a specific asset, operators can see how problematic the machine has been by just correlating this monitored information with the KPIs. The computerised maintenance management system (CMMS) software does a lot of this, so these values can be accessed and searched in the CMMS data if there is an interface with such a system, or they can just be calculated directly in the PI asset framework part of the system.

The data historian analytics are not necessarily limited to the machine being monitored, it can also be applied to the condition monitoring system itself. This includes metrics on the accuracy of the condition monitoring system for fault detection diagnostics and estimating lead time to repair, such as time from detection to diagnosis for faults, time from diagnosis to service action, etc. This can be used for evaluating the performance of the condition monitoring system; more importantly, it can also be used for fine-tuning the estimates to improve the performance of the condition monitoring system and its diagnostics and analytics. It is possible a condition monitoring system provider may not necessarily provide these measurements by default, so this is one of the benefits of a historian-based condition monitoring solution.

Historian-based analytics on performance monitoring using a gas turbine

One of the icons shown in Figure 1 is for opening up the performance monitoring plots and calculated parameters.

Figure 3 shows the typical process values used for calculating the LM6000 performance parameters.

These process parameters can come from the distributed control system or data historian but will have to be imported into a standalone condition monitoring system for calculating performance values, so this data becomes duplicated. It is not only process data that is needed, but also machine data and machine performance curves from the gas turbine supplier.

All this data represents the input parameters for calculating

the performance values and determining the alarm limits.

Typical process parameters that are calculated for a gas turbine can include overall thermal efficiency, firing temperature (actual and according to ISO 2324), isentropic compressor efficiency, etc.

The performance calculated functions are used for both monitoring to alarm limits, and also as input into a number of plots for diagnostic purposes. These plots are normally not provided by the data historian, but by the condition monitoring system (CMS) or third-party service providers to the data historian. These typically include heat vs time, efficiency vs time, exhaust temperature vs time, etc.

A more successful digitalisation initiative

The PI system is a fully capable condition monitoring, analytics, and decision support system. It can aid operators, engineers, and monitoring maintenance technicians in monitoring and optimising the health of their machines at each stage of the life cycle of a machine. The CMS provides tools to resolve an issue and support the end-user specialists.

Automatic decision support

This includes automatic decision support to reduce the workload of the diagnostic specialists. The CMS compliments the PI system by providing diagnostic tools such as specialised plots to better understand the fault, its severity, and the estimated lead time for maintenance. If the user does not have that expertise, they have the option to export that data to a third-party service provider that has that expertise.

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Figure 3. Developing and fine-tuning automatic decision support; monitoring results are combined with maintenance feedback (left) and rule-based automatic support is modified to reflect this feedback (right).

and the engineers learn, the analytics that are in place can be adjusted to capture that knowledge and a better solution can be developed going forward. Because the PI system is not a siloed solution and all the data is available, not just some of it, this enables a more successful digitalisation initiative on the asset healthcare that would otherwise not be possible.

Figure 4 is an example of how these analytics would work. In the upper left are the measurements that are coming in from the condition monitoring system hardware, and in the upper right are indicators that are being calculated from those measurements to look for the different things that inform the user of Figure 4. Automatic decision support example for shaft bearing rub. what the fault is. The lower left area enables With the AF database, analytics can be set up in a template the user to determine what state the machine and deployed to various assets in a fleet of machines. AF is currently in, so the most appropriate analytics can be analytics provides a powerful tool set that makes it easy applied to it. Then finally, in the lower left, all that can be to work with time series data. It allows the machines to be combined to determine a likelihood of a particular failure modeled for vibration and process attributes. It allows users happening – in this example, the likelihood of a rub occurring to calculate various failure indicators from that raw data. For on a particular bearing. example, it is possible to measure the flatness, the reverse procession instability, and many more indicators of a potential Conclusion failure mode of the bearings and other components. These The typical LNG plant has a wide range of machines, both indicators can then be combined to more accurately identify critical and balance-of-plant, where some are even monitored the origin and severity of a particular failure mode. With by different systems with their own proprietary data this information, an analyst can focus their efforts and more servers. Proprietary data and analytics can be expensive, not quickly determine the next course of action. transparent, and not always readily accessible. The LNG plant With those analytics in place, the PI Vision software also could benefit immensely by storing the monitoring data in a provides tools for root cause analysis. It allows users to central historian for correlation and fleet monitoring purposes, reliably compare historical events. With the knowledge of which could also offer more data for artificial intelligence and historical faults that may have happened on that machine as machine learning statistical analysis. well as those related to other machines, users can get more There is a lot of powerful functionality and capability with confidence in estimating lead time to maintenance and the PI-based analytics. There is also a lot of data available in avoiding the same fault occurring again. When it comes to the historian for analytics, which of course, can be used for specialised plots, users can go from the PI system to a CMS more effectively monitoring machines, even if these are using that allows further analysis with specialised plots. As users different condition monitoring systems. It is possible to even move through the process of analysing and acting on an event measure the performance of the different condition monitoring that has happened to their machine, maintenance will systems. The PI AF calculator engine is transparent and implement actual fixes and upkeep on the machine. But relatively easy to programme. There are specialised plots that through that process, users will learn things about the will still have to be provided by the condition monitoring machine that can then be captured and put back into the PI supplier or the third-party service provider, but oftentimes, system. With the event that is initially generated, users can these can be integrated in the PI system, the PI Vision. capture notes and documents as well as document the reason Automatic fault analysis and automatic decision support is for the failure. Based on the information that maintenance possible in PI.

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Stefano Calandri, Vanzetti Engineering, Italy, studies the response to the technological evolution of engines with a view to greater efficiency and intensified deployment of LNG structures.

M

ore and more new ships are using methane engines for their propulsion system, particularly those with high-pressure systems. This is a reversal in trend compared to a few years ago, when low-pressure systems were more common. Moreover, in the small scale industrial sector, the cryogenic pump downstream applications that have seen a significant growth in the past few years are related to gas pipeline feeding, gas power generation stations, gas peak shaving plants, and LNG transfer in small-to-medium size shore terminals.

Therefore, Vanzetti Engineering has significantly increased the supply of its high-pressure pumps for the marine sector in response to the increasing demand for this type of product for marine engine fuel supply systems.

Pumps for ships

The new trend in recent years about LNG marine engines is linked to their technological development, with a growing focus on more sustainability and greater efficiency. Vanzetti Engineering was already supplying high-pressure pumps for the marine sector in 2019. However, if up until 2020, 90% of the cryogenic pumps sold for this sector were low-pressure pumps

(maximum 20 bar), from the start of 2021, orders for high-pressure pumps (maximum 350 bar) have increased considerably, to the point that today 50% of orders are for high-pressure pumps and 50% for low-pressure pumps.

Since 2021, the number of orders for VT-3 reciprocating high-pressure cryogenic pumps has boomed. This is due to the new market trend towards high-pressure systems, especially for large methane-powered vessels such as container ships, bulk carriers, gas and chemical carriers, and car carrier ships. Today, large ships can be fitted with high-pressure two-stroke engines and therefore require the Duplex, Triplex, or Quintuplex versions of reciprocating pumps.

Vanzetti Engineering’s VT reciprocating cryogenic pumps supplied a large number of skid-mounted VT-3 Duplex and Triplex pumps for over 30 ships with high pressure fuel systems, to customers located in various geographic areas, in particular China, Korea, Singapore, and Norway.

Fuelling vehicles

To fuel vehicles with a natural gas engine (NGV) with compressed natural gas (CNG) or LNG, the company offers customised solutions for public stations and private fleets. LNG is stored in a

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cryogenic tank, which provides fuel to the high-pressure reciprocating pump. Compressed LNG is pumped through an ambient vaporiser, where it is warmed and transformed into CNG. To complete the process, the CNG is then stored in a gaseous buffer, ready for refuelling vehicles. For this type of fuelling station, the supply proposed by Vanzetti Engineering consists of: zz Reciprocating piston pump model VT1 with 800 Nm3/h capacity (or two pumps to double the flow-rate) and 30 kW electrical motor power installed. zz Cold charge group to optimise the CNG temperature and the gaseous storage efficiency (optional). zz High-pressure ambient vaporisers for vents. zz Distribution and safety panel to protect non-cryogenic components from temperatures that are too low and over pressures. zz Electrical control cabinet (optional) with remote access for web browser monitoring.

Safety, reliability, and low maintenance

The company’s VT-3 reciprocating cryogenic pumps, which evolved from the previous VT-55 model, come in Simplex, Duplex, Triplex, or Quintuplex versions depending on the flow rate required and have a maximum pressure of 420 bar. The VT-3 model is an effective solution in terms of performance,

Figure 1. Submerged cryogenic pump ARTIKA series.

safety, reliability, and low maintenance requirements and can be provided on a skid with all accessories including sensors, instrumentation, and valves for a safe and reliable control of the pump. VT Series cryogenic reciprocating pumps offer high efficiency, compatibility with cold converter and thermosyphon storage tanks, and easy installation thanks to 360˚ rotating inlet and outlet connections. Their maintenance is quick thanks to the integrated cartridge seal system. VT Series pumps can be used in CNG refuelling stations for road vehicles and for buffer filling.

Centrifugal multi-stage submerged pumps

With numerous marine pump projects supplied and several in its order portfolio, ARTIKA submerged pumps can be the answer to various needs for small, medium, and large LNG carriers: fuel gas pumps, spray pumps, stripping pumps, and cargo pumps. Depending on the requirements, the ARTIKA models can pump the LNG from extremely low to very high flow rates, with supplied differential pressures that can vary from minimum levels up to approximately 20 bar necessary for the XDF two strokes’ engines. For example, for automotive sector LNG refuelling stations, Vanzetti Engineering proposes the ARTIKA 160 submerged pump that can be used for one or two LNG dispensers. The ARTIKA 120-3S is the smallest pump in the series and is used in marine sector applications.

The ARTIKA 200-4S can deliver a guaranteed flow rate of over 30 m3/h at 35 bar, while the ARTIKA 200-6S is able to reach a differential pressure of 55 bar.

Both models can be used for FSRU projects. In order to meet the needs of applications that transfer LNG to small and medium size terminals, the ARKITA 300 is available in a 1 or 2 stage configuration, which can reach a flow rate of up to 270 m3/h.

With a flow rate of up to 546 m3/h, the ARTIKA 400 will complete the current range of submerged LNG pumps designed by Vanzetti Engineering. With the ARTIKA Series, the company is able to supply all the cryogenic pumping equipment downstream of the liquefaction plants, on skids, and complete with all the accessories, sensors, and instruments. The features of ARTIKA pumps include the seal-less concept with the motor bearings permanently lubricated by LNG, which allows a perpetual cold condition for quick and efficient starting and stopping and a low maintenance frequency due to the absence of wear parts. The ARTIKA Series submerged cryogenic pumps for LNG are available in one-stage or multi-stage configurations (2, 3, 4, or 6). They are designed to work submerged in cryostats/sumps or in cryogenic tanks and are suitable for continuous and discontinuous operations. They feature helical inducers to minimise NPSH requirements, integrated motors to be used with inverter/VFD, and low noise (<80 dB) during operations.

External centrifugal pumps

Figure 2. Reciprocating cryogenic pump VT-3 series.

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The company has developed the hydraulic gearbox motor (HGM) series to expand its range of centrifugal cryogenic pumps to be mounted on tanker trucks. This extension range allows the company to meet any type of requirement for loading and unloading road tankers. A centrifugal cryogenic pump on truck board is used to transfer LNG from the truck to the refuelling station storage tank, allowing the pressure difference between the storage tank and the tank of the vehicle to be compensated. Unlike the hydraulic direct motor (HDM) series pumps, the HGM series pumps have a hydraulic motor and gearbox transmission to take maximum advantage of the

HGM technical features. The structure of the new HGM series is particularly robust and offers a maximum operating speed of 8190 RPM, with a maximum flow rate of 950 LPM. These new types of pumps, which includes the HGM 185 and HGM 200 models, offer significant advantages: the low weight allows the unload maximisation whereas the compact design requires a small amount of space for installing. The introduction of this new series enables the company to meet the needs of those who require a cost-effective solution, while maintaining a high-level of performance and reliability.

The HGM series is an additional solution for: road trailers unloading, storage/iso-containers loading/unloading, process and back-up operations, petrochemical industry applications, special applications with differential head and flow rates upon customer demand.

HGM technical features include: hydraulic motor and gearbox transmission, mechanical seal in rulon, inducer to minimise required NPSH, low noise emission (<80 dB).

Certified quality in compliance with international standards

Vanzetti Engineering’s production process is characterised by a high level of quality combined with customer satisfaction.

Over the years, the company has won several awards and certifications for its cryogenic pumps and components produced in compliance with mandatory and voluntary standards. The quality management system, which is rigorously applied, allows full traceability to each production phase. From the design and construction to the inspection and testing of each component, the company operates in full compliance with all current Italian, European, and international standards:

zz UNI ISO 9001 Quality Management System. zz European PED. zz European Machinery Directive. zz European ATEX Directive. zz Technical Rules of the Customs Union (EAC). zz EIGA/IGC/CGA guidelines. zz Marine Class Certifications: BV, DNV, ABS, RINA, LR, CCS, NK, KR, RMRS.

Conclusion

Vanzetti Engineering’s goals for the future include improving its products and research and development for the devices that will equip its next-generation systems. It is therefore essential for the company to go beyond the concept of consultancy and pure sales because it is of the utmost importance to participate proactively in every realisation; in this way, it will be possible to achieve numerous advances in technological deployment, which will translate into the generation of value and benefits. The company also pays attention to the entire after-sales phase, focusing on the customer, as giving the customer the opportunity to get to know the product in-depth means enhancing the technology and being able to exploit every feature of it to achieve maximum performance.

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Patented nozzle safety feature is recognized in the market as a major failsafe advantage for the operator.

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avitation occurs in centrifugal pumps when the net positive suction head available (NPSHa) is lower than the net positive suction head required (NPSHr), causing the formation and accumulation of bubbles at pump inlet that collapse and result in a series of mini implosions. Cavitation can occur in different locations within pump hydraulics and can cause significant damage to the pump’s internal components. The cavitation behaviour of cryogenic centrifugal pumps is an important performance criterion for safe operation in the event of a lack of suction pressure. Inducer technology is often used in pump applications to delay cavitation or to improve suction performance by reducing the NPSHr. One of the most common applications for cryogenic centrifugal pumps is inside LNG storage tanks, where NPSHr determines the non-useable height of the liquid being stored.

In-tank pumps are vertically suspended within a discharge column, mainly used to transfer the fluid within the tank. Due to their size and construction, storage tanks cannot be pressurised, which limits available suction pressure to the pump. A helical style inducer is installed at the lowest section of the pump to enhance suction performance (Figure 1).

This case study compares the cavitation performance of an in-tank LNG cryogenic pump with a constant pitch inducer and a pump configuration with a variable pitch inducer. Computational fluid dynamics (CFD) simulations and experimental performance tests were conducted to determine the cavitating (two-phase) and non-cavitating (single-phase) performance of the two inducers under operating conditions. NPSH with a 3% differential head drop (NPSH3) was used as a criterion to identify the true cavitation performance of each inducer configuration. Replacing the constant pitch inducer with a variable pitch inducer resulted in a 25% improvement in NPSH3 performance with minimal impact to single-phase pump performance.

Inducer design for in-tank cryogenic pumps

Due to cost and manufacturing constraints, storage tanks for any hydrocarbon application (LNG, methane, propane, butane, etc.) are constructed to handle a maximum tank pressure of 300 mbar (4.35 psi) or less. Consequently, suction pressure of the pump is often dictated by the static height of the liquid. Inducer design is crucial for these applications as it ultimately determines the minimum liquid level in the tank required for safe and

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stable operation. The main objective is to reduce the NPSHa as much as possible so that the height of useable liquid inside the tank can be increased. It should be noted that the overall footprint of a storage tank can be as large as 200 m (656 ft) dia.

Therefore, any small improvement in the magnitude of a few centimetres can result in substantial improvement in the useable amount of liquid.

The subject retractable in-tank pump was designed to operate in propane and installed inside a storage tank. It is a vertically suspended two-stage cryogenic submerged motor pump with a helical inducer downstream of the suction impeller to enhance suction performance. All in-tank pump applications are furnished with a helical inducer to delay cavitation inception so that it can be safely operated at very low liquid levels with reduced suction pressure.

Under normal operating conditions, in-tank pumps often have enough suction head and there is no concern of cavitation during continuous operation. However, during the process of emptying the storage tank, cavitation performance dictates the liquid height. Although in-tank pumps are not continuously operated under very low suction head, in order to attain an acceptable low liquid level after the tank is emptied by the pump, NPSH is quite important for these particular applications.

The original pump design was constructed using a straight pitch constant hub diameter (constant pitch) inducer. Constant pitch inducers follow the flat plate design at which the inlet and outlet blade angles are the same. Therefore, overall head (pressure) increase mainly depends on the rotational speed, tip, and hub diameters. In this case, the blade angle is 8.9˚ at the tip diameter (Table 1). Hub and tip diameters are constant along the axial direction.

For the new (variable pitch) inducer design, the blade angle was increased from suction side to discharge side with constant change along the axial length. The inlet blade angle was determined based on the meridional flow at the suction section to ensure shockless entry to the inducer. In order to reduce the meridional flow at the suction side, the hub diameter was reduced and gradually increased towards the mid axial point.

Blade count was increased from two to three to prevent any alternate blade cavitation. Blades were leaned forward to minimise the back leakage vortex that occurs between the tip of the inducer and the inlet casing bore. Table 1 shows the specifications of both the original and the new inducer design.

Enver Karakas PhD and Robert Mollath, Elliott Group, USA, describe how to enhance cavitation performance in cryogenic centrifugal pumps, using a case study as an example.

The main characteristic of the variable pitch inducer is the ability to increase head via change in blade angle from suction to discharge. With the increase in blade angle at discharge, more head can be produced by the inducer with an increase in absolute velocity. More importantly, with the variation in blade angle from suction to discharge, shockless entry at the design flow can be obtained. It should be noted that the variation in blade angle from suction to discharge is adjusted based on the impeller eye geometry.

CFD simulations

To establish a pump performance curve, pump performance was investigated in terms of non-cavitation performance. To determine cavitation performance, CFD simulations were conducted at rated flow rate with varying suction pressures. ANSYS CFX software was used to simulate the first stage of the pump assembly.

In order to predict the true performance of the pump assembly, all hydraulic components (inducer, impeller, and diffuser vane) were included in the CFD model.

which is used to determine the cavitation characteristics. As in suction specific speed, there are certain values of the cavitation number, depending on the pump differential head drop. The most important cavitation number in pump applications is the critical cavitation number which corresponds to a 3% pump differential head (pressure) drop. The critical cavitation number determines the NPSHr of a pump.

Below this suction head or corresponding liquid height, the pump is often not allowed to operate due to the possibility of significant damage. This critical NPSH level is also known as NPSH3.

Cavitation modelling

The cavitation model implemented into the CFD code defines the relationship between the initial bubble

Pump cavitation parameters

There are two fundamental dimensionless pump cavitation performance parameters used in performance comparison. The first parameter is the suction specific speed, which is commonly used to identify the cavitation performance of a pump. It represents a non-dimensional version of the suction pressure. It should be noted that there are certain values of the suction specific speed depending on NPSH, and consequently, the amount of differential head loss.

The second parameter is the cavitation number,

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radius and the pressure around the bubble. The interphase mass transfer rate for condensation and vaporisation was defined using empirical constants, a proven method of predicting cavitation performance of inducers.

Boundary conditions

Table 2 outlines the boundary conditions and simulation details.

Thermodynamic and transport properties of vapour and liquid are defined as a function of temperature and pressure in accordance with saturation and sub-cool tables published by the National Institute of Standards and Technology (NIST).

Test setup and procedure

Tests were conducted at Elliott Group’s Cryogenic Test Facility to determine the cavitating and non-cavitating performance of each pump assembly. The tests were carried out at a constant temperature level with propane at cryogenic condition.

For non-cavitation performance testing, each pump was operated at several different flow rates according to API 610 guidelines [16], and pump differential head input power was recorded while pump rotational speed, vibration levels, liquid temperature, and other critical test parameters were closely monitored. During non-cavitation performance testing, system pressure was adjusted to Figure 1. Typical configuration of an in-tank LNG cryogenic pump. maintain at least 5˚ of sub-cooling at pump suction to prevent any vapour formation. Pump efficiency was calculated based on the Table 1. Specifications of the original and new inducer design recorded hydraulic output power based on flow and head, and measured Constant pitch inducer Variable pitch inducer electrical input power to the pump assembly considering the Rotational speed 3000 RPM 3000 RPM motor efficiency.

Rated volumetric flow (Q) 238.5 m3/hr (1050 US GPM) 238.5 m3/hr (1050 US GPM) Each pump was tested to determine the NPSH3 level according Blade count (n) 2 3 to API 610 guidelines. Pumps were adjusted to operate at the desired flow Tip diameter (Dt) 196.8 mm (7.75 in.)

196.8 mm (7.75 in.) rate with sufficient suction head at 38 mm (1.5 in.) at suction; Hub diameter (d) 70 mm (2.76 in.) saturation temperature, and the 70 mm (2.76 in.) at discharge suction head was reduced by adjusting 7˚ at suction; Blade angle at tip diameter (β) 8.9˚ the test tank liquid level.

11˚ at discharge During cavitation performance Pitch (p) 100 mm (3.94 in.)/360˚ rotation Variable pitch testing, liquid temperature and pump pressure was recorded and monitored Blade chord length (c) 611 mm (24.06 in.)

523 mm (20.54 in.) at pump suction and discharge, along with the liquid level of the test tank.

While the liquid level (suction head) Table 2. Boundary conditions and CFD simulation details began to decrease, a computer Total pressure in stationary frame: varied for controlled high-speed data recording Inlet boundary condition cavitation simulations system continued to save test parameters until the pump differential Outlet boundary condition Mass flow rate: Varied for non-cavitation simulations head dropped by 45% (55% of head Fluid Propane at -45˚C (-49˚F) with Pvap = 89051 Pa (12.92 psi) without presence of cavitation). Since the test liquid is a hydrocarbon with a Rational speed 3000 RPM (applicable to inducer and impeller) considerable amount of compressibility, and with relatively less density with Interface model between rotating Multi frame of reference and stationary components respect to water, operating the pump with vapour formation was not a Analysis type RANS steady state with ‘false’ time scale concern during testing. Liquid height from the inducer centreline at 3% head Turbulence model k-ε turbulence model drop was reported as the NPSH3 of the Homogeneous model (equal temperature, full pump assembly. NPSH3 is also Multiphase fluid model equal velocity) known as the NPSHr. A head drop curve for each pump assembly was Heat transfer Isothermal at -45˚C (-49˚F) plotted to determine the exact liquid Cavitation model according to described mass height from the inducer centreline that Fluid pair mass transfer option transfer equations corresponds to a 3% head drop.

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Results

CFD simulation results for the constant pitch pump under normal operating conditions, and without the presence of cavitation, were compared to the non-cavitation performance test results to identify if the assumptions and boundary conditions had any impact on the accuracy of the calculations. For this purpose, CFD simulation results in terms of pump differential head and hydraulic efficiency versus volumetric flow rate were overlaid on the pump performance curve of the constant pitch pump assembly.

CFD predictions of the two-stage pump were calculated based on the differential head of each hydraulic component. Two-stage performance is essentially the total differential head produced by the suction stage plus one additional impeller and diffuser vane differential head.

CFD simulations and pump performance of the pump with variable pitch inducer were compared to actual pump performance under non-cavitation conditions. The purpose of this comparison was not only to validate the CFD predictions, but to also compare the actual test results of the pump assembly with constant pitch inducer to the pump assembly with variable pitch inducer under non-cavitation conditions. Results indicate that the head change between the constant pitch inducer and the variable pitch inducer is insignificant with respect to two-stage total head of the impeller and diffuser vane (Figure 2).

Cavitation performance of the pump assembly with constant pitch inducer and variable pitch inducer are reported in terms of NPSH3 of the full pump assembly. During NPSH testing, pumps are tested at various flow points to determine corresponding NPSH3.

Computer simulations are run at rated flow (238.5 m3/hr, 1050 GPM) to determine the NPSH3 at rated flow only. This is

mainly because API 610 requires that NPSH3 cavitation performance is met at rated flow, and cavitation behaviour of the pump assembly at other flow points are for reference only.

Head drop curves with the constant pitch inducer and the variable pitch inducer are plotted to identify any cavitation performance improvements according to CFD results. Figure 3 is the CFD head drop curve of each configuration of the pump assembly. NPSH3 improvement from 1.3 m to 0.96 m (4.27 ft to 3.15 ft) is predicted by CFD simulations at rated flow.

This corresponds to an NPSH3 improvement of 26% at rated flow (Figure 3).

In addition to the CFD NPSH3 prediction, vapour formation in terms of vapour volume fraction at the inducer and impeller blades was investigated. Figure 4 shows the vapour volume fraction at the inducer and impeller under suction head of 1.12 m (3.67 ft). This point is identified as ‘A’ in Figure 3, CFD head drop curve. As shown in Figure 4, the pump assembly with constant pitch inducer had a considerable amount of vapour formation at the inducer, and the vapour further propagated to the impeller suction side, causing a breakdown in pump discharge. Under this suction head, the pump differential pressure dropped to 66% of its original value. Under the same suction head, the pump assembly with the variable pitch inducer had some degree of vapour formation at the inducer; however, there is no evidence of vapour at the impeller eye. With the variable pitch inducer, the constant pitch pump differential head is maintained (100%) regardless of vapour formation at the inducer section (cavitation inception).

Cavitation performance test results are shown in Figure 5. The NPSH3 improvement in terms of cavitation performance between the two inducers is 25%, which is similar to the CFD

simulation results. As tested, suction specific speeds are reported to be 46 280 and 36 875, respectively. There is a discrepancy of 15 – 17% between the CFD simulation results and the performance test results, which can be attributed to the complexity and accuracy of both simulations and testing.

Conclusions

Figure 2. Performance curve of pump with constant pitch inducer as tested vs variable pitch inducer. CFD predictions.

Figure 3. CFD head drop curves of both pump assemblies at rated flow.

According to the results under non-cavitation conditions, the CFD simulations closely predict the actual pump performance for both configurations of the pump assembly.

Due to the insignificant relative head increase between each inducer with respect to total head produced by impellers and diffuser vanes, there is minimal change to pump performance under non-cavitation conditions between each pump configuration.

Cavitation performance in terms of NPSH3 is improved by approximately 25% at rated flow by the variable pitch inducer which is designed with consideration of pump operating conditions and impeller eye geometry to attain good NPSH3 performance.

The complete pump assembly (inducer, impeller, and diffuser vane) is included in the simulations since NPSH3 cavitation performance is defined as the NPSHa value when pump’s differential head is dropped by 3%. It is observed that cavitation volumes at inducer locations do not necessary result in the pump head drop to NPSH3 level unless the vapour formation propagates to the impeller eye section.

Therefore, it is highly recommended to model at least the first stage (suction stage) to determine the true cavitation performance.

Finally, a secondary finding of the analysis is that vapour formation in the impeller eye section negatively influences NPSH3 performance. This suggests that future research and analysis to optimise impeller vane geometry with the variable pitch inducer could further improve NPSH3 performance.

Bibliography Figure 4. Vapour volume fraction at inducer and impeller blades at rated flow, NPSHa = 1.12 m, Point A.

1. KARAKAS, E. S., and MOLLATH, R., ‘Cavitation Performance Improvement of an Industrial Cryogenic Centrifugal Pump by Implementing Variable Pitch Inducer’, Turbomachinery and Pump Symposia, (2021).

2. JAKOBSEN, J. K., ‘Liquid rocket engine turbopump inducers’, NASA Technical Report, SP-842 8052, (May 1971).

3. SCHEER, D. D., HUPPERT, M. C., VITERI, F., and FARQUHAR, J., ‘Liquid rocket engine axial-flow turbopumps’, NASA Technical Report, SP-8125, (April 1978).

4. JAPIKSE, D., MARSCHER, W., and FURST, R., ‘Centrifugal Pump Design and Performance’, Concepts ETI, Inc., (1997).

5. BRENNEN, C. E., Cavitation and Bubble Dynamics, (1995).

6. BRENNEN, C. E., ‘Hydrodynamics of Pumps’, Concepts ETI, Inc., (1994).

7. PLESSET, M. S., ‘The Dynamics of Cavitation Bubbles’, Journal of Applied Mechanics, Vol. 16, pp. 277 – 282, (1949).

8. ZWART, P. J., GERBER, A. G., and BELAMRIi T., ‘A Two-phase Flow Model for Predicting Cavitation Dynamics’, International Conference on Multiphase Flow, Paper No. 152, (2004).

9. MAIN, K. V., CERVONE, A., and HICKEY, J-P., ‘Turbulence Modeling of Cavitating Flows in Liquid Rocket Turbopumps’, Journal of Fluids Engineering, Vol. 139, (2017).

Figure 5. Head drop curves of pump assemblies as tested at rated flow.

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10. NIST Chemistry Web Book, SRD 69, http://webbook.nist. gov/chemistry/fluid/ 11. ‘Centrifugal Pumps for Petroleum, Petrochemical and Natural Gas Industries’, API STD 610 11th Edition.

LNG Industry magazine

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Register for your free subscription at: www.lngindustry.com

Karthik Sathyamoorthy, President, AG&P LNG Terminals & Logistics, analyses how small scale LNG technologies and transportation models are shaping the future of natural gas, whilst providing emerging countries with an uninterrupted supply of clean energy.

N

atural gas is one of the most promising energy fuels due to its environmental qualities and economic viability. The global gas supply industry is shifting, with the spotlight on decarbonisation goals and the availability of alternative resources. Companies need to amend their business models to pivot to a carbon-neutral world and realise that innovations and technology are crucial to delivering valuable changes.

The LNG industry is becoming increasingly diverse and dynamic. Despite price volatility, the recent increase in demand trends suggested that developing nations, such as the Philippines, Bangladesh, and Pakistan, will play a significant role in LNG growth compared to historically well-known buyers, such as Japan, South Korea, and Taiwan. This means that small scale, modular, and floating technologies are shaping the future of the LNG market – one that is flexible, scaleable, and accessible.

The adoption of small scale LNG through small scale carriers and ISO containers is significantly increasing, with China and Europe as major users of these types of infrastructure. The industry is also developing in emerging countries such as India and Thailand, which seek to provide uninterrupted and clean energy in the form of natural gas to thousands of citizens in their domestic market right to their doorstep, even in the most landlocked areas.

City gas distribution processes

To take India as an example, the Ministry of Petroleum and Natural Gas has laid a plan to expand the city gas distribution (CGD) networks across the country for gas access to at least 70% of the population, covering over 407 districts. The CGD companies in India are expected to invest up to Rs 120 000 crore (approximately US$14 billion) over the next 10 years.

AG&P, developer, owner, and operator of downstream LNG/natural gas ecosystem, captured the opportunities that carrying out gas distribution in India has to offer – to bring LNG in affordable and smaller volumes to minor markets, which are the non-traditional, more dispersed off-grid customers.

Today, over 200 compressed natural gas (CNG) stations are being commissioned across five states of India for the automobile industry’s fast-fill and time-fill, ensuring a limited emission of pollutants in the air. Over 200 000 households benefit from stable and reliable power supplies through the last-mile infrastructure, which includes laying more than 1000 km of pipelines to each end-user. AG&P employs a hybrid methodology in serving its customers effectively, covering the last mile delivery by utilising robust customer-specific solutions and varied modes of gas transportation, such as trucking services that transport LNG to factories and central depots where gas is transferred into local, regional pipe networks, and smaller trucks to supply cascades to disparate smaller pockets of commercial customers with limited pipeline access.

Over the next 10 years, more than 28 districts and approximately 80 million people in India will benefit from the clean, affordable, and safe

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Figure 1. AG&P is readying its 5 million tpy Philippines LNG for commissioning to supply gas to one of the largest power producers in the country.

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fuel with the development of 1500 CNG stations to serve vehicles to transition and operate on clean fuel seamlessly and 17 000 km of pipeline connecting over 10 million households.

Plug and play

Another key feature of small scale projects is their decentralised nature. Due to its scaleability and flexibility of delivery methods, gas has development prospects in almost any region, urban or rural. To determine the feasibility and effectiveness of small scale LNG projects, it is reasonable to consider existing supply systems, regulatory policies, individual market intricacies and preferences.

Small scale LNG is suitable for economies with smaller and unpredictable demand, scattered demand centres, lack of delivery infrastructure, short implementation timelines, and/or financial constraints. Infrastructure requirements for these projects can be fulfilled through options such as FSUs with regasification equipment, FSRUs, small scale vessels, ISO tanks/ISO containers and others.

Expanded services

This is the case with Senegal, which converted a Moss LNG carriers to the world’s first modular (M-FSRU) to accelerate the launch of a gas-based economy in order to cater to a growing population and a goal to phase out heavy fuel oil by 2025. Gas Entec, a subsidiary of AG&P, completed the conversion of the 125 000 m3 LNG carriers for KARMOL, a joint venture between Turkey’s Karpowership and Japan’s Mitsui OSK Lines.

The vessel was equipped with two units of a combined regasification capacity of 84 million ft3/d. It was connected to Karadeniz Powership Aysegul Sultan in Dakar, which enabled the 114 MW floating power plant to scale gas up and down (from 15 million ft3/d to 300 million ft3/d), depending on the fluctuating demand of the region. The M-FSRU will also serve smaller shore-based grids in Senegal.

Natural gas can also be transferred from large gas carriers to smaller vessels to distribute gas to smaller ports with a shallow draft, limiting the size of ships it can harbour. The use of small gas tankers for distribution to remote areas has great potential to contribute to emerging gas markets with limited port conditions. Many countries, such as the Philippines and Indonesia, are using smaller vessels for gas distribution across these archipelagos that lack available infrastructure and access to the shore.

As the next step, AG&P plans to commission small scale vessels to reach these locations, which aligns with its aim of ensuring that uninterrupted clean energy is distributed to the most inaccessible places.

AG&P is also working on expanding into the Philippines’ CGD network and is in conversation with various government bodies for the transmission, distribution, and supply of natural gas in landlocked areas, which will eventually serve natural gas to the whole of the Philippines.

Case study: the Philippines

The takeaway

Case study: Senegal

In the Philippines, AG&P is commissioning the first hybrid onshore and offshore terminal at Batangas Bay that will come into operation at the end of 1Q23 with an initial capacity of 5 million tpy.

Figure 2. AG&P’s LNG-by-truck delivery service providing

immediate gas supply access to customers not connected to existing gas infrastructure.

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The Philippines is facing a gas supply crisis with domestic production from Malampaya (the country’s sole gas field) declining rapidly, resulting in the necessity for LNG import capacity for energy security in the coming years.

The 5 million tpy terminal comprises two onshore 60 000 m3 onshore tanks and a 137 000 m3 FSU. It will reach full capacity operation in 2025. It will operate on a tolling basis with one of the largest power producers in the country as its first anchor tenant. The terminal’s initial capacity will supply the power producer to meet LNG requirements from transport, industrial, and residential sectors in Luzon, the most populated island in the Philippines.

In addition to ensuring energy security, the terminal is built with a unique hybrid design to accommodate redundancies and ensure that disruption is mitigated from frequent typhoons for seamless gas supply to the domestic market.

November 2022

The small scale LNG sector is small but promising, with a broad potential to be profitable and scaleable. Natural gas demand is likely to multiply, pushed by strict environmental regulations and the industry’s capabilities to unravel new consumers. The challenge is penetrating untapped markets to ensure that clean natural gas reaches each industry or household efficiently. Companies, such as AG&P, benefit from the right strategy, business model, and affiliations across the natural gas value chains in select markets. Through unique technical and commercial solutions and a remarkable safety record, AG&P has established itself as a company fully capable of efficiently delivering natural gas to nascent economies.

More comprehensive research, innovation, and infrastructure development are currently available to promote small scale LNG ecosystems with cost-effective solutions supporting the last mile deliveries while maintaining safety standards.

As the world transitions into a cleaner tomorrow, more stakeholders involved in developing innovative natural gas ecosystems will enable economies to meet their environmental objectives faster, address their energy security concerns and improve millions of lives by providing access to cleaner energy.

Tony Collins, EonCoat, USA, explains how the shift towards sustainability has seen an increase in support for LNG storage assets protected by non-toxic coatings.

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he 21st Century demands solutions that sustainably meet the economic needs of society, but also protect the environment in the face of climate change and pollution. LNG is the right energy solution for an environmentally conscious society: it is the cleanest-burning fossil fuel and has numerous environmental advantages, providing operators a smart, safe, and affordable way to meet regulations.

LNG releases 45 – 50% less carbon dioxide (CO2) than coal, 30% less CO2 than fuel oil, dramatically reduces nitric oxide emissions, does not emit soot, dust, or fumes, and produces insignificant amounts of sulfur dioxide, mercury, and other particulates compared to other fuels.

Safety

LNG is inherently safe because it is not flammable in liquid form.

Another huge safety factor is that LNG vapours are not toxic.

In addition, LNG spills do not damage the waterway or harm aquatic life in any way.

So where do the operators of this safest, cleanest, and most environmentally-friendly fuel turn when they need to protect the steel assets that store and transmit their product? Many of them choose the safest, cleanest, most environmentally-friendly and completely non-toxic coating of chemically bonded phosphate cement that protects steel from corrosion for decades, typically the life of the asset. In addition to being safe and environmentally-friendly, chemically bonded phosphate cements are not flammable – making them even safer for use around fuels.

Cement as coating

So, what are chemically bonded phosphate cements? They are acid/base cements, similar to dental cements, and were pioneered

by Argonne National Labs to shield radioactive waste in the

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mid-1990s. In 2010, while working on cement for structural applications, EonCoat (based in North Carolina, the US), observed that this cement would stop the rusting of carbon steel better than any known protective mechanism – including superior to cathodic protection and all known corrosion coatings.

How can it be that a cement could be so effective? Simple: it has no resin.

Coatings have four things: zz Binder (or resin). zz Pigments. zz Additives. zz Solvents.

This fundamental assumption is why no coating engineer would have considered the technology created by EonCoat.

Technically, chemically bonded phosphate cements are not coatings because they do not have a resin as the binding agent, but rather bond to steel through an acid/base reaction. Oddly, the absence of a resin is exactly why chemically bonded phosphate cements are so effective. Coatings can contain only a limited amount of pigment because of something called critical pigment volume concentration. Exceed this volume percentage and the resin cracks. There is a practical limit of approximately 20% inhibitive pigment in resins. These inhibitors are what enable coatings to prevent corrosion by providing something for steel to bond with. An inhibitor is something that has a lower energy state – called Gibbs energy – when bonding with steel which has lost an electron. In order for steel to protect itself when it loses an electron, it must be offered something with a lower energy state than oxygen. Otherwise, the steel will bond with the oxygen and form rust.

An additional downside of resins is that they are sticky, and the inhibitor must work its way out of that resin to get to the metal where it can protect the steel.

Instead of using a resin, the inhibitors in chemically bonded phosphate cements bond to each other, and to steel, via an acid/base reaction. The cement can be a 100% inhibitive pigment, and this can be bonded chemically to the metal.

Chemically bonded phosphate cements enable a pigment loading five times the maximum loading of inhibitor for most polymers, and an easy way for the pigment to reach the steel because it is chemically bonded with it. There is no resin to impede access to the metal.

Figure 1. Sameer Patel, Lead Scientist in developing

EonCoat, safely applying EonCoat with minimal PPE.

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Why is this important? Corrosion comes down to a simple fact – corrosion is the result of an iron atom losing an electron and bonding with oxygen. Iron will choose what it bonds with based on what creates the lowest energy state and what negatively charged ion is physically closest to it. The goal as corrosion engineers is to provide a large volume of inhibitive pigment – such as phosphates and silicates – that have lower energy states when bonding with iron than oxygen does.

So how much volume is required? If a blasted steel panel is placed in a glass of salt water, it is possible to see the rust begin to form. Once the phosphate ion has been added to the solution, the rate of corrosion slows down when it reaches 0.5 moles of phosphate/l of water. Upon reaching a 1 molar concentration, or practically exceeding the molar concentration of the salt, the rust will completely stop. With a chemically bonded phosphate cement, it is possible to reach a 4 moles/l concentration at the coating/metal interface. At that concentration, rust is just not possible. Embedding inhibitors in a resin limits the molar concentration to well under 0.5%. This is the inherent limitation of polymer technology. It is not possible to get enough ammunition to the battlefield.

Applications of the coating

Within a year of discovery of the corrosion resistance, EonCoat had figured out how to spray the cement like a coating. Shortly after, the first large oil company began using EonCoat to protect tanks.

Today, many energy companies across the globe use EonCoat on tanks, pipelines, and offshore platforms. This protection mechanism is not only 100% effective, even in corrosive environments, but enough phosphate can be added to last the life of the asset.

Over time, two new coatings have been developed using similar chemistry. In 2015, a high-temperature product was developed that is primarily used for corrosion-under-insulation.

And most recently, EonCoat developed the weldable tank bottom coating – soil facing side. This product will not burn or otherwise be compromised when the tank plate it is on is welded from the other side. Customers use this coating to protect the soil facing side of tank bottoms. No longer will tank bottoms rust out and need to be replaced.

As great as the protection is, perhaps the most significant impact of this technology is that it gets rid of the safety and environmental impacts of polymer coatings. Volatile organic compounds (VOCs) cause so much harm to the health of painters who apply them and to the environment in the form of greenhouse gas. Now it is known that employees who are exposed to VOCs suffer a loss of 10 – 15 points in IQ. The other health hazards are too numerous to list here – but VOCs are likely to be the next asbestos. When the public did not know better, everybody had an excuse, but now the public does know. EonCoat have painters wear a PF-100 mask that filters down to 0.3 µm. The implication is that the staff are safe from toxins, yet painters suffer cognitive decline and a host of unpleasant illnesses that take their lives too soon. The company now knows that VOC molecules, because they are gases, are approximately 1000 times smaller than what the PF-100 filters can capture, with dia. in the scale of picometers. One picometer is a million times smaller than a micrometer. It is a reasonable assumption that PF-100 masks do not adequately capture VOCs. The LNG industry, the beacon of clean and safe fuels, is embracing chemically bonded phosphate cements, the clean and safe way to protect its carbon steel assets. It is a leadership example to all.

Edo Vonk, VSL International, highlights the basic guidelines for inspection and maintenance of pre-stressed concrete tanks for LNG and LPG storage, emphasising the differences between the various systems. he use of pre-stressed concrete containments has proven to be a cost-effective, durable, and safe solution for liquid storage facilities. Their size can range from small (several metres in diameter) to very large (up to 100 m dia.), and their height varies depending on the application.

The basic principle of pre-stressed concrete tanks relies on the tensile strength of steel tendons, which are tensioned against the circular concrete structure. This induces a uniform axial compression into the concrete cross-section under the hoop stresses of the tendon. While concrete itself is a material that exhibits relatively high compressive strength, it does not allow the transfer of significant tensile stresses. Under tensile stresses, the concrete will crack and lose its structural integrity, unless reinforced by steel reinforcement bars, as well as foregoing its leak tightness. Putting the concrete into compression by the use of pre-stressing for all prevailing service load-cases is an elegant solution that has demonstrated its efficiency and reliability for approximately a century.

For LNG and LPG storage tanks, the concrete wall acts (in most cases) as the outer secondary containment designed to react the internal tank pressure in

accidental scenarios only, i.e., after failure of the primary steel alloy containment membrane. In addition, this outer secondary concrete structure provides a robust barrier against external abnormal loads (impact, explosions, etc.) and aggressive environments, in particular where exposed to industrial emissions or chloride-laden marine air. The concrete containment is hence a safety-critical element of any LNG or LPG storage facility, and tank designers, operators, and owners have to ensure that the concrete containment could fulfil its critical role throughout the life of the facility.

Similar to any other pre-stressed concrete applications, in particular bridges, pre-stressing systems require regular inspection and maintenance in order to ensure their integrity throughout the service life of the structure, and the structure can be prone to hidden defects, in particular corrosion of the high tensile steel.

Basic guidelines for inspection and maintenance of pre-stressing systems

In this context, it is important to establish some basic guidance for the inspection and maintenance of pre-stressing systems in LNG and LPG storage tank applications. To the knowledge of the author, such guidelines are currently lacking for LNG and LPG storage tank applications, and it is therefore the objective of this article to present a snapshot of the state-of-the-art in the inspection of pre-stressing systems and discuss its application and relevance in the case of LNG and LPG storage tanks.

Corrosion of high-tensile steel

Pre-stressing systems use very high-strength, cold-drawn steel wires (up to approximately 2000 MPa tensile strength) with low ductility (below 5% elongation at rupture) and small cross-sections (typical wire cross-sections below 10 mm dia.) These steel wires can be potentially prone to failure by corrosion. While corrosion failure mechanisms of conventional structural steel are mainly governed by gradual section loss, the failure mechanism of high-tensile cold-drawn steels are typically controlled

51

by local accelerated corrosion (pit or crevasse corrosion) and subsequent rapid failure under crack propagation or notch effects.

In general, such failures are sudden and characterised by very short advance warning.

Pre-stressing systems

Two distinctively different systems can be found in LNG and LPG storage tanks. The pre-stress is either applied by spirally winding a continuous high-strength steel wire under load around the outer-concrete perimeter (as seen in older generations of pre-stressed concrete tanks) referred to as ‘spiral wrapping system’, or by embedding high-tensile steel strands within reservations (ducts) inside the concrete wall proper referred to as ‘embedded post-tensioning system’. This is in addition to the general circular pre-stressing of the tank wall. Secondary post-tensioning systems might be present in a tank, either in vertical direction, or as concentrated horizontal tendons in the upper ring beam to react to the outwards dome forces of the roof structure.

Differences between the systems

In the context of inspection and maintenance, it is very important to understand the differences in detailing and behaviour of the two systems, as well as the prevailing deterioration mechanisms.

Figure 1. LNG concrete storage tank during construction.

Spiral wrapping systems

After wrapping of the steel wires in a continuous tensioning process, their corrosion protection is achieved by applying a layer of shotcrete (spray-applied cementitious material). The corrosion protection is based on the principle of electro-chemical passivation of the steel surface in the high-alkaline cementitious environment. For long-term corrosion protection, the encapsulation needs to be: (a) continuous, hence it shall be free of voids, (b) largely impermeable, i.e., dense and without larger continuous pores or cracks, and (c) remain at the depth of the steel surface highly alkaline throughout the service life. Several environmental effects can lead to the breakdown of one or several of these characteristics which will lead in turn to local or widespread corrosion of the pre-stressing steel. The two most important mechanisms to cause breakdown of the protective function are concrete carbonation, which leads to a loss of passivity of the steel and chloride-induced corrosion in marine environments. In addition, the presence of sulfates or other pollutants in industrial environments can also lead to accelerated corrosion phenomena.

Carbonation is triggered by the diffusion of carbon dioxide from the atmosphere into the outer concrete layer. This then triggers chemical reactions, lowering the pH value of the cement matrix. Once the carbonation front has reached the embedded pre-stressing steel, the steel’s electrochemical potential becomes more active. This then triggers general surface corrosion, eventually leading to section loss and failure of the steel cross-section. At the same time, the corrosion products are highly expansive, resulting in cracking and spalling of the concrete and ingress of moisture and corrosive substances.

Chloride induced pitting corrosion is caused by the local access of chlorides to the steel surfaces. In the case of storage tanks, the most frequent source of chlorides is airborne chlorides in marine environments deposited at the concrete surface. Even higher deposition rates can be observed where tanks are located close to the seashore in direct marine spray. Chlorides migrate via pores and cracks deep into the concrete and eventually reach the steel surface. This is where they can cause a local breakdown of the passive film which then results in very local and accelerated pitting corrosion.

Failed wires will re-anchor itself by bond in the shotcrete layer to some extent after initial slip so that the first wire breaks might not become immediately visible. More widespread failure will however lead to larger concrete spalling and eventually failure and uncontrolled release of the continuously wound tendons. This bears a significant health and safety risk in normal service conditions in addition to the tank containment losing its safety relevant function.

For spiral wrapping systems, inspection shall hence focus on the depth of carbonation, the presence of chlorides (or other corrosive agents), and the presence of cracks, voids, spalling, or porosity which can all cause early and accelerated corrosion of the post-tensioning system. Wire failures are a pre-cursor of full system failure.

Embedded post-tensioning systems

Figure 2. Corrosion of strands inside a pre-stressed tendon.

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November 2022

These systems consist of a duct embedded into the concrete prior casting, creating a void in which the high-tensile steel tendon can be threaded afterwards. The tendon is made in most cases by a number of prestressing strands, with each strand formed by seven 5 mm dia. wires. The pre-stressing tendons are individually anchored in a steel anchorage block using conical steel wedges.

After tensioning to the targeted force, the pre-stressing tendon is

injected with a cementitious grout, providing passivation of the pre-stressing steel strands and therefore corrosion protection.

While older systems used corrugated, spiral wound steel ducts as void formers, more recent systems use corrugated plastic ducts combined with system couplers to obtain a leak-tight additional barrier. These systems are considered today the state-of-the-art in durability.

The detailing of the concrete storage tank wall is such that embedded post-tensioning tendons have much larger concrete covers than in the case of spiral wrapping system. Consequently, embedded post-tensioning systems are better protected against corrosion induced by external effects. Based on several decades of research and observations in the corrosion of post-tensioning systems in bridges and other concrete structures, it is recognised that there can be other internal mechanisms that can trigger localised corrosion. When the tendons are injected with cementitious grout after stressing, it is possible that air voids get trapped inside and/or that the grout mix segregates as a result of improper detailing, unstable mix design, insufficient mixing, incomplete venting, or issues of general workmanship. Where air voids are present, it has often been found that the remaining oxygen and moisture can be sufficient to cause local corrosion of the exposed pre-stressing steel. This process will be significantly accelerated in the presence of chemically-different segregation products, leading to the formation of local corrosion cells due to a difference of electrochemical potential. It is known from bridges that such failures can occur as early as only a few years after completion or delayed until activated by the access of moisture from the outside.

Any failure of strands will remain hidden as the tendon can re-anchor itself within the corrugated duct. This will, however, still lead to a local loss of pre-stress in the concrete wall and hence a safety risk for the storage tank operation.

Non-destructive testing

Recent years have seen a rapid improvement in non-destructive testing technology applicable to the inspection of a pre-stressed concrete structure to ensure the integrity of a client’s asset is confirmed where the three most suitable are: zz Ground-penetrating radar (GPR) – GPR has established itself as a rapid scanning technique for concrete structures. It can detect changes in material conductivity and hence density.

It is best used to detect voids and areas of delamination while they are still hidden within the structure. Radar signals are, however, being fully reflected by metallic objects and can hence not be used to find voids within metallic post-tensioning ducts. With recent advances of data processing algorithms supported by fundamental research into concrete conductivity, GPR has today been successfully used to also map hot-spots of chloride contamination and moisture. It can therefore be used to detect pathologies in spirally-wound, as well as embedded post-tensioning, systems. Compared to other technologies, such as electrochemical potential mapping, GPR can achieve much higher scanning rates and help to reduce the cost of full tank mapping. zz Ultrasound-pulse echo arrays (UPE) – The integration of pulsed ultrasound measurement principles with a hand-held array of transducers and advanced imaging capability has resulted in powerful equipment for the detection of voids

Figure 3. Sudden failure of a pre-stressing tendon due to corrosion.

Figure 4. Advanced ground-penetrating radar (GPR) map showing increased chloride concentrations.

in concrete and post-tensioning systems. Different to radar, ultrasonic signals travel well through dense materials, such as steel, which allows the detection of voids even within metallic duct systems. As it requires physical coupling, the achievable measurement productivity onsite remains low and UPE should hence remain reserved for local investigations following some initial findings from document studies, visual, or GPR surveys. zz Magnetic flux leakage measurement (MFL) – This is an electromagnetic measurement principle making use of the principle that a sudden reduction in steel cross-section can lead to a leak of an induced magnetic field which can be detected at the concrete surface. The magnetic field is either induced by strong electro- or permanent magnets, and the flux is measured by set of coils. The testing unit needs to be moved along the tendon, and gets typically mounted on a rail system for quick scanning and efficient handling. MFL is the most suitable method to find wire breaks.

The combination of advanced non-destructive testing methods with engineering review of existing tank documentation and environmental conditions, periodic visual inspection, and limited intrusive material sampling are the prerequisite to keep ageing pre-stressed LNG and LPG storage tanks remain in safe state. The interpretation of results requires the implication of necessary experts in pre-stressing systems to derive relevant conclusions for any maintenance, repair, or strengthening measures.

November 2022

53

Romuald Machac, Hutchinson, South Korea, outlines high-performance solutions for the LNG industry in terms of insulation, protection, and barriers.

T

he global situation and the evolution of hydrocarbon consumption targets are forcing the world to think about new energy import solutions.

LNG is representing a sustainable solution to gradually replace the 150 billion m3 of gas concerned by restrictions. Indeed, LNG will be transported from different parts of the world by ship.

Under the current situation, everybody understands the importance of LNG to be, or to become, the dominant source of energy for most of the countries around the world.

LNG will also be the preferred fuel for many modes of transportation, especially for the shipping industry.

Hutchinson®, as a subsidiary of TotalEnergies, with 40 000 employees spread in 25 countries, designs and manufactures solutions that guarantee safety and energy performance in the most demanding markets: automotive, aerospace, energy, rail, and various other industries.

Hutchinson – Precision Sealing Systems produces foam, sealing systems, protection, and insulation solutions for structures in contact with LNG.

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A secondary barrier

Triplex® is a composite membrane that is LNG-tight at -170˚C. It is being used as the secondary barrier for Mark III cryogenic containment systems designed by the French company, GTT. To transport or store 600 times more energy within the same volume, the natural gas is being liquefied to reduce its volume. To convert natural gas into LNG, it must be cooled down to the cryogenic temperature of -162˚C. This cryogenic temperature brings along technical challenges for which Hutchinson has designed a full product range.

Specifically focusing on LNG storage and transportation, Hutchinson has been supplying Triplex for approximately 30 years, with most of the active large LNG carrier fleet fitted with Triplex.

Today’s large-capacity LNG carriers, consisting of four tanks with a total transport volume of approximately 175 000 m3 of LNG, require perfect insulation and sealing of the two containment barriers.

Triplex is certified by all classification societies. It is fitted mostly on large LNG carriers, but is also used on onshore storage tanks, fuel tanks, bunkering vessels, floating LNGs (FLNGs), and FSRUs. It ensures the sealing of the secondary barrier, securing the LNG tanks of more than one-third of the world’s LNG carriers.

Triplex-F is flexible, not only during normal operation, which is approximately -100˚C, but also in the event of a problem on the primary barrier, when it will be at -162˚C and in direct contact with LNG. This flexibility allows it to absorb the thermal contractions of the LNG tanks, as well as the deformations at sea of the vessel’s structure.

Triplex-R is rigid and directly bonded on R-PUF foam/panels.

When erecting the LNG tank, the Triplex-F is bonded between panels directly on the Triplex-R for a secure sealing.

Although the market is historically located in South Korea, it is expanding rapidly in other geographical areas, such as Europe and China. To meet this growing global demand, Hutchinson has started to distribute Triplex in these countries, especially in China, which will soon become the largest LNG importer.

Protection for facilities

Zaltex® is a solution for passive fire protection (PFP) and cryogenic spillage protection (CSP) hazards on facilities to ensure safety for workers, structures, and equipment.

It is a basalt-based composite foam panel that was designed for cryogenic protection against accidental LNG spills for onshore and offshore structures requiring high mechanical strength and insulation. Fully customisable, Zaltex can be used in LNG plants, chemical equipment, drilling/production facilities, storage, or transportation. Zaltex has been specially designed to withstand multiple cryogenic shocks without its structure being altered.

Hutchinson has developed the Zaltex panel for 2 hrs resistance as CSP and PFP protection.

Depending on the protection requirements from customers/projects, Zaltex can be adapted to meet specific demands, such as the protection duration or the mechanical

stress by adjusting its thickness and density. A higher density of Zaltex improves the mechanical resistance, and conversely a lower density increases the panel insulation capacity and therefore the protection time. It is possible to combine different layers of different densities to match exact requirements.

With optimal mechanical properties, a resistance to compression higher than 10 MPa, Zaltex is robust in time even if it is subjected to multiple maintenance operations.

Zaltex also helps to save money during the installation process by eliminating the major constraints associated with paint application.

Zaltex protection can be installed without any climatic constraints (e.g. rain, snow, and humidity), and from temperatures below -40˚C to above 50˚C. Since Zaltex is laid like parquet, the financial gains during the installation are also made on the reduction of the immobilisation time of the surface to protect. Zaltex can be installed in only a few hours and does not require specific training. The cutting can be done with simple tools usually used for wood. There is only the need of a Hutchinson supervisor to check and manage the working process.

As part of a strategy of continuous improvement and simultaneous engineering, Zaltex has successfully obtained several certifications that confirm its ability to fully meet the requirements of the LNG market: � Certification: Cryogenic pool test – ISO 20088-1/ISO standard target of 2 hrs at -40˚C. � Certification: JetCryo – ISO 20088.

The multiple uses of foam

Experts in rubber since 1853, Hutchinson also designs and manufactures a full range of ethylene, propylene, diene, monomer rubber (EPDM) foams under the brand name Bulatex®.

From very soft to hard, Bulatex exists in both closed and open cells. It is a solution adaptable for all needs: shock absorption, anti-vibration, wedging, sealing (air, liquids, dust), acoustic insulation, noise, vibration, and hardness (NVH), and thermal insulation (i.e., cryogenic temperatures).

The closed cell foams guarantee a secure sealing at low compression, and the open cell foams – or sponge foams – ensure sealing while adapting to all geometries (shape defects, large tolerances, etc.) due to their high compression capacity.

Bulatex foams are also fire resistant and compatible with FMVSS 302 certification. � Densities from 50 – 750 kg/m3. � Load-bearing capacities from 2 – 1500 kPa. � Thermal conductivity from 0.035 W/m˚C . � Hardness from 55 Sh00 to 50 ShA. � Temperature: from -50˚C to 150˚C. � Options: fitted with adhesives (transfer, non-woven, mesh, hot-melt).

Other materials for foam cell converting: polyurethane (polyester and polyether), polyethylene, PVC, rubber (open and closed cell), felt, and felttrine and airbag net.

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to custom-made parts, such as complete seats, balls, and components kits. Different parts are machined to ensure a good fit of the components for an optimal sealing of the valve. Due to its experience, the company offers solutions adapted to most specific customer needs in terms of size, resistance to extreme temperatures, pressure, and abrasive and corrosive fluids. zz Design – FEA 2D-3D: To simulate and predict behaviour under pressure and temperature, and patented seats designs.

Figure 1. Gas Vitality. Image courtesy of TotalEnergies.

zz Machining capabilities: In-house production process through CNC machines from 0.25 in. up to 72 in. zz Control systems: CMM, ZEISS, DEA measuring machine, RGD test bench (for valve up to 1000 bars), internal polymeric material characterisation (traction, hardness, and compression test) also at cryogenic temperatures, roughness tester with mobile probe. zz Surface treatments: Electroless nickel plating and nano nickel silicon carbide, surface hardening coatings such as TCC, CCC, and stellite, cladding materials: nickel alloy (Inconel 625), stainless steel (F316), and internal lapping processes to ensure secure sealing between ball and seats.

The company’s objective is to provide infrastructures with thermal insulation, protection, and barrier against fire and/or cold, rapid installation in all conditions, and solid mechanical properties.

With products offering thermal protection, mechanical resistance, and safety, Hutchinson effectively meets the ever-growing needs of the LNG market and contributes to its development as a greener, safer, and more economical energy source.

Figure 2. Triplex-R and Triplex-F.

Valve components for cryogenics

To increase the safety of energy production, Hutchinson offers a wide range of valve components, from standard parts

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22nd World LNG Summit & Awards

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LNG Industry is audited by the Audit Bureau of Circulations (ABC).

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29 November – 2 December 2022 Grand Hyatt Athens, Greece

THE MEETING PLACE FOR THE GLOBAL LNG INDUSTRY SCAN HERE TO REGISTER

DISTINGUISHED SPEAKERS INCLUDE

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Maria Rita Galli

Hiroki Sato

Martin Houston

Minister of the Environment & Energy Greece

Senior Management Executive Officer & Division CEO, Global Business Division Chubu Electric Power Co., Inc.

Octávio Simões President & Chief Executive Officer Tellurian Inc.

Maria Spyraki

CEO DESFA

Philip Mshelbila

Vice Chairman Tellurian Inc.

Spyros Leoussis

Kunio Nohata

Akshay Kumar Singh MD & CEO Petronet LNG Ltd

Executive Vice President & Chief Commercial Officer Cheniere

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Denitsa Zlateva

Constantinos Papalucas

MEP European Parliament

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Chief Commercial Officer Capital Product Partners LP

Steve Hill

Executive Vice President Shell Energy

President and CEO Tokyo Gas Network Co., Ltd

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Jonty Shepard

VP of Global LNG Trading & Origination bp

Executive Director Bulgargaz

Maria De Renzis Executive Growth & Strategy Director Baker Hughes

Anatol Feygin

Coordinator of the National Hydrogen Committee Hellenic Ministry of Environment and Energy

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Global Head of LNG RWE Supply & Trading

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THE FUTURE IN FOCUS

The Net Zero Navigator is a conceptual liquid hydrogen carrier that uses NASA-inspired technologies to eliminate greenhouse gas emissions.

By supporting advanced vessel concepts like this, ABS is pioneering the maritime energy transition.

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