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ISSN 1747-1826

CONTENTS 03 Comment

NOVEMBER 2021

31 Stay ahead of the game

Jim Chappell, AVEVA, USA, explains why digital twin technology can be a game changer when it comes to maximising LNG operations and boosting plant profitability.

04 LNG news

36 Keeping Europe supplied

10 LNG through Russia's eyes

AlexanderbKlimentyev, Inna Kirilkina, AminabTalipova, and JinsokbSung, RussianbSmall andbMid-scale LNGbResearchbGroup, Russia, outline Russia’s LNG industry, including its main producers, plants, and the wider LNG market.

Cedric Vandenbroucke, Dunkerque LNG, France, details the truck loading services available at the Dunkirk LNG terminal.

41 Monitor the deliveries

Prasanth Sreekumar (UAE), Scott Sutherland (USA), and Stephan Natter (Switzerland), Endress+Hauser, explain why the bunkering industry is deploying mass flowmeters to improve efficiency.

44 Singapore: an LNG hub

Capt Daknash Gansen, Senior Director (Operations & Marine Services) of the Maritime and Port of Authority of Singapore, Singapore, details the country’s development as a sustainable global hub port that champions LNG bunkering.

47 Run like clockwork

10 17 A coating shield

Richard Holliday, PPG Protective and Marine Coatings, UK, outlines a detailed test undertaken to compare epoxy passive fire protection products commonly specified for the protection of steel structures.

Michael Hastings, Brüel & Kjær Vibro, Denmark, explains how early detection and diagnostics of bearing manufacturing faults and improperly assembled gearboxes is vital for the smooth running of critical machines at LNG plants.

51 It's all algorithms

Roman Bershader, Independent Compressor Consultant, USA, details the best practices for compressor surge and choke protection in the LNG industry.

56 15 facts on... Russia

23 Take a look at the he tank

Chris Magruder, Olympus, USA, describes bes the recent advances in phased array inspection for LNG tank fabrication.

26 At one with the technology Vincent Higgins and Christian Salazar, Honeywell Process Solutions, USA, explain how advanced technology addresses skills requirements for LNG operating personnel.

ON THIS MONTH’S CO COVER Uniper is an international energy company with w wit h approximately 12 000 emplo employees in more m ore than 40 countries. The comp company plans to m to make ake its power generation CO2-neutral in Europe Eu urope by 2035. It main activities include power g Its generation in Europe and Russia as well as gl global commodity trading, including a div diversified gas portfolio that makes Uniper one o of Europe’s leading gas companies. The company is headquartered in Düsseldorf and is currently the third-largest li listed German utility. www.uniper.energy

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Copyright Copy C Co opy o p right © Palladian Publications Ltd 2021. All rights reserved. No part of tthis hi h 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 rrespective i 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.

LYDIA WOELLWARTH EDITOR

COMMENT T

he phrase on everyone’s lips, and filling the subject lines of most emails in my inbox, is COP26. This iconic climate conference has only been underway for several days, but already we have heard some remarkable statements and collaborative strategies, and the LNG industry is not out of reach of numerous initiatives. For those that have managed to avoid all news of COP26, this is a UN Climate Change Conference, held this year in Glasgow, Scotland, where world leaders are gathering to pool ideas and present creative ways to actively reduce carbon emissions in line with the Paris Climate Agreement goals. There was no need to continue the virtual attendance similar to recent conferences and events, to arrive at COP26 many world leaders and dignitaries chose to arrive by private jet – 400 in fact. This use of transportation emitted as much carbon dioxide as 1600 Scottish people do in a year. So, the event was not off to a particularly green start. Skipping from aeroplanes to boats – the role of the shipping industry has become one of the topics of discussion at COP26, with further focus expected in the coming days. 14 of the world’s nations have taken action to decarbonise the maritime sector, having signed the ‘Declaration on Zero Emission Shipping by 2050.’ Major shipping nations are involved, including the UK, US, Denmark, Germany, France, and Norway, as well as other noticeable players in Belgium, Finland, Honduras, Hungary, Iceland, the Marshall Islands, Panama, and Sweden. This shipping declaration essentially sets up a discussion for the International Maritime Organization’s (IMO) Marine Environment Protection Committee gathering which takes place in several weeks. By signing the declaration, the countries “commit to strengthen global efforts to achieve zero emissions from

international shipping by 2050. In that regard, pledge to work at IMO to adopt such a goal, to adopt goals for 2030 and 2040 that place the sector on a pathway to full decarbonisation by 2050, and to adopt the measures to help achieve these goals.” The IMO’s current target is a minimum 50% cut in emissions by 2050 compared to 2008 levels, so this new direction would be a significant step up. Another global pledge decided at COP26 that will indirectly affect the LNG industry regards the issue of methane emissions. US President Joe Biden and European Commission President Ursula von der Leyen led the initiative, which aims to achieve a 30% reduction in methane emissions by 2030 compared to 2020 quantities. More than 100 countries have come onboard with this goal, however the major emitters of India, China, and Russia, have chosen not to be involved. Studies have shown that methane is a more powerful contributor to global warming (as a warming agent) than carbon dioxide, thus cutting its emissions in line with the agreement will assist the world in avoiding 0.3˚C of warming by 2040. Methane slip has been an issue of concern for a while, particularly as the shipping industry moves in the direction of LNG. Like most things in life, there are critics and sceptics and supporters. Some groups say that LNG should not be pursued by the shipping industry, and instead should look to alternatives such as ammonia and hydrogen. On the other hand, some organisations are proving that progress is underway in reducing emissions from LNG-fuelled ships, so there should be less concern. With numerous days of COP26 still to go, keep an eye on LNG Industry’s website to stay aware of the latest developments and new declarations that will impact the sector.

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LNGNEWS South Korea Mexico

MPL, ConocoPhillips, and Bechtel collaborate on lowcarbon LNG

exico Pacific Limited LLC (MPL), developer of a North American LNG export project (MPL LNG Project) based in Puerto Libertad, Sonora, Mexico, has announced that it has entered into a collaboration agreement with ConocoPhillips LNG Licensing LLC and Bechtel, working with Techint S.A. de C.V., to advance the global energy transition and to assist in lowering greenhouse gas (GHG) emissions by pursuing lower-carbon LNG design solutions for the future phases of the MPL LNG Project. The MPL LNG Project was chosen as the greenfield project for this world-class initiative. The MPL LNG Project’s strategic location on the West Coast of Mexico will, by itself, result in lower GHG emissions due to shorter transit to Asian markets as compared to many other Gulf of Mexico and Pacific Basin LNG producers in addition to lower GHG emissions resulting from the use of leading technologies. The collaboration will seek to further reduce baseline emissions by exploring energy transition and GHG emission reduction technologies developed by ConocoPhillips LNG Licensing and designed by Bechtel in a cost-efficient and competitive manner. This collaborative relationship brings together LNG industry market leaders in technology, design, construction, and operation of LNG facilities to leverage one of the most advantaged and competitive North American greenfield projects as a catalyst for the future of low-carbon LNG production.

Nakilat takes delivery and management of third LNG carrier new-build

akilat has taken delivery of a new-build LNG carrier, Global Sea Spirit, which will be commercially and technically managed in-house by Nakilat Shipping Qatar Limited (NSQL). Built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea, this is the third of four LNG new-build carriers to be delivered to Global Shipping Co. Ltd, a joint venture between Nakilat (60%) and Maran Ventures Inc. (40%). The first two LNG carrier new-builds (ME-GI type) were delivered in May 2020 and January 2021 respectively and are currently in service. With a cargo carrying capacity of 174 000 m3, Global Sea Spirit is the first vessel with X-DF propulsion to join the Nakilat fleet, with the second new-build (also with X-DF propulsion) expected to be delivered early next year. Like the ME-GI system, vessels running with X-DF engines propulsion are proven to be more fuel efficient, reduce greenhouse emissions, and be more environmentally friendly due to their low carbon emission. Similar to the rest of Nakilat’s fleet, the new-build fully complies with all mandatory international and national regulations pertaining to environmental protection. They also have significantly lower boil-off rates, and are equipped with onboard reliquefaction units, thus providing greater operational flexibility for charterers. Global Sea Spirit is chartered to Cheniere Marketing International LLP. The delivery of all four new-build LNG carriers by 2022 will bring Nakilat’s fleet to 74 vessels, which is just under 12% of the current global LNG fleet based on carrying capacity. To date, there are 24 LNG carriers, four LPG carriers, and one FSRU vessel being managed and operated in-house by NSQL.

USA

Cheniere and Glencore sign long-term LNG SPA

heniere Energy, Inc. has announced that its subsidiary, Cheniere Marketing, LLC, has entered into a binding LNG Sales and Purchase Agreement (SPA) with a subsidiary of Glencore plc. Under the SPA, Glencore has agreed to purchase approximately 0.8 million tpy of LNG from Cheniere Marketing on a free-on-board basis for a term of approximately 13 years beginning in April 2023. The purchase price for LNG under the SPA is indexed to Henry Hub, plus a fixed liquefaction fee. Jack Fusco, Cheniere’s President and CEO, “This agreement once again reinforces Cheniere’s position as a leading global

November 2021

LNG provider, and we look forward to a successful long-term relationship with Glencore. This SPA further builds upon Cheniere’s commercial momentum, marking another important milestone in contracting our LNG capacity ahead of a Financial Investment Decision (FID) of Corpus Christi Stage 3, which we expect to occur next year.” The Corpus Christi Stage 3 project is being developed to include up to seven mid scale liquefaction trains with a total expected nominal production capacity of approximately 10bmillion tpy. It has received all necessary regulatory approvals.

LNGNEWS Malaysia

EIG to acquire interest in APLNG

Avenir LNG and LIQUIND Marine team up for shipto-ship bunkering

Australia

IG has announced that it has entered into a definitive agreement under which it will acquire a 10% interest in Australia Pacific LNG Pty Limited (APLNG) from Origin Energy Limited for an equity purchase price of US$1.592bbillion. This innovative agreement represents the first ever acquisition of an interest in an operational integrated LNG project by a private equity sponsor. A tier-one, integrated LNG project with an established liquefaction facility, APLNG is the one of the largest LNG projects by liquefaction capacity on Australia’s eastern seaboard and a major supplier of LNG to Asia and gas to Australia’s domestic market. The project, which is located in Gladstone, Queensland, Australia, has a track record of consistently achieving its nameplate capacity of 9.0bmillionbtpy and holds a leading acreage position spanning the prolific Surat and Bowen basins, providing long-life reserves. The project operates at globally competitive breakeven costs and is well positioned to meet growing LNG demand in the Asia-Pacific region. The project is operated by ConocoPhillips (downstream operator) and Origin Energy (upstream operator) and maintains long-dated LNG contracts with two investment grade counterparties, Sinopec and Kansai Electric. Over the last 15 years, EIG has invested in nine separate LNG projects located in six countries, and this acquisition represents a continuation of its strategy to gain exposure to high-quality LNG assets. The acquisition also builds on EIG’s investment presence in Australia and provides EIG with a platform for future growth in global LNG. R. Blair Thomas, Chairman and CEO of EIG, said, “This is a groundbreaking transaction that reflects our strong confidence in the asset, our partners, and the importance of LNG as a critical enabler of the energy transition. The transaction leverages EIG’s extensive experience in global LNG to deliver an attractive, steady stream of cash flows for our investors.” The transaction has received approval from the Australian Foreign Investment Review Board and is subject to the waiving of pre-emptive rights by ConocoPhillips and Sinopec, as well as other customary completion conditions. Morgan Stanley acted as EIG’s financial advisor in connection with this transaction and Allens Linklaters and Latham & Watkins acted as legal advisors.

November 2021

n Friday 22 October, MT Tosca conducted its first LNG ship-to-ship operation at the anchorage area of Pengerang in Malaysia. The 7000 DWT product tanker is currently on its maiden voyage from Shanghai to Europe and the first vessel in the GEFO fleet that is equipped with a dual-fuel engine. For the organisation of the bunkering operation, GEFO engaged the small scale LNG suppliers Avenir Supply & Trading and LIQUIND Marine. The companies joined forces and contracted the small scale LNG bunker supply and delivery by utilising the Avenir Advantage 7500 m3 LNG bunker vessel, which is owned by Avenir and commercially operated by Petronas. The operation was the first collaboration for the companies and demonstrates the ability to flexibly supply LNG as a marine fuel globally, utilising Avenir’s LNG bunker vessels which are strategically located across key trade lanes. Following this successful collaboration, the companies will continue to jointly seek opportunities to enable the competitive and flexible supply of LNG to various customers in strategic locations, with a focus in Europe.

THE LNG ROUNDUP X GTT to design cryogenic fuel tanks for SHI X Naming ceremony held for France’s first LNG bunker vessel X Elliott to hold ceremony for cryogenic pump testing facility Follow us on LinkedIn to read more about the articles

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LNGNEWS India

South Korea

Tractebel to manage LNG fuelling station construction projects

ABB to turbocharge engines of LNG carriers

NG storage and dispensing facilities are being installed in retail gas stations in India that currently only provide diesel and gasoline. Tractebel has been awarded the engineering, procurement, and construction management (EPCM) for two of these stations. As part of the government’s initiative to reduce greenhouse gas (GHG) emissions, LNG will soon be available at fuelling stations in the southern Indian states of Tamil Nadu and Kerala, for dispensing to long haul trucks. Bharat Petroleum Corp. Ltd, an Indian government-owned company, has selected Tractebel’s gas and energy experts for the overall design, detailed engineering, project management, and construction supervision at two locations. The company is also assisting with the procurement of LNG equipment such as cryogenic tanks, dispensers, pumps, and associated fittings. Once operational, the LNG stations will provide commercial vehicle operators with increased access to cleaner fuel, thereby driving a reduction in vehicular pollution. The LNG fuelling stations are expected to open in July 2022. Mridul Kumar, Project Manager at Tractebel, stated: “A top priority of the Clean India Green India sustainability plan is to reduce vehicle pollution, a major contributor to GHG emissions throughout the country. We are pleased to be a part of the initiative by providing LNG as a cleaner alternative at retail fuelling stations. Expanding the availability of LNG will help reduce the volume of harmful CO2 emissions, an essential step in stopping the clock on climate change.”

BB’s A200-L turbochargers will be used on MAN Energy Solutions’ 5G70ME-C10.5-GA engines destined for six 174000 m3 LNG carriers ordered by four shipowners – Korea Line Corp., PAN Ocean, Knutsen OAS, and JP Morgan – under a long-term charter agreement with Shell. The ME-GA is MAN’s first low-pressure dual-fuel two-stroke engine. It sits alongside MAN’s well-established high-pressure ME-GI engines, offering LNG carriers and other vessels an alternative way to cut greenhouse gas emissions and minimise air pollution at lower capital cost. The gas-fuelled engine can also operate on synthetic or biomassderived LNG as it becomes available, either for full use or as part of a fuel blend, further reducing climate impact. Turbocharger performance is particularly important for dual-fuel engines. High turbocharging efficiency ensures that a high air-fuel ratio is maintained during high-load operations, reducing potential fast combustion, which can adversely affect operation and emissions. The A100/A200-L series is ABB’s most advanced single-stage turbocharger technology for two-stroke engines, using the latest thermodynamic and aerodynamic expertise to pack the highest-pressure ratios and efficiency currently available into a compact unit. The small footprint also translates into a lower cost of ownership as spare parts are smaller and more economical and the turbocharger itself is easier to handle for servicing. ABB Turbocharging will also provide turbochargers for the auxiliary engines on each vessel.

15 - 18 November 2021

30 November - 03 December 2021

05 - 09 December 2021

ADIPEC

23rd World Petroleum Congress

Abu Dhabi, UAE

21st World LNG Summit & Awards Evening

www.adipec.com

Rome, Italy

www.23wpchouston.com

Houston, USA

www.worldlngsummit.com

14 - 16 December 2021

31 January - 02 February 2022

28 - 30 March 2022

Turbomachinery & Pump Symposia 2021

European Gas Conference

8th International LNG Congress

Vienna, Austria

Dusseldorf, Germany

Houston, USA

www.energycouncil.com/event-events/

www.lngcongress.com

www.tps.tamu.edu/

european-gas-conference

November 2021

LNGNEWS South Korea

Japan

Carbon neutral/offset LNG delivered to Japan

ussian LNG carrier, the Grand Aniva, has arrived at the Chita Terminal in Aichi Prefecture, Japan, with Sakhalin Energy’s first carbon neutral/offset LNG cargo. It is delivered to the Japanese company Toho Gas to be supplied as carbon neutral city-gas to its customers. According to Roman Dashkov, Sakhalin Energy’s Chief Executive Officer, the fact that the Japanese customers are seeking mutually acceptable commercial solutions in compensating the carbon footprint of the supplied energy sources is mainly caused by the Japanese government announcing carbon neutrality by 2050. That is why all initiatives to reduce carbon dioxide emissions are considered, while helping to save the global environment. “Successful co-operation with the Asia-Pacific customers and Sakhalin Energy’s work on decarbonising the entire LNG chain from production to final usage of end users, allows to bring Sakhalin gas supplies to Japan to the next stage. It is not only an achievement of the present day, but also the shaping of the long-term outlook for the company’s commercial strategy, which involves supplies of carbon neutral/offset LNG as a competitive standard offer for many years ahead,” Roman Dashkov stressed. The carbon neutrality/offset of the first Sakhalin-2 LNG cargo was achieved by purchasing carbon credits from one of the company's shareholder’s affiliates, Gazprom Marketingb&bTrading Ltd. In addition, Sakhalin Energy is considering the possibility of obtaining Russian carbon credits using a pilot carbon trading system on Sakhalin, and the possibility to generate carbon units as a result of solutions based on the environmental assets.

GE signs contract with Samsung Heavy Industries

E Power Conversion has been awarded a new contract with Samsung Heavy Industries (SHI) to supply its SeaGreen™ Power Take Off (PTO) system, incorporating GE’s latest medium voltage Advanced Permanent Magnet Machine (APMM), for Maran Gas Maritime’s new LNG carrier. The LNG carrier is due for delivery to Maran, LNG shipping specialists based in Greece, in 2023 and will be built at SHI's yard in Geoje, South Korea. For this contract, GE’s APMM-powered technology will help to provide increased reliability and efficiency, helping to reduce Maran’s operating costs as well as its ship’s fuel consumption and greenhouse gas emissions. PTO is an effective way of incorporating GE’s hybrid electric ship technology where there is limited space, and it will provide electric power to the ship’s onboard network. GE’s scope of supply includes two sets of medium voltage APMM shaft generators offering high power density, a compact design and high thermal performance, and GE’s proven MV7000 medium voltage pulse width modulation (PWM) active front end frequency converters. GE is responsible for design, engineering, commissioning, training, and assistance for sea and gas trials. The SeaGreen PTO/PTI system helps shipowners to improve fuel efficiency, reduce emissions, and meet environmental standards. The system can also decrease the operating hours of auxiliary generators – and their need for maintenance – for additional operational cost savings. Andreas Spertos, EVP-Technical Director at Maran Gas, says: “As we expand our fleet of LNG carriers, we are fully committed to ensuring that the new vessels will incorporate the latest technology available which will achieve best efficiency, highest reliability, and help to reduce the environmental footprint to the maximum possible extent. The introduction of GE shaft generators helps us to fulfil this commitment.”

Australia

Flex LNG announces time charters

lex LNG Ltd has agreed two time charter agreements with a minimum firm period of three years for each of its two existing LNG carriers, Flex Resolute and Flex Courageous. The charterer, an energy major, will have the option to extend each ship by two additional two-year periods bringing the total period to seven years under each of the time charters. Under the time charters, the vessels will be delivered to the charterer during 1Q22 in direct continuation of their existing time charters. Both ships are large LNG carriers with ME-GI

November 2021

propulsion and a cargo capacity of 173 400 m3. Furthermore, Flex Couragous is equipped with a partial reliquefaction system while Flex Resolute is equipped with full reliquefaction system, bringing the active boil-off rate down to 0.075% and 0.035% respectively. This makes the ships very flexible and fuel efficient for transportation of large LNG parcels with close to 0% methane slip from the main engines. The time charters remain subject to final documentation and certain closing conditions.

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Alexander Klimentyev, Inna Kirilkina, Amina Talipova, and Jinsok Sung, Russian Small and Mid-scale LNG Research Group, Russia, outline Russia’s LNG industry, including its main producers, plants, and the wider LNG market.

NG production in Russia is 8.3% of the global production and one of the fastest-growing industries in the country, with 29.6 million tpy of operating capacities as of 2020 (Figure 1). Therefore, LNG export development is one of the high-priority targets for the Russian government. In the most recent State Energy Strategy, total LNG capacities are expected to reach 140 million tpy. The Russian LNG industry is comparably young and dates back to 2009 when the consortium of Sakhalin Energy and foreign investors’ LNG plant was put into operation. At that time, the projected capacity was 9.6 million tpy, with the Asian market as the final place of destination. Japan and South Korea were the biggest consumers of Russian LNG and remain so until today. It took almost 10 years for NOVATEK to establish the 16.5bmillionbtpy Yamal LNG plant. It is located in the Arctic zone, designed for severe weather conditions, and based on the Yuzhno-Tambeyskoe large gas-condensate field. Not without government support – which entirely sponsored the construction of marine port Sabetta – the plant started fully operating at the end of 2018. Another ambitious project by NOVATEK is the Arctic LNG 2 project that is currently under construction. The project is expected to exceed Yamal LNG capacities by almost 3bmillionbtpy. As of 2020, Russian LNG from two plants was exported to 33bcountries (Figure 2). Russian LNG projects can also be differentiated geographically by destination and by the contracts/portfolio structure. Both Yamal and Sakhalin plants have contracted volumes to China on delivery ex ship (DES) terms. Gazprom has long-term African and Indian deliveries in its portfolio with EGAS and GAIL. In contrast, NOVATEK’s portfolio includes other market players such as Total, Shell, Gunvor, and is very similar to Cheniere’s portfolio. Compared to other big market players such as Qatar, the US, or Australia, Russia is prone to act in all regional directions. The average duration of contracts in Russia varies from fivebto 20 years, where the shortest contracts were signed in recent years.

A comparison of the main markets for the largest LNG producing companies (Qatar, Australia, US, and Russia) demonstrates the different strategies:

actively developing to cover the internal demand for natural gas, mainly in remote and distributed areas. In particular, NOVATEK has been operating Kryogas-Vysotsk mid scale LNG since 2019 and is planning Obsky mid scale LNG by 2023. However, with z Asia is the only one used for Australian projects (more than rapidly changing reality and global prospects for natural gas, the 99.5% from produced LNG). company adjusts its strategy and advances technologies. Thus, z Qatar followed world market trends and the change in sales Obsky LNG today is considered a potent ammonia producer for in the world has mirrored the sales of Qatar’s LNG facility. future hydrogen industry development. Gazprom, the most z The US and Russia are finding a balance between different prominent incumbent in the Russian gas industry, actively regions in Asia/Europe, and the Middle East/North America. involves small and mid LNG plants in its strategy along with its only Sakhalin Energy plant. If all conceived LNG projects of all The Sakhalin and Yamal giants do not limit the history of capacity sizes were realised in Russia, the total LNG production Russian LNG. On the contrary, mid and small scale LNG plants are might reach approximately 250 million tpy by 2035 (Figureb4). In Russia, there are currently six operational LNG export projects. The Sakhalin-2 LNG exports LNG to the Asia Pacific region, mainly nearby East Asian countries. As a result of its geographical position, Yamal LNG sends LNG cargoes across the world. The majority of the produced volume is delivered to European countries and Asia, albeit smaller volume. Vysotsk LNG is a mid scale LNG project on the Russian Baltic shore. There Figure 1. World LNG capacities and the shares of primary LNG producers. are three small scale LNG export projects: Source: based on GIIGNL data. Kriogaz LNG; SiTek; and Gazprom Transgaz Ekaterinburg (GTE). Kriogaz LNG is located in Pskov, not far from Estonia; SiTek is located in the Republic of Sakha-Yakutia in East Siberia; and GTE is located in Ekaterinburg. Kriogaz LNG sells LNG small scale cargoes by trucks, mainly to the countries on the Baltic Sea, whereas SiTek and GTE export all of their LNG to Mongolia and Kazakhstan, respectively.

Pricing Figure 2. Russian LNG export by country of destination. Source: based on GIINGL data.

Table 1. Greenhouse gas (GHG) management on Russian LNG projects GHG management CCS Hydrogen in the fuel mix Renewables e-LNG Nuclear power energy High-pressure gas pipelines C2+ and rare gas extraction Utilisation of cold ambient air Short transportation distance Complex logistics and LNG transhipment Carbon offsets

November 2021

Sakhalin-2

Yamal LNG

Baltic LNG

Yakutian Far East LNG LNG

In 2020, among the four significant destinations of Sakhalin-2 LNG, China paid the lowest price, with imports priced at slightly below US$3.9/million Btu. Chinese companies imported spot LNG cargoes only because they do not have a long-term contract with Sakhalin-2 LNG. Several Japanese companies, KOGAS of South Korea and CPC of Taiwan, all have long-term contracts with Sakhalin-2. In 2020, annual average spot LNG prices maintained a lower level than term-contracted LNG. Therefore, LNG import prices to China recorded the lowest range compared to companies purchasing LNG from Sakhalin based on long-term contracts. Small scale LNG from Ekaterinburg to Kazakhstan costs slightly below US$4/million Btu on average. In the same year, Yamal LNG export prices to Asian countries were recorded higher than European countries. This is because LNG prices in Asia are frequently higher than those in the European market. For example, the Japan-Korea marker (JKM) price level maintained higher than the TTF-European hub price throughout the year. At the same time, transportation costs to the Asia Pacific region were also higher than those to Europe. As a result, the average LNG price from the Yamal to European customers was higher

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Investments and export regimes

Figure 3. Markets of primary LNG producers (share from countries’ produced LNG). Source: based on GIINGL data.

The Russian LNG industry is getting more and more interesting for foreign investors. The level of maturity of any economic sector could be, to some extent, estimated by the activity of foreign investors. In the case of Russian oil and gas, foreign money was mainly welcomed in offshore upstream and midstream projects. It is clearly explained by the international practice of co-operation in technically and economically complicated projects. Usually, one country cannot provide the necessary level of expertise. Sakhalin-1 and 2 might be good examples. For Russian LNG liquefaction facilities, already operating and under construction, the following outline the oil and gas giants intensely interested in Russian gas import:

z Sakhalin-2: Shell Concern; Mitsui Group; Mitsubishi Group. z Yamal LNG: Total; CNPC; Silk Road Fund. z Arctic LNG 2: Total; CNPC; CNOOC; Japan Arctic LNG B.V. (Mitsui & JOGMEC Consortium). z Far East LNG: Exxon Mobil; SODECO; ONGC Videsh Ltd.

Figure 4. LNG plants operational and planned. Source: #LNGmap project. than TTF prices on average. Belgium paid in the region of US$4.8/million Btu, the highest price among European buyers. Among Russian LNG export destinations, small scale LNG volumes of SiTek from the Republic of Sakha-Yakutia to Mongolia received the highest value with an annual average sales price of over US$12/million Btu. Average sales prices of Vysotsk LNG recorded US$4/million Btu, higher than TTF price by approximately US$0.9/million Btu. Lithuania and the Netherlands paid lower than TTF from Vysotsk LNG – they paid US$1.7/million Btu and US$2.2/million Btu on average, respectively. Thus, average LNG prices to European and Asian countries were higher than TTF and JKM in 2020. However, it is worth noting that in 2020, spot gas prices maintained a record low level due to the demand shock caused by the pandemic. On the other hand, the price of term-contracted LNG stayed at a relatively higher level in the same year. This is because most of the production volume of Sakhalin-2 LNG and Yamal LNG is devoted to customers under a long-term contract. In 2021, on the contrary, TTF and JKM prices rocketed, and spot LNG prices are experiencing the highest level in history. Therefore, in 2021, it is anticipated that the average LNG price from the majority of term-contracted cargoes around the world will be considerably lower than spot prices, including Sakhalin-2 LNG and Yamal LNG.

November 2021

Among the proposed projects, Kara LNG is being considered by BP Russian Investments Ltd and Q.H. Oil Investments Ltd (Qatar Investments Authority). It is essential to note that foreign investors try to participate in all strategically crucial facilities, including floating storage and terminals. For example, TotalEnergies is a 10% owner of floating LNG storage in Murmansk and Kamchatka. Small LNG projects are also interested in foreign aid, but several obstacles exist for successful international co-operation. Most of them occurred due to certain peculiarities of Russian export legislation. Currently, there is no legal restriction, and the small scale LNG project could attract foreign finance or any other contribution through different types of joint venture, partnerships, or other co-operation agreements. But one of the unavoidable and very reasonable conditions in most cases is the LNG export contract which proves the project feasibility and guarantees investment return. So, the critical issue for an LNG project is to make sure the potential product is already sold. Among Russian companies, only two giants – Gazprom and Novatek – could afford to meet these conditions. Rosneft is negotiating its right to join this exclusive LNG exporters club. There is a substantial concern that in case of failure, Rosneft will not keep its LNG ambitions. Given the abundant gas reserves in Russia and existing infrastructure, one of the critical limitations for LNG project realisation and further export to the global LNG market remains in the regulatory area. The existing regime restricts export for small or mid scale LNG producers and requires potential LNG exporters to own the entire value chain – from the license to production to transportation. The export legal framework should be liberalised in case of taxes on LNG and pipeline gas to increase Russian LNG export. LNG export monopoly was fixed by the federal law ‘About Gas Export’ in 2006. The decision was backed by the necessity

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to maximise budget income in the condition of rising LNG export prices and high margin sales. In 2013 the law was changed. LNG export was allowed to the entities – federal fields developers whose licensed activity before 1 January 2013 presumed LNG production or exploration gas for further liquefaction. As a result, the export right was granted to specific fields which met certain extra conditions. For example, Yamal LNG and Arctic LNG 2 are fuelled from those gas fields where gas could be exported without Gazprom permission. Due to this crucial legal point, NOVATEK managed to attract an appropriate investors pool and promoted LNG production and export as its main strategic line. It is essential to mention that this law does not regulate LNG export by the entities operating under Product Sharing Agreements (PSA). At the moment, seven projects are being allowed to export LNG: PJSC Gazprom, PJSC Rosneft, PJSC Yamal LNG, Gazprom Export Ltd, Arctic LNG 1 Ltd, Arctic LNG 2 Ltd, and Arctic LNG 3 Ltd. Indeed, a restrictive LNG export legislature is one of the critical obstacles for Russian LNG export expansion. Several projects have already stopped due to this reason. For example, Gorskaya LNG, Pechora LNG, and some small scale LNG projects

Figure 5. Russian LNG exports price by country (annual average in 2020). Source: based on data from the Federal Custom Service of the Russian Federation.

did not manage to persuade investors without signed, valid export agreements. In 2019 several alterations to the Gas Export Law were made, but they did not let other companies export gas and simply added some new fields developed by NOVATEK to the list of gas export fields. However, the damage for Russian interest became apparent, and the Energy Strategy of Russia 2035 presumes some liberalisation (permission to sell without Gazprom control) in the case of mid (2 million tpy) and small (80b000btpy) LNG projects. Also, in parallel, it is expected that gas tax reform will cut taxes on pipeline gas and increase taxes on LNG, including the particular obligation for localisation of LNG liquefaction equipment and national gas carrier priority.

Carbon footprint Natural gas has the role of a transition fuel, because emissions produced from using natural gas are significantly lower compared with oil fuels and coal. The carbon neutral LNG will improve the ecological position on the energy market for an extended period. On the other side of the coin is natural gas, highly criticised for methane leaks and required greenhouse gas (GHG) management to stay on the market long-term. Carbon footprints are managed at all steps of the production chain, including gas production, transportation, liquefaction, LNG shipment, and regasification. Sakhalin-2 has a specially developed programme called ‘Ecological LNG.’ Russian companies have a low-carbon footprint due to the cold environment and actively improve technological development and renewable energy sources. So the use of Russian LNG will decrease CO2 emissions not just in the case of a coal to gas switch, but also in the case of Australian or US LNG to Russian LNG. Even with a low CO2 footprint due to the cold climate site, Russian LNG projects implement different ways to manage GHGs through the entire value chain. The most diverse ways include the use of electric drivers combined with nuclear power, and producing additional products such as ethane, C3+, and rare gases. Russian LNG plants have completed several deliveries of carbon neutral LNG cargoes. There are three cargoes of carbon neutral LNG delivered from Russian LNG plants: two for the Asia market (CPC and Hokkaido Gas were buyers for Taiwan and Japan respectively) and one for the UK (Shell was the buyer). The carbon offsets were well-to-wheel.

Conclusion

Figure 6. Carbon footprint of selected LNG plants. Source: IEA Environmental Integrity Project, Emission Increase Database, November 2019.

November 2021

Known as the largest pipeline exporter globally, Russia has a significant potential for LNG industry development. Given enormous gas reserves, the second largest natural gas market globally, and geographical access to big LNG consumers, Russia can export gas through the well-developed gas network infrastructure. The success of Yamal LNG in the Arctic is an encouraging example for other producers in Russia to strive for their success and drive the industry development. Today, Russia is aiming to achieve its vast potential to become a global LNG sector leader, since it has the potential to produce up to 250 million tpy in Baltic, Antarctic, and Pacific basins and accelerate the growth of the domestic LNG market.

he hydrocarbon processing industry has strict international testing standards related to the performance of passive fire protection (PFP) coatings for oil and gas platforms, terminals, refineries, and other petrochemical facilities. In recent years, several high-profile PFP coatings failures in cold-weather climates, such as a well-documented case at the oilsands in Alberta, Canada, have demonstrated the need for more rigorous testing of intumescent epoxy coatings for application in such environments. Whether floating offshore or based on land, LNG installations are essentially densely populated factories in which fire hazards are in close proximity to process areas as

well as facilities such as control rooms and even accommodation modules. This increases the risk of rapid escalation combined with the need for specialist escape and evacuation provisions for personnel while trying to minimise damage to the asset. Growing interest in offshore floating LNG (FLNG) for export trade and increasing numbers of import facilities for local power supply mean that the number of offshore fixed and FLNG installations is growing. Such projects may often feature gas storage close to industrial installations or at ports where a nearby population or critical infrastructure is present. Fire ratings for such installations are traditionally based on the ability to withstand pool fires, which may not be sufficient

where products are stored and handled under cryogenic temperatures and at high pressure. LNG presents fire risks before or after liquefaction, most dangerously the risk of jet fire. Regulators such as FERC in the US expect project designers to demonstrate that hazards such as jet fire and cryogenic spills are adequately addressed in their permit applications, but the obligation is on safety engineers to manage risk to acceptable levels rather than meet a regulatory standard. Safety case requirements compel engineers to identify the unique hazards of their facility and ensure safety and environmental critical elements such as firewalls and critical structural and process components are provided with adequate protection, but these are only required to meet performance standards drawn from industry guidelines in providing resistance to credible threats. To resist jet fires more effectively requires not just highperformance coatings but a testing regime that includes the specific characteristics of highly flammable and high-pressure inventories, often in extreme environments. This article highlights a comprehensive test regimen sponsored by a major coatings manufacturer and developed and executed by a leading international university, which compared five intumescent epoxy passive fire protection (EPFP) products commonly specified for protection of steel structures in the hydrocarbon processing industry. The testing served not only to quantify the potential performance of the five EPFP coatings in less-temperate climates but may also provide a template for industry-wide adoption of more comprehensive testing standards for PFP coatings in general, particularly as their use continues to

expand in northern locales and on lighter, pre-coated, modular steel structures. When evaluating PFP coatings for any application, it is important for specifiers to look beyond the fire rating. This is true for all PFP coatings types, but especially so for intumescent EPFPs, which are increasingly preferred over traditional cement-based and fibre-based PFP materials due to their lightness, flexibility, performance, and ease of application. While any PFP material will have fire certification, EPFP intumescent epoxy coatings should be selected for their ability to meet all the demands associated with their end use, including their ability to survive transportation to a job site, as well as the installation and construction methods employed at the job site, without cracking or delamination. Such systems are expected to be virtually maintenance free for the life of the facility and ready to perform the required fire protection function at any point in its design life – one particularly hard winter should not risk damaging the EPFP. With the growing popularity of stick-built and modular off-site construction techniques, steel beams, columns, and other components for LNG facilities are increasingly prefabricated and finished with EPFP coatings before they are delivered to the job site. In many cases, these fireproofed components are shipped across oceans and continents, through changing weather conditions. This, in turn, can cause poorly designed coatings to crack or delaminate and compromise their performance before they are ever placed into service. This trend, combined with the increasing prevalence of gas import or export projects being constructed in extremely cold environments, makes expanding the scope of industry standard testing of PFP coatings beyond their existing parameters more critical than ever.

Table 1. Tests performed

Specifying PFP coatings

Material

Temperature (˚C)

25, 5, -10, -30, -50

25, 15, 5, -10, -30, -50

25, 15, 5, -10, -30, -40, -50

25, 15, 5, -10, -30, -50

Due to the many options available, picking the right PFP coating system to meet the specific safety demands of a particular facility or application can be a daunting task. The following guidelines, authored by an industry consultant and published in 2014 by a leading offshore engineering trade journal, outline a step-by-step hierarchy of needs that engineers can reference to determine the safest and most effective PFP coating system for their facilities. According to these guidelines, the ideal PFP coating system designed for a facility:

Extra tests were performed on products C1 and C2 to establish the failure point because these samples did not provide a conclusive outcome at -50°C.

z Shall not generate hazards, such as the formation of corrosion which can lead to leaks and loss of integrity, or use hazardous materials such as asbestos. z Shall not degrade with time in the environment to which it is exposed during its designed service life, or before the first maintenance, including process operating conditions. z Shall survive an initial explosion, including resultant overpressure, drag force, deformation of substrates, and impact from flying debris. z Shall survive an initial high heat flux, high-momentum jet fire that may occur. z Shall provide fire protection for the required time and maintain the temperature of the item being protected below its critical temperature.

Figure 1. A test methodology was developed to quantify the performance of the new coating against four alternatives.

November 2021

Over the years, many intumescent coating types have been formulated to achieve these demands on steel structures in traditional temperate and tropical environments. However, due

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to their rigid formulation, some of these products have proved not to be well-suited for colder climates where thermal cycling extremes can cause steelwork to expand and contract dimensionally and frequently, which can lead to delamination, cracking, and loss of fire integrity.

A new testing regimen In 2018, a major coatings manufacturer developed a new epoxy-based EPFP coating that was designed to be thinner, lighter, and more flexible than alternate PFP coatings, yet offer the same high levels of impact, jet fire, and pool-fire resistance as other field-proven counterparts. To investigate the viability of its new formulation, the company engaged independent researchers at a leading international university who are recognised industry experts in the fields of structural dynamics and PFP material science.

Together, they developed a test methodology to quantify the mechanical performance of the new coating against one of the sponsoring manufacturer’s existing and well-proven EPFP coatings and together with three commonly specified alternative EPFP coatings. The five materials referenced earlier are identified as follows: z Product P – Serving as the benchmark material, this product has a proven 35-year track record of cracking resistance in extreme and cold environments. It was developed by the sponsoring manufacturer and is wellregarded throughout the industry. z Product N – The next-generation flexible and extremely lightweight epoxy intumescent coating. It was engineered by the sponsoring manufacturer to accommodate weather extremes and the lighter steel structures now being constructed for many hydrocarbon applications. z Product C1 – A rigid epoxy-based PFP coating with a 15-year track record developed for the onshore UL 1709 fire test standard market.

Figure 2. Exhibiting ductile tearing at room temperature. Left: product P; right: product N.

z Product C2 – A relatively rigid, mesh-free EPFP coating that had previously exhibited failure in cold climates on structures built using modular and stick construction techniques. z Product C3 – A newly launched, novel epoxy-based EPFP intumescent coating described as a ‘low-temperature-cure modified epoxy with a more rigid network.’ The test regimen was conducted as follows.

Test specimens Figure 3. Product N ductile-brittle transition <0˚C (32˚F) temperature.

Figure 4. Exhibiting brittle failure at room temperature. Left: product C3; right: product C1.

The five EPFP coatings described were applied to flat steel bars measuring 600 mm long, 50bmm wide, and 10 mm coated at a nominal thickness of 8 mm. Flat bars were selected because they were consistently coated by draw-down technique using a shuttering frame. The dimensions were large enough that the effect of stresses induced by differentials in coefficients of thermal expansion could be easily and consistently measured. The bars were also small enough to fit in a freezer with temperatures as low as -60˚C (-76˚F). 15bspecimens were prepared for each of the five EPFP materials, equalling 75bspecimens in total.

Test arrangements

Figure 5. Left: product C1 exhibiting delamination at 0˚C (32˚F). Right: product C2 exhibiting delamination at room temperature.

November 2021

A three-point bend test was employed on each steel bar with the specimen supported on two brackets. Total specimen length, as detailed above, was 600 mm. There was a clear span of 500bmm between the supports with the EPFP coating occupying 460 mm of the clear 500bmm span. Using a 200 kN capacity Instron, the maximum vertical displacement of each

specimen was measured at mid-span by the movement of the loading platen built into the test instrument.

products remaining undamaged at strains greater that 0.5% across the critical temperature range.

Test calibration

Key observations

A calibration test of an uncoated specimen at an ambient temperature of 25˚C (77˚F) was undertaken to establish a benchmark load displacement-surface strain relationship.

As expected, the three rigid intumescent EPFP coatings (products C1, C2, and C3) performed the least well, exhibiting brittle failure modes at relatively low strain levels and, in some cases, delaminating extensively from the steel test specimens even before the application of load at low temperatures. Product P, the benchmark EPFP coating with the 35-year track record, performed the best at low temperatures, exceeding the yield-point strain limit of 0.2% for steel structures at temperatures of -50˚C (-58˚F.) Product N, although slightly less flexible than product P, also performed very well at low temperatures, again exceeding the industry standard strain limit of 0.2% at a temperature of -50˚C (-58˚F).

Temperature calibration A calibration test of coated EPFP specimens was completed to establish a common through-thickness temperature profile. This was undertaken by cooling a selection of specimens to -50˚C (-58˚F) for 24 hours, then inserting a needle thermocouple into the midpoint of the EPFP. This temperature was then compared against the surface temperature of the steel and the EPFP coating using an infrared gun thermometer, which showed that the temperatures were consistent throughout the thickness of the coating. Changes in temperature of approximately 5.5˚C (10˚F) were noted to occur after being outside the freezer for 1 min., and 10˚C (18˚F) after 2bmin. outside the freezer.

Main test 75 tests were performed, consisting of the combinations of specimen type and temperature shown in Table 1. For each test, all specimens were held at specified temperatures for 24bhours before being subject to strain-temperature testing. During the tests, visual observations were made of the first sight of the following: z First surface cracking or tearing. z First through-thickness (down-to-steel) cracking. z Delamination or disbonding. Figure 2 shows that the flexible products are able to withstand large deflections before the onset of surface tearing. Figure 3 shows that below 0˚C (32˚F) the tearing transitions into a cracking but the product remains adhered to substrate. Figure 4 shows the more rigid products, C1 and C3, already exhibit cracking at room temperature, and at below 0˚C (32˚F) the failure mode exhibits delamination from the substrate as shown in Figure 5. Figure 5 also shows that product C2, the most rigid material, exhibits delamination from the substrate even at room temperature. The points of displacement at which the observations were made were recorded, then converted to surface strains using a calibration curve created from the calibration tests described earlier. A minimum of two specimens of each material were tested at each temperature specified in Tableb1.

Conclusions Until recently, the oil and gas industry has operated under the belief that, when it comes to EPFP coatings ‘harder is tougher.’ But with the prevalence of modular construction and its demands for lighter steel components – as well as the increasing level of industry construction in cold weather climates – that truism no longer applies. It is now essential that designers understand how steel behaves in various conditions and why it can require more flexible PFP coatings. Just as PFP coatings must be formulated to accommodate these new realities, the scope of industry-standard testing must expand to meet them as well. The design of safe, affordable, and effective EPFP coating systems, tailored to the specific requirements of the facility it is meant to serve, can be a complex undertaking. The development of new EPFP coatings solutions to meet the changing demands of the industry has the potential to complicate matters further. For all these reasons, the need for more robust testing standards and protocols for the next generation of EPFP coatings, including cold-weather testing, is more critical than ever.

Test results A summary of test results for all specimens was recorded and failure-strain results for each product were plotted to illustrate their trends of transition between ductile (tearing) and brittle (cracking) failure as well as to establish if the products exhibited delamination. This is shown in Figure 6 which plots the steel surface strain where the product tears or cracks the EPFP coating against key temperatures of interest. As the graph illustrates, there is a direct correlation between temperature and load failure with two of the

Figure 6. Strain-temperature plots at first crack for tested epoxy passive fire protection (EPFP) materials.

November 2021

r, rude g a sM ribes i c r s h e C SA, d es in U , s pu vanc d a Olym t ction cen e e p r s e n th ray i ion. r t a a c d i e r phas k fab n a t NG for L

he increase in LNG storage and processing projects worldwide combined with the success of portable phased array inspection systems for this application have created a demand in the market for dedicated phased arraybased LNG tank solutions. Radiography testing (RT), a common non-destructive testing (NDT) method used for LNG welds, is time-consuming and causes inspection bottlenecks when it cannot keep pace with production. Using specialised phased array probe sets and software designed for American Petroleum Institute (API) compliance of LNG tank inspection as a

replacement for RT can provide significant improvements in productivity and inspection results.

LNG tank construction LNG requires cryogenic storage conditions at temperatures below -162˚C (-260˚F). 9% nickel steel alloy tank shells are welded with an Inconel alloy I625 electrode, creating a dissimilar metal weld that remains ductile at cryogenic temperatures to prevent cracking. LNG tanks are thermally insulated and require a cooling system. They are made up of an inner welded shell to contain the LNG, an outer shell made of concrete, and a thick layer of thermal insulation between the two, requiring that the phased array weld inspections be performed from inside of the tank during construction.

Tank shell sections can be up to 12 m (39 ft) by 4 m (13bft) in size and beveled for either horizontal welds of different thickness or vertical welds of the same thickness. The largest of LNG tanks under construction today can be up to 45bmm (1.7 in.) thick at the base and include more than 2000 linear m (over 6500 ft) of weld. NDT inspection of welds during LNG tank fabrication does not necessarily need to synchronise with the completion of each shell ring, meaning the phased array inspection can be staggered or undertaken in stages.

Phased array inspection equipment To perform an efficient and effective phased array weld inspection of LNG tanks, the recommended equipment consists of an acquisition unit, an acquisition software on a laptop computer, an encoded mechanical or automated scanner, and unique Olympus LNG quad probe that provides full volumetric inspection of the austenitic I625 weld bevel and heat-affected zone (HAZ).

Four-in-one phased array probe optimised for LNG tank inspection

Figure 1. Thousands of meters of welds need to be validated using non-destructive testing (NDT) during LNG tank fabrication.

Figure 2. Phased array instrumentation configuration for LNG tank inspection.

The LNG quad probe is designed for API and ASME compliance and is made of two 1D linear phased array probes and two Dual Linear Array™ (DLA) probes all wired to a single connector for reduced cost and ease of use. The 1D linear phased array probes, typically applied to carbon steel inspections, are used with shear wave wedges to detect and size any bevel and HAZ flaws with precision, but only the DLA probes can reliably penetrate the austenitic I625 weld volume. Phased array instrumentation designed for a mobile job site is lightweight, ruggedised, water resistant, and can be used on battery or external power in close proximity to the scanner, eliminating the need for long and expensive umbilical probe and scanner cabling. For the LNG quad probe support, a minimum instrument pulser configuration of 32:128 is required. A laptop is connected to the acquisition unit by Ethernet cable, and the acquisition software includes tools for creating configurations, performing daily calibrations, and managing the acquisition, analysis, and reporting. The LNG inspection workflow is predefined in the software, including the bevel change outs, so the inspection crew can focus on performing the inspection and not on the set-up. The mechanical scanner used for the data acquisition is selected based on job site conditions. Where a basket lift or scaffolding is available for welding, the inspection crew can use a magnetic, non-motorised scanner and move it along the weld line. More commonly, a motorised scanner with remote controller is used, which can be driven on the weld line with or without a remote camera installed. The 9% nickel shells are sufficiently ferrous for the magnetic wheels of the scanner to stick to the tank.

Testing preparation Figure 3. Left: Probe hardware. Right: The scan plan in the acquisition software showing the probe positioning and coverage.

November 2021

Surface preparation of the LNG tank weld requires light buffing to remove weld spatter, and the weld crowns are ground flush at the shell intersections to allow the scanner to pass unobstructed. A phased array system’s data acquisition rate for LNG weld inspection is approximately 75bmm (3 in.)/sec., depending on thickness, and a typical

work shift can include inspection and analysis of several days of welding. The phased array probes are coupled to the tank’s inner surface with water from either a manual sprayer or electric water pump using approximately 1 l per 5 m of weld, and light water spillage is normally not a problem inside the LNG tank during construction. The scanner technician positions and drives the scanner, keeping it aligned with the weld line, while the inspector watches the data displays in real-time. Defects, when necessary, are marked for repair immediately after the inspection and prior to moving to the next weld.

Figure 4. Calibrating the probes using a standard with manufactured flaws in the bevel and weld volume.

Phased array set-up and configuration The phased array scan plan is the summary of the inspection strategy and includes probe and wedge models, offset positions, angles used for inspections, focus depths, virtual probe apertures, etc., and is documented in the company work procedure and acquisition software in accordance with (IAW) the API 620 and ASME V referencing codes. Figure 5. Software user interface for data collection and analysis. All weld bevel designs for the tank are created in the system software in advance, and a scan plan based of repaired areas are performed using the same inspection on thickness for each range of tank shells is prepared. The method as the original weld. acquisition software is designed for a fast and efficient The weld acceptance decision is made using API 620 workflow, taking approximately 15 min. for the start of shift table U1 or table U2 for AUT in lieu of radiography. Both set-up and calibration or midshift bevel and thickness tables require the flaw to be characterised as surface changeout. connected or embedded and sized in length and height for Phased array probe calibration an acceptance decision based on weld thickness. Table U2 The inspection scanning sensitivity is set prior to each is most frequently used as it is less sensitive, resulting in a series of inspections using welded mock-ups of the shell lower reject rate, and can only be applied when certain sections with reflectors fabricated at the bevel fusion for toughness criteria of the shell material are met. the shear wave probes and in the weld volume for the DLA Personnel and certification probes. Movement of the scanner on the mock-up weld Personnel performing phased array inspections of LNG validates all aspects of the inspection system, including tanks must comply with a company work procedure written ultrasonic sensitivity, probe position relative to weld bevel, IAW qualification and certification of non-destructive probe coupling, mechanical encoding, and the acquisition personnel testing standards, such as ISO 9712, SNT-TC-A1, software. or similar. Certification includes training hours, written API 620 acceptance criteria testing, and proficiency testing performed on artificially The I625 dissimilar metal weld used in the fabrication of flawed and real production weld specimens. API LNG tanks differs from carbon steel welds in that the The typical two-person crew includes a certified I625 weld volume cannot be penetrated ultrasonically inspector and a scanner technician who is an inspector in without use of DLA probes. training. API and ASME compliance require that the weld quality inspection data and examination reports be DLA probes have long been used for inspections of approved by a Level III reviewer, which is typically carried stainless steel and other coarse-grained austenitic out remotely off-site after files are uploaded to a server or materials, and they penetrate the weld using a refracted cloud at the end of each shift. angle pitch-catch technique. The shear wave probes provide the coverage of the HAZ adjacent to the weld and precision measurements on the bevel flaws. Use of the four Conclusions phased array probes in this configuration eliminates the Implementing phased array inspection systems in need for time-consuming manual flaw prove-up after replacement of radiography testing in API 620 LNG detection and provides optimum detection and tank construction is no longer an expensive or risky repeatability for LNG weld inspection. development proposition. Service companies or fabricators The phased array inspection data is analysed in C-scan can bid on LNG tank inspection contracts with confidence, knowing dedicated phased array probe solutions are top view and S-scan side view data displays that visualise available. Moreover, specialised equipment and fully weld flaws and imperfections so they can be characterised, developed inspection procedures provide a short training precision sized, and located in the weld for repair. Rescans track for LNG inspection project success.

November 2021

Vincent Higgins and Christian Salazar, Honeywell Process Solutions, USA, explain how advanced technology addresses skills requirements for LNG operating personnel.

he LNG industry is inherently complex and becoming more competitive. LNG facilities must deal with a host of issues affecting their operational and business performance. Personnel at these sites are responsible for the operation and maintenance of critical assets such as storage tanks, heat exchangers, rotating machinery, and many other types of equipment. A key trend in addressing industrial training requirements is the use of advanced, immersive simulation technology as a solution to improve plant operator performance and, in turn, enhance efficiency, reliability, and safety.

Demands on operations personnel LNG companies are adapting to a changing world, where the advancing role of technology can help build resiliency and agility. Field operators are often the eyes, ears, and lifeline of an LNG facility; however, many field teams still rely on traditional classroom training procedures and are often disconnected from their counterparts in the control room. According to industry data, a large percentage of incidents at LNG facilities and other process industry

sites occur because workers lack competence. The operations staff must thoroughly understand plant processes and become proficient at identifying issues and troubleshooting problems before production suffers. Field operators in particular need to be familiar with LNG operating procedures, safe handling practices, equipment specifications, maintenance protocols, governmental regulations and related technical and safety codes, and standards and reporting requirements. Their job orientation typically involves studying standard operating procedures (SOPs) and then taking part in e-learning or an apprenticeship with ‘over the shoulder’ training in the field. Unfortunately, the current challenging environment has severely restricted the ability to deliver comprehensive instruction at many industrial sites. Knowledge transfer between seasoned employees and new hires – especially when it comes to abnormal plant situations – has become difficult, if not impossible. Faced with increasingly complex technology and an experienced workforce nearing retirement, LNG facilities need robust training solutions that accurately depict real-world operating conditions.

Conventional training methods often fail to help operators become better at their jobs. The result can be reliability issues and unplanned downtime.

Advancement of training simulators At large LNG terminals and other facilities, operator training simulator (OTS) systems have long been used to train control room staff on a wide range of process automation and control applications. These simulators impart fundamental process understanding and help in maintaining and improving occupational skills. Modern OTS solutions combine dynamic process simulations, emulated control systems, and replicated interfaces to recreate the look, feel, and behaviour of the actual plant. They provide an effective means for optimising processes and gaining operations experience. Simulation offers a protected area for instruction on new job scenarios, which can be relearned at any time. Unfortunately, OTS technology replicating the realistic environment, operating conditions, and physical actions in plant floor areas has never been available to field workers. Today, a new type of immersive field simulator (IFS) combines cutting-edge competency tools with proven OTS technology to create a unique and collaborative learning environment for all plant personnel. This solution enables teams of field operators and technicians to interact virtually and achieve a training experience similar to their counterparts working at control room consoles.

The IFS is intended to provide virtual reality (VR)/mixed reality (MR)-based instruction, which helps better train the modern industrial workforce. It can be used to extend console operator simulator training to field operators for credible, realistic, and immersive collaborative training experiences. The new breed of simulators enables operating companies to help to increase their worker competency while enhancing safety, so they can maximise their plant performance. The IFS design is the culmination of years of development in digital twin technology coupled with decades of real-world process domain experience. The simulator embeds industry know-how via digital twins and experience-driven insights to drive intelligence beyond that of traditional big data-based solutions. Leading automation suppliers have offered operator training simulators to replicate the functions and activities of an industrial control room setting. However, this trainingbased control room was not connected to the actual production operation but rather was tied to a digital twin of the process and assets. With the IFS, the same digital twin has been paired with a digital twin of the 3D world – essentially the plant itself with individual assets such as pumps, compressors, and pipes. The replications are linked to a mathematical process model so that an action such as turning a valve in the virtual world also changes the variables in the back-end digital twin of the process. These functions are subsequently connected to the control room training simulator. Integration of the IFS’s 3D-immersive modelling environment with a traditional OTS enables field and panel operators to train together in a safe environment, learning collaborative skills essential for effective operations.

Putting the immersive solution to work

Figure 1. Virual reality based simulator to optimise training for industrial workers.

Figure 2. Virtual, digital twins of various plant environments.

November 2021

An immersive training simulator offers a smooth, virtual walkthrough of the plant to familiarise field operators with the situations they will encounter in their day-to-day jobs. As a versatile, on-premise or cloud-based solution, it responds to the frequent changes to processes and assets that are typical of LNG industry facilities. This approach simplifies updates to help accurately reflect the current configuration within the plant and in the field. The training department can optimise management of change when it comes to swapping out equipment, animations, etc. Since the IFS is intended to be hardware-agnostic, its platform can accommodate future developments in VR and MR technologies. MR exists in the space between purely immersive and purely augmented reality. The technology blends VR, which is fully immersive and disconnected from the trainee’s actual physical surroundings and augmented reality, which superimposes images onto the real world. With the IFS solution, LNG plants can use holographic computers and MR headsets to simulate various scenarios – such as primary failure and switchovers, start-up or shutdowns, and cable and power supply failures – that train and test personnel on their skills. Trainees can sit at the simulator and go through

the exact set of steps for a specific activity as they would in the real world and then go out and accurately perform the same procedure on physical equipment in the field. Much like a flight simulator in the airline industry, the IFS facilitates trainees to become familiar with infrequent, yet critical tasks. It helps younger operators encounter a wide range of experiences in a realistic virtual environment and develop ‘muscle memory’ to execute their job functions in a calm and competent manner. As a result of the simulator’s portability and ease of access, trainees can receive instruction immediately prior to performing crucial work in the field. Unlike traditional OTS platforms, IFS systems can be made future-proof so they adapt to equipment or process changes occurring within a dynamic production environment. By employing the latest cloud-based technologies, users can easily keep the digital twin of their processes up to date, so it accurately represents current plant operating conditions. Some IFSs include robust features such as asset libraries where users can modify 3D models as their plant processes evolve and lesson editors allowing trainers to build their own lessons without the need for any coding. Experience has shown that immersive field simulation is a preferable method of training for the current generation of digital-native workers, who are taking over many complex job responsibilities in the plant. A 3D-immersive approach with VR helps to improve knowledge retention and fill the skills gap between experienced employees who are retiring in large numbers and younger workers who must gain know-how in a wide range of critical operations.

Real-world experience One of the world’s largest LNG producers has found IFS technology improves upon traditional training tools and methods, which studies show are not always useful in making industrial personnel better at their jobs. Virtual reality learners are four times faster to train than in the classroom. The LNG firm had thousands of hours of experience using standard OTS process and asset models to prepare panel operators to perform their job functions. The company recently added new immersive, 3D capabilities to its OTS system and extended those capabilities to operators in the field. Control room personnel and field operators can now train at the same time and take advantage of a true end-toend instructional experience that replicates their facility’s real-world environment.

Instead of beginning with a review of SOPs, field staff members can proceed directly to guided lessons that include the procedures along with appropriate actions to be taken at the asset location. This approach has been found to improve knowledge retention as well as the ability to apply training experiences to actual job functions. The LNG producer has utilised the IFS solution to prepare its workers to handle normal operating conditions, as well as respond to abnormal situations such as gas leaks and fires that cannot be staged in a safe manner in the actual plant. The simulator presents these situations using high-fidelity models that are appropriate for both panel and field operators. Within this training scenario, all changes made by field operators to control systems or equipment assets are visible to the panel operators, and vice versa. Adjustments to a valve by a field technician in the virtual world, for example, are bidirectional and reflected in the process and asset mathematical models and displayed on the panel operator’s screen. The integrated outcomes and performance of the two groups is subsequently assessed and graded together as part of a single plant operations team. For the LNG producer, the IFS allows training to be conducted anywhere and at any time; rather than travel to a classroom location, employees can utilise the system from home or another remote location and fully participate in training simulations. This solution was effective during on-site restrictions or travel restrictions and allowed the company’s operator training programmes to continue without any undue delay or disruption.

Conclusion The drive for higher efficiency and greater safety in an ever-more-stringent regulatory environment is causing LNG facilities to consider new ways to improve the training of their personnel. A new generation of immersive field simulation can be used for asset digitalisation and to create an intelligent workplace while optimising safer field operations. This type of simulator incorporates virtual reality to provide plant operators and field technicians with a detailed, accurate environment to train on both normal and abnormal operating conditions. The IFS solution improves training times beyond traditional classroom-based learning and minimises situations that can result in operational downtime.

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Jim Chappell, AVEVA, USA, explains why digital twin technology can be a game changer when it comes to maximising LNG operations and boosting plant profitability.

overnment policies and operating company sustainability initiatives encouraging transition to clean energy have led to an increase in demand for natural gas, leading to tight market conditions. However, with adequate supply sources in most producing regions around the world and a need to deliver increasing amounts of LNG to regions short in natural gas, there will be significant opportunity to fully utilise the maximum capacity of liquefaction plants when markets favour suppliers. To stay ahead of the game, maximising LNG production at lower cost is imperative for companies to sustain profitability in this competitive market.

Challenges Although an LNG process plant is designed to operate optimally at a design production level, any variations in feedstock and fuel gas composition, changes in ambient conditions, and degradation of operating assets can impact throughput and optimal processing conditions, affecting its operating profit. Stricter regulations on environment, product quality, and safety have also led to an increase in operating costs, adding pressure on profit margins. Compounding the challenges, the volatile boom-bust business cycle

environment has caused a shortage of skilled operators in most plants, affecting productivity and safety performance. Having skilled and competent operators is key to reducing incidents and plant outages.

Leveraging a digital twin strategy The concept of a process digital twin is not new and it has been around for more than a decade. A process digital twin is a first principles replica of a chemical process with heat exchangers, turbines, pumps, compressors, and other equipment that enables modelling of process and control, and monitoring of equipment performance. It is the foundation to optimise LNG production and to detect equipment problems before failures occur, uncovering new

Figure 1. Reducing process variability and operating closer to the optimum points.

opportunities for process improvement while reducing plant downtime. Only in recent years, the advancement in technology – cloud platform, analytics, and computing power – and greater clarity on the use cases have accelerated the adoption of digital twins. LNG companies are starting to realise the benefits of digital twin technology that enables unprecedented real-time insights of their operations, elevating their operational excellence to the next level: a 0.1% increase in production due to improved process and operating efficiency can easily yield several millions of dollars in additional annual revenue.

Building a digital twin To build a digital twin for an asset, description tags and data – such as geometry, layout, connectivity of key components, and process data – must be created around the asset. The common set of data and information is then shared across departments throughout its asset and operations lifecycles – from engineering, to procurement, to construction, to commissioning, and operations. As the operational life continues, the digital copy is updated in real-time with current data and engineering information to optimise maintenance and operational activities. Engineers and operators can quickly access critical up-to-date engineering information and operating data around the assets. Now, engineers can access information and health of an asset easily through tag searching. Previously, the tasks would have taken considerable time and effort, leading to missed opportunities in addressing any flagged issues before failures that result in production outages. In addition, the process data can be fed into simulation and analytics to optimise the liquefaction process, reduce unplanned downtime, and maximise LNG production.

Enabling simulation and analytics in LNG trains

Figure 2. Real-time process optimisation approach.

As converting natural gas to a liquid in an LNG train involves a few processing steps from removal of impurities to liquefaction, an integrated approach is key to maximising LNG production. Operating constraints, including pumping capacity, refrigeration availability, pressures, temperatures, and variables such as feedstock composition and ambient temperature must be modelled and optimised with maximum throughput as the final objective. The following five-step approach enabled by a digital twin to maximise LNG production is fundamental to improving performance and boosting profitability.

Steady state and dynamic simulation models of process and controls

Figure 3. Data reconciliation for performance monitoring.

November 2021

At the FEED stage, steady-state simulation models of the plant process can be created to optimise LNG plant design. Engineers and operators can perform engineering studies – such as simulation of various heat exchanger, distillation column, and flare designs – to identify design changes that will significantly increase the plant output and the reliability

and safety of plant operation. With a unified simulation platform, the evolution from a steady state to dynamic simulation can be achieved easily. Dynamic simulation can be performed on these models to validate process design such as relief and flare systems and controls, enabling engineers to optimise design and reduce CAPEX. Engineers can perform engineering studies to identify design changes that will significantly increase the plant output, to understand process limitations, heat exchanger performance, and reliability and safety of plant operation. In addition, the dynamic simulation can enable effective troubleshooting, control system checkouts, and comprehensive evaluations of standard and emergency operational procedures to shorten time requirements for safe plant start-up and shutdown. This forms the backbone of an operator training simulator (OTS) where operators can be trained on procedures to address real experiences to perfection in a safe and controlled classroom environment before they are deployed to the plant. Major LNG operators have already reaped significant benefits using simulators as part of their enterprise-wide training programmes, enabling them to reduce training costs and time to proficiency by up to 50%.

Reduce process variability Advanced process control (APC) has been used widely in cryogenics operations to stabilise operations and reduce process variability due to varying feedstock rates and composition, ambient temperature, product demand, and

changing equipment conditions. It does so by adjusting the process conditions in real-time to handle those changes in feedstock rate and quality while maintaining the plant operations within the constraints – pressure, temperatures, and horsepower availability. Reducing process variability not only improves product quality, but also enables the process to be operated closer to its optimum points, reducing energy consumption and improving yield. For a typical LNG plant, applying APC can yield a 3 - 4% increase in throughput, yield, and a 2 - 5% lower energy consumption (million Btu/t). Other benefits include extended equipment life, reduced operator intervention, and improved plant stability and operation.

Process performance monitoring In an LNG process, heat exchangers handle complex heat transfer for the liquefaction of gas and are critical to production. Equipment efficiency and instrumentation accuracy should be monitored constantly as degradation of the heat exchanger can lead to inefficiencies and production slowdowns. Having an integrated model to monitor all rotating equipment, distillation towers, and heat exchangers not only analyses the interactions of various plant components, but also provides additional metrics on efficiency and utilisation. Reconciliation of material, energy, and equilibrium balances around a piece of equipment or entire plant can also identify bad instrument readings and pinpoint material and energy loss locations, effectively acting as a data

activities such as heat exchanger cleaning studies.

The last mile to close the performance loop

Figure 4. Closing the performance loop.

validation layer. This is valuable information that cannot be measured directly, but is calculated based on first-principle, rigorous models that have been tuned to actual plant condition.

Predictive analytics to monitor equipment health As LNG trains are extremely cold during operation, any planned or unplanned shutdown will take longer to restore full production rates than equipment operating near ambient temperatures. Therefore, minimising plant shutdowns is key to improving production. Predictive analytics enables modelling of rotating equipment performance – such as pump, compressor, and turbine – using advanced pattern recognition and machine learning algorithms to identify and diagnose any potential operating issues days or weeks before failures occur. Operating models including past loading, ambient, and operational conditions are used to create a unique asset signature for each type of equipment. Real-time operating data is then compared against these models to detect any subtle deviations from expected equipment behaviour, allowing reliable and effective monitoring of different types of equipment with no programming required during set-up. The early warning notification allows reliability and maintenance teams to assess, identify, and resolve the problems, preventing a major breakdown that can cost companies millions of dollars in production slowdowns or even stoppages.

Real-time process optimisation While APC sets the optimal process conditions based on empirical, linear dynamic models, it is difficult to resolve non-linear relationships that may impact the plant throughput. Real-time process optimisation – either open-loop or closed-loop – considers current process performance, process constraints, feedstock, mixed refrigerant composition, and throughput to determine the best set of operating targets based on satisfying material and energy balances. These targets can then be made available to operators for implementation in their control systems, or they can be automatically downloaded to APC systems directly. In addition, the same performance and optimisation models can be used to conduct offline optimisation and feasibility case studies, enabling plant engineers to plan operations. Engineers can run the same models to analyse various operating scenarios to determine optimal configurations in the plant, to analyse constraints/bottlenecks that impact production, and to evaluate the impact of maintenance

November 2021

Insight and process optimisation advisory do not create value until action is taken to adopt and implement the new optimised set points. Accurate, reliable, and timely information must be channeled not only to the subject matter experts but also to executives who are empowered to make operating decisions that impact the bottom line. This is where enablers such as workflow management are critical to ensuring that actionable data is executed upon to seize any profit improvement opportunities. The right information is delivered to the right person at the right time. No matter the stage in a digital journey, implementing the solutions in a logical step-wise fashion, as economics and resources allow, enables progressive value building as additional solutions are implemented, allowing each solution to pay for subsequent implementations.

Conclusion The digital twin framework enables operational excellence by helping LNG operators and owners to take a modelfocused approach that quickly turns the significant amounts of data already available into information and wisdom that generates business value. The breadth and depth of products and services in AVEVA’s portfolio is designed to offer greater choices and flexibility to solutions architects in designing a path to maximise LNG production that best meets the needs of clients in a methodical and extensible manner. Ultimately, it is a journey to continuous improvement, and what the company has learned from successful customers has been outlined in the following: z Find a vendor uniquely qualified to implement operational excellence solutions: Extensive experience in the process industries. Numerous years of applicable optimisation expertise. Commitment to each customer’s continuous operational excellence. z Choose integrated technology that promotes: Improvements through an asset’s lifecycle including process design, simulation and training, and optimisation. Operational excellence through continuous improvement, actionable intelligence, and workforce optimisation while managing and lowering risk. z Implement projects as economics allow: Services team supports client’s efforts through collaborative project development, ongoing engagement, co-operation, and partnership. Contacting an AVEVA consultant with field experience in planning and implementing analytics architecture can help operations management teams to begin or continue their journey to maximum effectiveness by improving their producing asset’s availability, performance, and quality while ensuring environmental and safety compliance and ultimately improving the business bottom line.

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he design of the Dunkirk LNG terminal began in 2006, followed by a five-year construction period which started at the end of 2011. The terminal was commissioned in July 2016 and started commercial operations on 1 January 2017. With an annual throughput capacity of 13 billion m3 and a total storage capacity of 600b000 m3, it is one of the largest LNG terminals in Europe. From the very beginning of the project in 2006, there was a strong focus on a safe, durable, maintenance-friendly design with limited operational constraints and no emission as a result of the recovery of warm water from a nearby nuclear power plant.

An ideal location Dunkirk LNG has a distinctive positioning, it is the only zero-emissions terminal providing a direct access to two gas markets located in the heart of Northwest Europe (France and Belgium) and offers a bundled service including unloading, reloading, storage, and regasification. This can be

complemented by a large panel of add-on services bookable throughout the year such as small scale LNG related services (truck loading, small scale reloading, etc.). This allows shippers to optimise their portfolio and respond quickly to changing market dynamics. Beyond France and Belgium, Dunkerque LNG presents a privileged gateway to the European LNG market. The French and Belgian gas systems are very well connected to the other neighbouring European countries through non-congested interconnection capacities. In this respect, France is ideally positioned both along the main North-South European gas route which serves South Europe’s countries (Italy and Iberia) and along the main West-East

Cedric Vandenbroucke, Dunkerque LNG, France, details the truck loading services available at the Dunkirk LNG terminal.

Figure 1. Aerial view of the West side of the Dunkirk LNG terminal.

European gas route which serves North West Europe’s countries (Belgium, UK, and Germany), opening a large and deep market for LNG volumes imported through the Dunkirk LNG terminal.

What is the vision of the Port of Dunkirk in terms of carbon neutrality? In Dunkirk, the greening of the Port was initiated very early, in the 2010s, due to the closure of refineries, then seen as an opportunity to reflect on the energies of the future and to anticipate the development of less carbon-intensive energies, even carbon-free. Following on from these reflections, several major projects have emerged. The objective is to make the Dunkirk Port area the cornerstone of the supply of renewable energies in the Dunkirk territory. As a result of its actions, the Port intends to accelerate its greening in order to achieve a 40% reduction in greenhouse gas emissions in 2030 (compared to 1990) and carbon neutrality in 2050, which are the two objectives of the French government to fight against climate change.

How is this objective achieved? In June 2017, Dunkirk Port and Dunkerque LNG signed a partnership agreement for the development of an LNG truck loading station. Through this agreement, Dunkirk Port accompanied Dunkerque LNG in its commitment to build and then operate the loading station as part of a larger project to set up an LNG bunkering service by land and sea at the Port of Dunkirk, thus offering a wide range of LNG fuelling possibilities to the market.

How did the commissioning of the truck loading station go? The LNG truck loading station at the Dunkirk LNG terminal has been in service since November 2020. It immediately operated optimally, and from May 2021 the company was able to start operations with the terminal’s LNG suppliers. Dunkerque LNG took another step forward when the temporary closure of a European terminal last June caused the market to seek other sources of supply. The company addressed its responsibility towards the value chain. Between May and July 2021, it achieved an average utilisation rate of 80%. The terminal teams mobilised to meet customer demand, in particular by offering an assisted service 24bhours a day, six days a week. The teams were able to manage contingencies and ensure rescheduling in order to optimise the use of the station. In total, as of 1bNovember 2021, 700 loads have already been completed, including 630 since May alone, thus demonstrating Dunkerque LNG’s responsiveness to the market.

What services are available?

Figure 2. A truck is positioned at the loading bay.

Dunkerque LNG’s truck loading bay has a capacity of 3000bslots per year. Assisted loading services are offered from Monday to Friday from 5.30 am to 6.45 pm (last slot) and self-loading services from Monday at midnight to Saturday 6.45 pm (last slot). Assisted loadings are performed with the assistance of an operator and self loadings are those performed by the drivers themselves without assistance. To be able to use an unmanned slot, the driver needs to perform three assisted loadings with specific training from the operator. At the same time the driver needs to follow an e-learning training. The Dunkirk LNG terminal is the first in Europe to offer an autonomous tanker truck loading service. After this, they can load on their own, especially at night. This innovation makes it possible to offer a service to the market at a more competitive price.

What is the process for trucks to be approved at the truck loading bay?

Figure 3. A driver manipulates the loading arms.

November 2021

In order for trucks to be approved, transporters have to send all documentation prior to the loading in order for a compatibility study to be performed three weeks before the loading. This documentation is shared on a secure online platform; every transporter has access to their account and can upload and update all relevant documentation regarding trucks and drivers.

Our truckloading station is ready to welcome new customers !

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What are customers doing with this LNG? Supply by tanker truck, or imported LNG, is a rapidly expanding market across Europe. This activity makes it possible to deliver fuel to industrial sites which are not connected to the gas network and also to deliver service stations which sell LNG in the form of fuel for heavy goods vehicles.

What is the next step for the company’s truck loading services?

Figure 4. A truck passes in front of tank 3.

How does loading work? The station is automated both in terms of operations and safety – almost no manual handling is necessary except for the connection and disconnection of the arms. The loading operation as well as the sequences before and after loading such as the preliminary leak test, the depressurisation of the tank, and the emptying of the arms after loading are managed from the touch screen. The loading is carried out with an articulated arm which allows the operator or driver to handle it easily.

In October, a call to market was launched for the sale of the remaining annual capacities. Dunkerque LNG also offers its customers monthly contracts with flexible terms. The station has already captured part of the market, especially in the north of France. Due to its location, the station has already captured a large part of the market from the Paris region to the north of France. In accordance with the regulations, tankers which do not cross borders can load 44bt of LNG instead of 40 t. The company is attentive to market developments in order to continue to meet the expectations of its customers.

Conclusion Haulage companies, as well as remote industry, increasingly choose LNG as alternative low emission fuel. Dunkerque LNG remains a key player in LNG in Europe serving a greener chain. Its infrastructure is designed to guarantee a source of supply in a booming market context. The commissioning of this loading bay brings a new source of supply to the northern European market with innovative services at a competitive price.

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Prasanth Sreekumar (UAE), Scott Sutherland (USA), and Stephan Natter (Switzerland), Endress+Hauser, explain why the bunkering industry is deploying mass flowmeters to improve efficiency.

NG bunkering is the process of providing LNG to a marine vessel for its consumption. LNG offers benefits in reducing the emissions associated with burning traditional bunker fuels such as heavy fuel oil (HFO) and marine gas oil. International Maritime Organization’s (IMO) regulation IMO 2020 has accelerated the use of LNG as a fuel in the shipping sector and the investments continue to develop. LNG bunkering facilities can be classified as shore-to-ship, land-to-ship, and ship-to-ship

bunkering. Compared to traditional bunkering with HFO, LNG bunkering offers unique challenges due to cryogenic conditions and boil-off gas (BOG). Traditionally, static level measurement devices have been used onboard bunker tankers to determine the delivered bunker fuel quantity. Recently, mass flowmeters (MFMs) have become increasingly popular. Some ports such as Singapore

have made the measurement by MFM mandatory. The dynamic flow measurement by MFM offers distinct advantages over static type level gauges such as direct mass flow which makes the calculation from level over volume and temperature obsolete. MFMs provide instant information about the quantity delivered to reduce the operation time significantly. Process information is available at any time for a maximum of process transparency. Flowmeters offer multivariable measurement and the highest level of accuracy under varying process conditions.

Measuring LNG bunker deliveries with mass flowmeter

Figure 1. Left: A pilot-E probe installed on the main LNG transfer line from an LNG bunker ship. Right: Cross section showing the direct flange mount of the pilot-E probe and the immersion of the tip of the probe into the flowing LNG stream.

MFMs are known to be extremely precise, flexible in installation, and require minimum maintenance. MFMs have been used in custody transfer type applications in the oil and gas industry for decades. It has become a logical consequence to also deploy MFMs for LNG bunker operations. Endress+Hauser offers dedicated MFMs which can handle the cryogenic conditions with the precision known from standard hydrocarbon measurement. This makes MFMs an ideal flowmeter type for custody transfer applications such as LNG dispensers, loading/unloading of LNG in terminals, and LNG bunkering from truck, terminal, or ship. Type testing and certification through notified bodies reduces the scope of testing in the installation to a minimum. Calibration on LNG is not required. Flowmeter health status can be monitored by the onboard feature ‘Heartbeat’ without removing the flowmeter from the line. Heartbeat technology provides a continuous health check of the flowmeter, ensuring key parameters are performing within specification at all times. Deviation from the factory reference values will trigger warnings as per NAMUR NE 107. This diagnostic function is available as standard with the company’s Heartbeat-enabled flowmeters.

Measuring LNG composition with Raman analyser

Figure 2. Mass flowmeter (MFM) installed on a traditional oil bunker barge.

Figure 3. Promass Q in LNG service.

November 2021

Raman spectroscopy is an optical technique capable of providing composition information for both gaseous and condensed phase mixtures. Laser light interacts with molecular vibrations of the components of the gas sample, with some of the incident light losing discrete amounts of energy to excite vibrational modes in the molecules of the sample. The resulting Raman scattered light has a different colour than the original laser light, and each different type of molecule generates one or more colours that are unique to that molecule. The composition of the gas has been effectively encoded into different colours and intensities of light. Kaiser Raman analysers use lasers in the visible and short-wave near-infrared region that are compatible with transmission along low-cost fibre optic cables. This allows fibre-optically coupled probes to be placed hundreds of meters from the main analyser. For the analysis of LNG, a cryogenic probe, such as the Kaiser Pilot-E probe, is inserted directly into the LNG sample, either in the main transfer line, or in a bypass loop1,2. The light is collected by the fibre probe at the point of measurement in the sample pipe and is transported back to the analyser along the fibre optic cable, eliminating sample lag times that are inherent in the use of heated gas sample

transport lines. As an in-situ measurement, no sample is removed from the main line or transported from the measurement point to the analyser. By measuring the sample in the liquid phase, no potentially explosive gases are removed from the pipe at the sample tap location, nor transported to the analyser, greatly enhancing the safety of the personnel working on or near the Raman analyser or working with the Raman probe at the sample tap. Figure 4. Typical installation of a Raman analyser for LNG Figure 4 shows a diagram of a typical Raman analyser measurements. installation, which consists of a Raman analyser base unit that contains the laser source, all electronics and power monitoring of the bunker delivery. The process progress can supplies, detection module, and either an embedded or an be viewed at any time. The bunker operation is completed by external controller and user interface. The optical probe can printing the bunker transfer ticket. All historical process data be located up to 500 m from the base unit, connected to the are stored on the bunker metering system. Optionally, the base unit by an industrial electro-optical cable. bunker operation data can be transferred to the ship system Figure 1 shows the details of a typical Raman probe for further usage. installation on an LNG transfer line attached via a direct Endress+Hauser is providing the LNG bunker metering flange mount. The diagram illustrates how the probe passes system as a standardised engineered unit. For the through the access tee and pipe insulation and into the main convenience of the operator all components are built in a transfer line so that the tip of the probe is immersed in the cabinet and are easy to access for operation and service. flowing LNG. Environmental and security requirements are fulfilled by LNG bunker metering system design and are certified by notified bodies to ensure the After the successful deployment of bunker metering systems compliance to the respective custody transfer standards. for oil, Endress+Hauser developed a bunker metering system References for LNG, comprising of quantity measurement for LNG and BOG using MFMs, LNG analysis through a Raman analyser, and 1. SNYDER, J., CAPERS, R. M., FAIRCHILD, R.C. AND WIEGAND, P. M., ‘Taking a closer look…’, LNG Industry the calculation of calorific value, density, methane number, (Autumn 2009). and energy through robust flow computers. 2. SUTHERLAND, W. S., ‘Laser Precision Measurement’, LNG The LNG bunkering system of Endress+Hauser provides an Industry (March 2019). intuitive HMI which allows the operator to safely initiate the

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s the world’s top bunkering hub, Singapore pursues a long-term commitment to a maritime decarbonisation agenda in building a sustainable global hub port. The Maritime and Port of Authority of Singapore (MPA) signed a Memorandum of Co-operation with the Port of Rotterdam Authority and Japan’s Ministry of Land, Infrastructure, Transport and Tourism to form the Future Fuels Port Network last October. The port network will develop a roadmap on adopting clean marine fuels in support of decarbonisation. Besides research and development, the three parties to this network will also co-operate on possible joint bunkering pilot runs with identified shipping lines to drive decarbonisation efforts in the shipping industry. Spearheading green growth and sustainability in Singapore’s maritime industry, MPA sees LNG as a viable and scalable marine fuel in the maritime sector’s transition to a low-carbon future. LNG plays a vital role in MPA’s multi-fuel decarbonisation strategy to reduce the impact of shipping on the environment.

MPA is focusing on the development of four key elements in the LNG supply chain: bunker supply, bunkering infrastructure, demand promotion, and bunkering standards.

Growing LNG bunker supply and developing bunkering infrastructure To establish an end-to-end supply chain for LNG bunkering in the Port of Singapore, MPA awarded LNG bunker supplier licences to FueLNG Pte Ltd and Pavilion Energy Singapore Pte Ltd in 2016. Since then, MPA has been working closely with its licensees to ensure an adequate supply of LNG bunker and to develop LNG bunkering infrastructure with the capacity to serve ocean-going vessels. For instance, MPA awarded a total of S$6 million to co-fund the building of two LNG bunker vessels for regular ship-to-ship LNG bunkering in the Port of Singapore. The first of these two vessels, FueLNG Bellina, arrived in Singapore in October 2020. The vessel undertook Asia’s first ship-to-containership LNG bunkering

operations in March 2021. It has since completed 18 ship-toship LNG bunkering operations. Singapore now possesses an LNG bunker supply capacity of up to 1 million tpy, which translates to approximately 300bship-to-ship LNG bunkering operations annually. As of 1 August 2021, over 420 truck-to-ship LNG bunkering operations had been safely carried out in the Port of Singapore. They included LNG bunker supplied to domestic harbour craft in Singapore’s port waters since 2017. With growing orderbooks for LNG-fuelled vessels, MPA awarded a third LNG bunker supplier licence to Total Marine Fuels Pte Ltd in February 2021 to prepare for a foreseeable increase in demand for LNG bunker. Its five-year licence begins from 1 January 2022. In addition, to enhance LNG storage and supply infrastructure in the Port of Singapore, MPA introduced port dues concessions in July 2021 to support the deployment of floating storage units (FSUs) and floating storage regasification units (FSRUs) for LNG bunkering (and breakbulk) activities in Singapore. These concessions entitle FSUs and FSRUs to a 50% discount in port dues (up to S$0.6bmillion/y per craft for five consecutive years).

MPA continues to work with interested parties to grow the LNG bunkering ecosystem in the Port of Singapore.

Promoting LNG bunker demand In creating demand for LNG bunker, MPA implemented a series of schemes to grow the domestic adoption of LNG as a marine fuel. For instance, it awarded S$14 million of co-funding grants to build seven LNG-fuelled tug boats and bunker vessels from 2016 to 2018. Additionally, MPA offers incentives under the Maritime Singapore Green Initiative to attract ocean-going vessels to call at the Port of Singapore for LNG bunker. Vessels that adopt LNG fuel receive a 25% discount in port dues during their stay under the Green Port Programme. They also receive an additional 10% concession in port dues when they tap on the services of LNG-fuelled harbour craft during their stay. Separately, under the Green Ship Programme, Singaporeregistered vessels that adopt LNG fuel receive rebates on Annual Tonnage Tax and discounts on their Initial Registration Fees. To promote the global adoption of LNG as a marine fuel, MPA co-operates with 10 other port and maritime administrations to establish a network of LNG bunker-ready ports worldwide. These ports, which are parties to a joint Memorandum of Understanding, also co-ordinate with international bodies and port operators on the provision of LNG bunkering services. In this way, this port network grows industry confidence in the availability of LNG supply across key shipping routes.

Developing bunkering standards

Figure 1. Singapore’s first ship-to-ship bunkering of an LNGfuelled oil tanker took place between FueLNG Bellina and Pacific Emerald.

While growing demand and ensuring an adequate supply of LNG bunker, MPA worked closely with industry partners and other government agencies to put in place effective LNG bunkering standards and procedures that facilitate safe and reliable LNG bunker delivery operations in the Port of Singapore. Launched in 2017, the Technical Reference for LNG bunkering (TR 56) provides a transparent technical framework for conducting LNG bunkering operations. It covers the requirements for bunker custody transfer, procedures and safety distances, as well as competency requirements for personnel. These standards and good practices that guide LNG bunkering operations in Singapore mitigate health and safety risks, enhance operational efficiency, and increase the overall trust and confidence of LNG bunker buyers and suppliers in conducting bunkering operations in the Port of Singapore.

Becoming a leading LNG bunkering hub

Figure 2. CMA CGM Scandola was the first containership to carry out ship-to-ship LNG bunkering operations in Singapore and Asia.

November 2021

Singapore aims to become the leading LNG bunkering hub in Asia and the world. To realise this ambition, MPA works together with market players in the bunker supply chain to offer safe, efficient, and reliable LNG solutions for global shipping customers in the Port of Singapore. As part of its decarbonisation agenda, MPA continues to explore credible LNG solutions such as drop-in fuels for the bunker supply chain as technology for bio-LNG and liquefied synthetic methane develops and matures. It consistently seeks industry feedback to address the needs of players in Singapore’s LNG bunker market and ensures that its services are safe, fair, and competitive.

achine condition monitoring is not just for detecting wear and erosion of components in turbomachinery as they reach their lifetime limits. It is also important for detecting incorrect assembly or component quality issues during commissioning or start-up after an overhaul. A comprehensive monitoring strategy with advanced measurement techniques and diagnostic monitoring tools such as alarm trends can detect incipient faults at an early stage of development for these types of

machines. Even if early fault detection is achieved, identification and diagnosis of the fault is not always evident, so diagnostic expertise is also needed in some cases. This technical case study demonstrates two examples of this; how a bearing manufacturing fault on a critical air compressor was detected early but the diagnosis was delayed just before the warranty ran out, and how an improperly installed spur gear on the propane compressor gearbox gave early fault

detection using a little known but useful function called alarm trend. The fault could have been detected even earlier using other measurements.

Case 1 – bearing with manufacturing fault detected on instrument air compressor A long-term vibration trend was observed by the end user on the first stage inboard bearing of the compressor since commissioning, which over time eventually exceeded alarm limits at approximately the same time the machine warranty was close to expiring. The monitoring system supplier was asked to quickly diagnose this fault. The monitoring system data was remotely accessed and a bearing fault was rapidly diagnosed. A root cause analysis was also carried out with the full co-operation of the original machine manufacturer, who subsequently replaced all the bearings under warranty.

Fault detected on compressor during warranty The instrument air compressor serves a critical role in an LNG plant. It provides clean, dry air that is used in a range of control and shutdown valves. There are three oil-free centrifugal compressors per train at the LNG plant in this case study. The instrument air compressor (described in Table 1 and shown in Figure 1) is driven by a motor though a gearbox using tilting pad journal bearings. The units were

Table 1. Instrument air compressor details Parameter

Value

Type

Centrifugal

Stages

Three

Power

90 kW

Flow capacity

200 tpd

Outlet pressure

10 bar

Speed

50 Hz

relatively new and still under warranty at the time of this case study.

Comprehensive monitoring strategy All the instrument air compressors at the LNG plant are instrumented, both for protection and condition monitoring, as shown in Figure 1.

Early detection of a developing fault The bandpass vibration level on the inboard bearing of the first stage impeller had exceeded the alert alarm limits, so special attention was given to monitor its progression. As seen in Figure 2, the vibration trend had been increasing steadily for approximately one year. After a few months the vibration level subsided again, but after two years since the upward trend first started, the vibration level exceeded the alert alarm limits once again. It was then decided to shut down the machine to investigate the problem. After a quick investigation nothing was found that required immediate attention, so the compressor was put back into service. The vibration levels remained above the alert alarm limits, so a series of tests were undertaken to try and identify the problem (e.g. changing the lubrication). The customer was not able to reduce the vibration levels, so the monitoring system supplier was asked to look into it and evaluate the problem. As the vibration levels were increasing towards the ‘danger’ alarm limits, the machine was shut down again.

Late stage diagnostic analysis One of the first observations in the spectrum plot shown in Figure 2 was that the third order harmonic of the running speed from the inboard bearing of the first stage impeller started to increase more than two years before the shutdown. The bandpass vibration level increased for a while, stabilised and then decreased, and then increased again. This could be the result of a bearing fault that initially smoothed itself out for a while and then the fault redeveloped again. The DC vibration displacement (not shown) showed a more or less linear change in shaft position during more than three years. This indicates gradual wear of the bearing. Because the compressor was still under warranty, the manufacturer was contacted to investigate the bearing.

Unusual fault mechanism requires a root cause analysis

Figure 1. Sensor configuration of the instrument air compressor. There are also a number of imported process parameters from this machine train not shown here (these include suction and discharge pressure and temperature, and motor current). In this case study, the bearing where high vibrations were detected is shown in red. Photo: Fretting on the first stage impeller bearing, presumably caused by a manufacturing defect.

November 2021

The monitoring system successfully detected a fault at an early stage of development while the compressor was still under warranty. The monitoring system in fact played a vital role here since four harmonics were individually monitored. The vibration response of different machine faults manifests itself with different

harmonics, and in this case, it was the third harmonic that gave the earliest indication of a bearing fault. The fault was slow to develop, so long-term trend capability was necessary. Diagnostic assistance provided by the monitoring system supplier was able to determine that it was a bearing fault. The compressor manufacturer was also contacted, and after disassembly, they determined that fretting on the first stage bearing (Figure 1) was due to poor bonding of the bearing surface as a result of a manufacturing defect. This evaluation is based on the fact that the bearing vibration levels had already started an upward trend not long after commissioning. It is not fully understood why only the third order was excited for this condition. Further investigation found a scratched bearing surface for the second stage impeller, which was most likely due to a foreign object that entered the bearing during commissioning. Burnt oil on the bearing surface from the third stage impeller was also observed, which was most likely due to carry-over water ingress.

Figure 2. Left: The third order harmonic dominates the vibration response in this spectrum plot (FFT). The 460 Hz signal component from a gearbox pinion remains unchanged, thus precluding the possibility of a fault with this portion of the gearbox (higher frequencies not shown in this plot). Right: After repair, the third order harmonic disappears from the spectrum (constant percentage bandwidth – 6%).

Table 2. Measurements for monitoring air compressor impeller bearings. Because of limited access, an accelerometer is used for monitoring the second stage impeller bearing instead of a displacement sensor Sensor

Measurement name

Frequency range (Hz)

Detection

Relative radial vibration (μm)

Bandpass

10 - 5 k

RMS & P-P

First and third stage impeller bearings

DC – shaft position

–

Half magnitude – bearing stability

–

RMS & P-P

First order vector – magnitude and phase

–

RMS & P-P

Second, third, and fourth order – magnitude –

RMS & P-P

Constant percentage bandwidth (CPB)

16.3 - 1.03 k

RMS

DC (μm)

–

Bandpass (mm/s2)

10 - 5 k

RMS

Relative axial displacement (μm) Thrust bearing

Absolute radial vibration Casing above second stage impeller bearing

Repair and postrepair results The manufacturer replaced all the bearings under warranty and the intercooler drain lines were checked for proper draining of water to avoid carry-over. The inlet air filter was also thoroughly inspected for damage and openings. After repair, Figure 2 shows a spectrum plot (constant percentage bandwidth measurement of 6% centre frequency) where the third order harmonic for the most part disappears.

Case 2 – detection of improperly assembled gearbox of the propane compressor The rapid deterioration of an incorrectly mounted spur gear gives little lead time to maintenance. In this case study, early fault detection was achieved by using an automatically calculated alarm trend, but even earlier warning could have been achieved by using other vibration parameters.

Other measurements – same as for displacement sensors except in mm/s

Propane compressor train The propane compressor train in this case study consists of a 75 MW Frame 7 gas turbine driving an axial compressor via a gearbox, as summarised in Table 3. The compressor train is unique in that there is also a variable speed starter motor/generator at one end of the train that is used to help start the gas turbine, which afterwards generates energy to the grid once the gas turbine is operating at speed. Moreover, the single casing centrifugal compressor itself is also complicated in that it processes propane at four different pressure levels to supply refrigeration to the incoming natural gas and pre-cooling of the mixed refrigerant in the LNG liquefaction process. The gearbox, like the rest of the propane compressor train, is extensively instrumented for protection, condition, and performance monitoring. As shown in Figure 3, X-Y displacement sensor pairs are mounted on each of the bearings of the gearbox.

November 2021

Observations and analysis On 15 February, the following condition monitoring measurement indicated a developing fault on the propane compressor gearbox: constant percentage bandwidth filtered spectrum (CPB). It was the running speed portion of the CPB measurement (Figure 4) that generated an alert alarm using the alarm trend function. The alarm trend was set up for a Table 3. Propane compressor details Parameter

Value

Type

Axial

Stages

Four

Power

75 MW

Flow capacity

170 000 m3/hr

Highest outlet pressure

30 bar

Lowest outlet temperature

-31˚C

Speed

3600 rpm

10-day lead time to the danger alarm (shutdown). The CPB indicated a pronounced 1× vibration trend as shown on the left of Figure 4. Although not set to alarm limits, the first order vector measurement data (1× magnitude and phase) was also analysed as a follow up. The 1× vibration magnitude portion of the vector measurement gave a similar lead time before shutdown to that of the CPB measurement, but the phase portion of the measurement started changing even earlier as shown in Figure 4. It would have given over two weeks advance warning. By comparison, the overall vibration measurement (not shown) gave indication of a trend similar to the CPB and vector magnitude measurements since the 1× vibration frequency was directly related to the fault, which was the predominant frequency component in the entire spectrum. But as a protection measurement, the alert limits are set too high for condition monitoring purposes so there is little lead time warning with this measurement.

Post-repair results When the gearbox was disassembled, the output shaft bull gear was found to be improperly mounted on its bearings. It was this fault that caused a running speed vibration amplitude increase and phase change. When the gearbox was repaired and reinstalled, the vector amplitude vibration went down and the phase stabilised. Although the 1× vibration measurements detected the developing fault with advance warning, it was the first order phase measurement that could have provided the earliest detection capability and thereby the longest lead time to service, if it was used. Regardless of which measurement is monitored, a rapidly developing fault can be quickly detected before the alert alarm limits are exceeded by using the alarm trend function. Either way, for faults that have a non-linear development, such as an improperly mounted gear, the CPB and vector measurements can detect these faults with sufficient lead time to plan the necessary maintenance.

Conclusion Quality issues or incorrect assembly faults of machine components can complicate fault detection and/or gearbox. diagnostics, so comprehensive condition monitoring functionality is a must for critical machines. Moreover, outside expertise services can be useful as well for difficult diagnostics. For fast developing faults, maximum lead time warning is crucial for cost-effective maintenance planning, therefore in addition to specialised diagnostic condition monitoring techniques, Figure 4. Left: The CPB showing the running speed vibration increasing up until shutdown. The 2× and 3× orders of the running speed are also shown. Right: The first order phase is visible when automatic alarm trend the vibration amplitude is high enough, as shown in this long-term trend. Around 10 February the functionality is also phase begins to change significantly. The first order vibration magnitude upward trend did not important for early fault start until after 15 February. detection.

Figure 3. Sensor configuration for the propane compressor

November 2021

Roman Bershader, Independent Compressor Consultant, USA, details the best practices for compressor surge and choke protection in the LNG industry. ver the past four decades, LNG has established itself as the preferred fuel and energy source around the world. As demand for cleaner natural gas, replacing solid and liquid fossil fuels, continues to grow, emission standards will tighten in the long-term, requiring development and innovation in the LNG industry. Compressors play a central role in the transportation, processing, and liquefaction of natural gas, having a significant impact on the overall performance of LNG plants and production efficiency. Improvements in compressor control and protection, which have remained largely unchanged, can reduce energy consumption, resulting in lower emissions. Dynamic compressors used in the LNG industry have very different characteristics depending on licensed technology and plant capacity. Regardless of size and design, the operation of any dynamic compressor is limited by severe unstable conditions, known as surge, at relatively low flowrates; and at relatively high flowrates known as choke or stonewall. Both conditions must be considered when designing the control system so that they can be prevented. Due to the severity of surge and the much higher likelihood that compressors will operate at relatively low flowrates, this issue has received more attention. If the choke phenomenon is not as severe as surge, prolonged operation in the choke zone is not only very ineffective but can also damage the compressor. Compressors are usually tested for

unstable conditions, then the test results are combined into compressor maps that graphically describe the performance of a particular compressor under specified inlet test conditions and gas properties. Compressor maps show compressor performance using a set of constant speed performance curves with surge line, and can also display a choke line to indicate a dynamically stable operating envelope. Very often compressor maps provided by manufacturers have a vertical axis as the compressor outlet pressure or compressor pressure ratio, and the horizontal axis as a mass flow or volumetric flow. Since dynamically unstable compressor operation due to surge or choke is a fluid mechanics phenomenon that can occur at different rotational speeds, inlet pressures, and inlet temperatures, the principle of similarity and dimensional analysis are used, which are common in experimental fluid dynamics. The compressor performance can then be displayed in dimensionless rectangular co-ordinates, selected so that the process parameters at the compressor inlet, such as pressure and temperature,

Figure 1. The first and second concepts of protection.

Figure 2. The third concept of protection.

November 2021

molecular weight of the gas, and rotation speed, are irrelevant. In other words, any particular operating point plotted on the dimensionless compressor map will define the corresponding prototypes regardless of inlet conditions, gas properties, and rotational speed. The first most commonly used dimensionless horizontal co-ordinate on compressor maps that characterises compressor performance is the corrected flowrate. The second dimensionless co-ordinate used as the vertical co-ordinate in compressor maps is the compressor pressure ratio.

Compressor performance Compressor performance curves at constant speeds plotted on compressor maps can vary considerably in shape and slope. Figure 1 shows a hypothetical compressor map that includes constant speed performance curves, surge, and choke limit lines, where the horizontal axis represents the corrected flow and the vertical axis represents the pressure ratio. Proportional-integral-derivative with feedback (PID) controllers are the most practical and are commonly used to regulate an anti-surge valve to protect the compressor from crossing the surge line, or a discharge throttle valve to protect the compressor from crossing the choke line. The antisurge and anti-choke PID controllers continuously calculate the ER value as the difference between the desired setpoint SPb(%) and the variable input CV (%) to correct the control output. For this reason, the surge line must be stored in the compressor control system as a table function of pressure ratio and corrected minimum flow, and the choke line as a table function of pressure ratio and corrected maximum flow, which define the compressor operating limits. The actual operating point OP must then be calculated based on inputs from the flow and pressure sensors in order to calculate the controlled variable. A concept called surge margin is used as a parameter that defines the physical meaning of the actual distance between the operating point and surge point that belong to the same performance curve. But in a rectangular co-ordinate system, the surge margin can only be represented as a projection onto one or another axis. The most used definition of the surge margin SM (Flow) in industrial applications is the distance between the projections of the Surge_P surge point and the OP operating point on the horizontal axis shown in Figure 1. The Surge_P projection is present on the compressor map but cannot be measured and is therefore unknown to the PID controller. Instead, the projection of the surge point Flow_min is available as the intersection of the horizontal line drawn from the operating

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point to the surge line, which is stored in the control system as a function of the pressure ratio. In the case of differential pressure flowmeters, which is widely used in the LNG industry, the horizontal axis on the compressor map is replaced by the square of the corrected flow (Corrected Flow2), so the controlled variable CV (Flow2) for the anti-surge PID controller at a given pressure ratio PR_OP is calculated according to the formula:

vertical performance curves, can be defined as the distance between projections of the surge point Surge_P and the operating point OP on the vertical axis for a given corrected flowrate Flow_OP of the operating point, as shown in Figure 1. But the PR_max point as the intersection of the vertical line drawn up from the operating point to the surge line is available instead of the Surge_P surge point. Therefore, the controlled variable CV (PR) in percentage can be calculated for the anti-surge PID controller using the formula:

Protection from surge Now a fundamental question arises, how to choose a safety threshold to protect the compressor from surge. The most recommended safety threshold is 10% or more, measured from the surge line to the operating point at a given pressure ratio PR_OP, as shown in Figure 1, where the horizontal co-ordinate is the corrected flowrate. Figure 1 shows that the surge margin SM (Flow) and the controlled variable CV (Flow) are not equal. If the safety threshold is required to correspond to the actual surge margin, then the setpoint for the controlled variable should be set higher. How much higher depends largely on the shape and slope of the performance curves and the slope of the surge line. The safety threshold or setpoint SP (%) after it has been set in the controller remains fixed. Consequently, the fixed setpoint in this method does not provide equivalent surge protection, which can vary significantly from one constant speed performance curve to another, being overprotective in one case and insufficient in another. The next question is whether the 10% safety threshold, defined as the distance between the minimum stable flow point on the surge line and the operating point, should be considered a true 10% safety margin if it does not represent the full operating range covering the distance from surge point to choke point. Another approach to the concept of surge margin SMb(PR), which is typical for compressors with almost

As in the previous algorithm, the surge margin SM (PR) and the controlled variable CV (PR) are not equal, and if the safety threshold is to match to the actual surge margin, then the controlled variable setpoint must be set higher. The fixed setpoint in this method also does not provide the equivalent surge protection for various constant speed performance curves. The third approach is considered more advanced and is depicted in Figure 2, expressed in terms of both the corrected flowrate and the pressure ratio, which actually determines the surge margin SM (PR; Flow) as the ratio between the tangent of an angle of the surge point and the tangent of an angle of the operating point:

In fact, the co-ordinates of the PR_max and the Flow_min points on the surge line are available, then there are two options for calculating the controlled variable CVb(%) for the anti-surge PID controller: z Relative to the PR_max point on the surge line using the equation:

z Relative to the Flow_min point on the ...surge line using the equation:

Figure 3. The fourth concept of protection.

November 2021

This method, like the two above using rectangular co-ordinates, has the same notable disadvantage in that the actual surge margin cannot be directly measured or accurately estimated. In addition, none of these methods can simultaneously determine the position of the operating point relative to the surge and choke limit lines in order to reproduce the full operating range due to the geometric constraints imposed on the performance curves by rectangular co-ordinates. To simultaneously determine the operating point position between the surge

and choke limits and at the same time estimate the real surge and choke margins, an unconventional virtual parameter must be created. In general, compressor operation can be described as moving the operating point towards surge or choke limits along a performance curve, or moving from one curve to another in terms of a variable radius from some imaginary centre point. Such movements are more like movements in polar co-ordinates than in rectangular ones. Hence, polar co-ordinates seem to be the most appropriate choice for illustrating operating point activities. In this context, the position of the OP operating point in Figure 3 can be described by two polar co-ordinates: the angle α_op and radius r_op. Surge points α_surge forming a surge line and choke points α_choke forming a choke line can be stored in the compressor control system after converting rectangular co-ordinates to polar co-ordinates, and the point polar angle α_op of the operating point can be calculated according to the input signals. It is important to note that the controlled variable CV and the surge margin SM are the same only in the polar co-ordinate system defined by the polar angle α_op. Then the controlled variable CV (%) for the surge protection in a case of the polar co-ordinate system can be defined as the polar angle of the operating point α_op minus the polar angle α_surge of the surge point divided by the entire operating range, measured from the polar angle α_choke of the choke point to the polar angle α_surge of the surge point:

The controlled variable CV (%) for the choke protection in a case of the polar co-ordinate system can be calculated as:

Conclusion Equality of the controlled variable CV and the surge margin SM makes the polar co-ordinate algorithms the most accurate methods for determining the true operating point position relative to surge and choke limits. In a polar co-ordinate system, unlike rectangular co-ordinate methods, the entire range of the operating points can be displayed in real-time, which is critical for setting the actual safety thresholds for surge and choke protection. Polar co-ordinate methods provide the same protection for all compressor operating conditions, regardless of the shape and slope of the performance curves, the slope of the surge line or the slope of the choke line, making them the most effective for protecting compressors. The controlled variable CV (%) in the polar co-ordinate algorithms is linear over the entire operating range, making it easy to tune PID controllers using standard tuning methods and incorporating modern control technologies.

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15FACTS Large scale LNG projects are expected to account for over 90% of Russia’s planned LNG capacity until 2030

...ON RUSSIA LNG capacities are expected to reach 140 million tpy according to the most recent State Energy Strategy

In October 2021, a Russian director and actor spent 12 days on the International Space Station ﬁlming the ﬁrst movie in orbit

The country’s LNG production could reach approximately 250 million tpy by 2035

There was 29.6 million tpy of operating capacities in the country as of 2020 Tchaikovsky’s Swan Lake ballet was ﬁrst performed in 1877

The LNG design production capacity of Yamal LNG is 16.5 million tpy

It took almost 10 years for NOVATEK to establish the 16.5 million tpy Yamal LNG plant

Russian LNG from two plants is exported to 33 countries as of 2020

Russia makes up one tenth of the world’s landmass

The Arctic LNG-2 project is

A temperature of -71˚C has been recorded in the town of Oymyakon – the world’s lowest minimum January temperature outside of Antarctica

currently under construction and is expected to exceed Yamal LNG capacities by almost 3 million tpy

LNG production in Russia is 8.3% of global production

If the aims set out in the State Energy Strategy are achieved, Russia would cover 25% of global LNG demand

The Volga is the longest river in Europe

November 2021

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