LNG Industry August 2021 by PalladianPublications

August 2021

CLEAN & SUSTAINABLE

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Chart is at the forefront of the transition to a low carbon future through technology, equipment and services delivering hydrogen, LNG and biogas for energy and transportation. Our carbon capture technology also removes harmful pollutants including SOx, NOx and mercury.

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ISSN 1747-1826

CONTENTS 03 Comment

AUGUST 2021

32 Fitting the right engine

Pádraig Kelleher, MAN Energy Solutions, Denmark, details the technology behind a new, low-speed, dual-fuel engine designed for LNG carriers.

04 LNG news

37 Calibration is the key

08 Activity underway in the

Dean Standiford, VSL, the Netherlands, explains how insulating a flowmeter can affect the flowmeter temperature measurement value and how this can affect the mass flow output.

Americas

Ruth Liao, ICIS, USA, explores the LNG sector in Latin and South America, considering how historic drought has boosted LNG demand in the Americas.

40 Digital twins for A to B

Haavard Oestensen and Andreas Jagtøyen, Kongsberg Digital, Norway, explain how the complexities of a volatile LNG market can be navigated with digital twins.

43 Real-life training in a virtual world Gregory Sudwoj, WinGD, Switzerland, discusses the importance of virtual seafarer training for the safe and effective operation of LNG vessels.

46 Visualise the data

Catie Williams, InEight Construction Software, USA, looks at the best practices for visualising data to help communicate information in a clear and effective way.

08 12 The butterfly effect

Scott Jago, STS Marine Solutions Ltd, UK, outlines the root causes of LNG composite hose failures and the procedures to elimate this risk.

17 Age is just a number mber

Bo Andersen and Marina Silva, Integrated ated Global Services, Inc., USA, detail an online CUI solution for ageing LNG plants, where al maintenance. production is maintained during critical

22 So long sulfur

Kevin Young, Johnson Matthey, USA, explains plains the technology orbent which aims to behind a new high capacity sulfur absorbent ess costs. advance performance and reduce process

29 Putting Spain on the LNG map

Francisco Maza Luque, Repsol, Spain, takes kes a look at the innovations that are helping to make kering Spain the first port of call for LNG bunkering operations.

49 All aboard the blue train

Nim Gnanendran Ph.D., NimblEng Energy Consultants, Australia, explains why mid scale LNG trains are an ideal size for the development of blue LNG concepts.

53 Fuel for thought

Harrison Thomas, Gasrec, UK, looks at how bio-LNG and bio-CNG are driving the transition towards cleaner, greener transport.

56 15 facts on... Latin atin and South America

ON THIS MONTH’S CO COVER LNGSTS is a brand of STS Marine Solutions, t leading independent ship-tothe ship-to-ship transfer aand nd d go-to company for LNG trans transfers, projects, cconsultancy, on nsultancy, commissioning, and tterminal management. ma O ver the past 15 years LNG STS h Over has executed more than 1000 LNG ship-to-ship transfers involving offshore locations, termi terminal transfers, or small scale, which is p proven thanks to the company's in-house Marine & Technical LNG Team and their thre three fullyowned LNG STS transfer systems. To know more about LNGSTS and S STS Marine Solutions, please visit www.lngsts.com www.lngsts.c

CBP006075 LNG Industry is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department.

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.

LNG SOLUTIONS

LYDIA WOELLWARTH EDITOR

COMMENT T

he chemical element that is carbon is interesting for many reasons. Whilst it loves to bond with other elements and create undesirable compounds such as carbon dioxide (CO2) and methane (CH4), it also is the backbone to so many things in life, and has fundamental roles to play in the human body. Carbon in the LNG industry is, however, not preferable. Carbon dioxide and methane emissions are associated with the upstream production, liquefaction, and transportation of LNG. Offsetting carbon is being increasingly used by companies – this is the action to compensate for the emissions of carbon into the atmosphere as a result of industry or other human activity. To offset cargo deliveries of LNG, carbon credits can be purchased and used, which ultimately support reforestation. A fortnight ago, bpGM, Sempra LNG, and IEnova, announced that they had entered into a contract for the delivery and receipt of the first carbon offset LNG cargo for the companies. The cargo was delivered to the Energía Costa Azul (ECA) terminal in Mexico, having been sourced from bp’s global LNG portfolio. To offset the emissions from this cargo delivery – covering emissions from all aspects of the process, from the wellhead to the discharge terminal – a corresponding amount of credits have been retired that were sourced from a Mexican afforestation project from bp’s collection of offsets. In order to estimate the emissions released, bp’s greenhouse gas quantification methodology for LNG was used. Concerns surrounding the measurement of emissions have been highlighted in the past, since there is no formal, consistent methodology or definition in existence. If

LNG cargoes are to be increasingly carbon-neutral going forwards, it is highly important for the carbon emissions to have a uniform standard of measurement, or one cargo’s carbon offsets may be different to another’s, dependent on the operator and the methodology used to measure. Wood Mackenzie delved deeper into carbon-neutral LNG cargoes and offsetting emissions in a recent article. Looking at the statistics, an average cargo lifecycle produces approximately 270 000 t of CO2 equivalent, which equates to nearly 240 000 trees to offset this quantity of emissions. This is a hefty number of trees, and thus whether it is achievable throughout the entire LNG industry is questionable. With LNG utilised as a transitional fuel and demand growing, so is the number of LNG cargoes, and therefore the carbon offsets required will increase hand-in-hand. The highly-observant among our readers will have noticed a new logo on our contents page, for World Land Trust – an international conservation charity. Since LNG Industry is a printed publication, we are conscious of our carbon footprint as much as LNG facilities are conscious of their need to deliver carbon-neutral LNG. We are using carbon balanced paper as part of World Land Trust’s Carbon Balanced Programme. This programme balances carbon emissions by protecting threatened forests and restoring forest habitats, with both actions ultimately preventing the release of greenhouse gases and also sequestering atmospheric carbon as trees grow and mature. To date, the World Land Trust has helped secure 2b222b247 acres of threatened habitats across 20 countries, and LNG Industry is proud to be a member of this movement.

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LNGNEWS Canada

Mexico

Operations commence at NFE’s LNG terminal

ew Fortress Energy Inc. has announced that its LNG terminal in the port of Pichilingue, Baja California Sur, Mexico has begun commercial operations. “The delivery of more affordable and cleaner-burning natural gas is a significant milestone for Baja California Sur,” said Wes Edens, Chairman and CEO of NFE. “Our facility will enable customers to significantly reduce emissions and costs by switching from oil-based fuels to natural gas.” The introduction of natural gas into the Baja California Sur market will help enable more energy efficiency, cost savings, and emissions reductions as it displaces fossil fuels. It also provides opportunities for job creation; training of a new, more specialised workforce; economic development; and improved environmental management. The terminal features NFE’s proprietary ISOFlex system, which allows larger LNG carrier vessels to transload LNG into ISO storage containers on offshore support vessels (OSVs) with a specialised manifold. These ISO storage containers can be easily offloaded at container ports and onto trucks, which enables the reduction of time, permitting requirements, and capital costs for the development of NFE’s terminals. “We are proud to have deployed the first-of-a-kind ISOFlex system at our terminal in Baja California Sur,” said Sam Abdalla, Vice President of Project Development of NFE. “This is a big achievement for NFE and will enable us to deliver critical energy infrastructure and logistics solutions much more quickly and less expensively.” Under the terms of an agreement signed in March, NFE will supply natural gas to the CTG La Paz and CTG Baja California Sur power plants in Baja California Sur through the terminal.

Construction of LNG Canada project reaches new milestone

hree towering pieces of equipment critical to the gas liquefaction process have arrived at the LNG Canada site in Kitimat, Canada, as construction activities progress through the project’s ‘going vertical’ stage. Crews spent a week carefully offloading a 345 t main cryogenic heat exchanger (MCHE) and two precooler units, which weigh 308 t and 284 t respectively, from a cargo ship docked at the LNG Canada project’s new material offloading facility (MOF) in Kitimat Harbour. The equipment was then placed on large, self-propelled modular transporters, which will slowly move the pieces along the project site’s new 3 km-long haul road to the main construction area in the coming days, where they will soon be connected to other pieces of LNG infrastructure. The largest of the three new pieces of equipment, the MCHE is approximately 50 m in length. Once installed vertically, it will be among the most visible components at the LNG Canada facility. It is the first of two MCHE units built by Linde plc for the LNG Canada project; the second MCHE is expected to arrive later this year, along with two more precoolers. Often described as the ‘heart’ of an LNG facility, MCHEs are made to liquefy natural gas. Gas enters an MCHE near its base and exits at its top in a sub-cooled, liquefied state, at -160˚C. The liquefied gas is then piped to a storage tank, and from there it is loaded onto specialised carriers for ocean transport. Precoolers are also integral to the process, increasing efficiencies during different stages of gas liquefaction. All three pieces of infrastructure are precision engineered from aluminium and are pressure tested prior to delivery.

Norway

Gasnor and Wintershall Dea sign LNG supply agreement

asnor and Wintershall Dea have entered into an agreement on LNG deliveries to supply vessels on the Norwegian shelf. From the start, deliveries will go to Viking Princess, delivered from the LNG bunkering terminal at Mongstad Base. When using LNG-powered supply vessels, the emissions associated with the supply services will be reduced by approximately 30%.

August 2021

Viking Princess is equipped with technology that makes it possible to reduce CO2 emissions by up to 2400 tpy – corresponding to emissions from approximately 1200 cars. The 90 m long and 21 wide vessel is equipped with dual fuel engines that can use both marine gasoil (MGO) and LNG as fuel, and also has a battery pack for efficient energy management.

LNGNEWS Kuwait

USA

Sempra LNG and PGNiG sign MoU

empra LNG has announced that it has entered into a Memorandum of Understanding (MoU) with the Polish Oil & Gas Company (PGNiG) for the potential purchase of approximately 2 million tpy of LNG from Sempra LNG’s portfolio of projects in North America. As part of the MoU, Sempra LNG and PGNiG are also working toward a framework for the reporting, mitigation and reduction of greenhouse gas (GHG) emissions throughout the LNG value chain. “We look forward to continuing to work with PGNiG to help meet their energy objectives from our strategically positioned LNG facilities and development projects on the Gulf and Pacific Coasts of North America,” said Justin Bird, Chief Executive Officer of Sempra LNG. “As we look to extend our LNG business to include net-zero solutions, working with companies like PGNiG to advance best practices in GHG mitigation can build on the global environmental benefits of substituting higher-emission fuels with lower-carbon LNG while also continuing to drive down emissions in the US natural gas value chain.” “We highly value our relationship with Sempra LNG and we are keen to continue it. The MoU allows for shifting the volumes originally contracted at Port Arthur LNG to other facilities from Sempra’s projects portfolio,” said Pawel Majewski, Chief Executive Officer of PGNiG SA. “We are also determined to curb the carbon footprint of fuels offered by PGNiG and are convinced that our co-operation with LNG producers like Sempra LNG will contribute to reach this goal most effectively.” The MoU is non-binding and was completed in connection with the termination of the parties’ Sales and Purchase Agreement (SPA) signed in 2018 that provided for 2 million tpy of LNG supply to be delivered from the Port Arthur LNG project. Sempra LNG owns a 50.2% interest in Cameron LNG, a 12 milllion tpy export facility operating in Hackberry, Louisiana, US, and is working with Cameron LNG on a proposed expansion of the facility through one additional liquefaction train with an offtake capacity of over 6bmillion tpy. Sempra LNG is also developing additional LNG facilities and carbon sequestration infrastructure along the LNG value chain on the Gulf and Pacific Coasts of North America.

August 2021

Qatargas delivers LNG to Al-Zour terminal

atargas Operating Company Ltd (Qatargas) delivered the first ever cargo of LNG on a Q-Flex LNG carrier to commission Al-Zour LNG receiving terminal in Kuwait in July 2021. The cargo was loaded onboard the Qatargas-chartered LNG vessel, Al Kharsaah, at Ras Laffan on 9 July 2021 and delivered to Al-Zour LNG terminal, owned and operated by Kuwait Petroleum Corporation (KPC), three days later. Commenting on this milestone delivery, Khalid bin Khalifa Al Thani, Chief Executive Officer, Qatargas, said: “At Qatargas, we are honoured to have been able to supply the commissioning cargo to this landmark facility in co-operation with our strategic business partners at KPC. The successful commissioning of this LNG receiving terminal will contribute towards strengthening our business relations with KPC." Al-Zour LNG terminal is set to be amongst the largest in the world by overall import capacity of 22 million tpy by 2022. Currently it is one of the world's largest capacity LNG storage and regasification green field projects. The terminal consists of two jetty heads, capable of simultaneous discharging and has eight storage tanks, with a net volume capacity of 225 000 m3 for each tank, with an overall capacity of 1.8 million m3 for eight tanks.

THE LNG ROUNDUP X EIA: US sees record LNG export growth X SLNG and Keppel to collaborate on gas project X Shell delivers first gas from Barracuda Project Follow us on LinkedIn to read more about the articles

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LNGNEWS Canada

Philippines

Tourmaline and Cheniere Corpus Christi Stage III sign agreement

Svitzer AMEA signs contract with FGEN LNG Corp.

heniere Energy, Inc. announced that its subsidiary, Corpus Christi Liquefaction Stage III LLC, has entered into a long-term gas supply agreement (GSA) with Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp. Under the GSA, Tourmaline has agreed to sell 140b000bmillion Btu/d of natural gas to Corpus Christi Stage III for a term of 15 years beginning in early 2023. The LNG associated with this gas supply, approximately 0.85bmillion tpy, will be marketed by Cheniere. Cheniere will pay Tourmaline an LNG-linked price for its gas, based on the Platts Japan Korea Marker (JKM), after deductions for fixed LNG shipping costs and a fixed liquefaction fee. Tourmaline Oil Corp. is acting as guarantor of the GSA on behalf of Tourmaline. This Integrated Production Marketing (IPM) transaction is expected to support the development of the Corpus Christi Stage III project. “This commercial agreement is expected to support our shovel-ready Corpus Christi Stage III project while enabling Canadian natural gas to reach international LNG markets" said Jack Fusco, Cheniere’s President and CEO. The Corpus Christi Stage III project is being developed to include up to seven mid scale liquefaction trains with a total expected nominal production capacity of approximately 10 million tpy. It has received all necessary regulatory approvals.

vitzer, a global towage provider and Maersk subsidiary, has announced that it has signed a 10 year time charter party with FGEN LNG Corp., a wholly-owned subsidiary of First Gen Corp., for the provision of towage and other vessel support services required by FGEN LNG’s Interim Offshore LNG Terminal. These will feature an FSRU that will be located at the First Gen Clean Energy Complex in Batangas City, the Philippines. Svitzer will provide four new 75 t bollard pull tugboats to assist the FSRU and LNG carriers that will deliver LNG to it – for berthing, unberthing, navigation assistance – and provide other services including fire fighting, pollution control, port and vessel security services, pilot and boarding party transfer, and fender management. Commenting on the contract win, Nicolai Vinther Friis, Managing Director for Svitzer AMEA, said: “We are truly pleased that FGEN LNG has chosen Svitzer as a trusted partner and provider of towage services for the FGEN LNG terminal in Batangas Bay. Our two companies share many of the same values and, at Svitzer, we look forward to collaborating with FGEN LNG on ensuring the energy security of the Philippines and to be part of the country’s green transition. This important contract adds a new country to the global Svitzer portfolio and expands our ability to provide safe and efficient towage and marine services support to more customers across the globe.” Operations are planned to begin as early as 3Q22 and Svitzer will now take the first steps to set up operations in the Philippines, which will include hiring 72 seafarers and five onshore staff, all local Filipinos.

21 - 23 September 2021

04 - 06 October 2021

Gastech Exhibition & Conference 2021

Global Energy Show

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Calgary, Canada

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15 - 18 November 2021

30 November - 03 December 2021

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Houston, USA

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21st World LNG Summit & Awards Evening

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August 2021

Ruth Liao, ICIS, USA, explores the LNG sector in Latin and South America, considering how historic drought has boosted LNG demand in the Americas.

he role of LNG as a swing supplier for Latin America has never been more pronounced than this year, as the region looks to set new historical highs for imports into Brazil for the first half of 2021, while imports into Argentina and Chile are also higher. The Americas as a whole makes up approximately 5% of global LNG demand, substantially smaller than key markets in Asia and Europe. But particularly for Brazil and Argentina, the buyers in these countries are more exposed to the spot market as both solely rely on short-term cargoes and lack contractual supply. While some new import capacity is expected to come online this year, such as the Puerto Sandino LNG project in Nicaragua and small scale imports into Pichilingue, La Paz, Mexico, competing gas supply and the growth for renewables was previously threatening to push out LNG demand. Particularly in 2020, LNG demand from countries such as Mexico, Brazil, Argentina, and Chile was in decline, as the COVID-19 lockdowns restricted economic and industrial activity. However, South American importers have faced various factors for LNG demand this year: weatherrelated drought in Brazil, lower domestic gas production in Argentina, and a lack of Argentine gas pipeline imports into Chile. This has given the US an advantage to become the lead LNG supplier into the Americas, given the shorter shipping distance to Brazil and Argentina compared with Asia, as well as the flexibility of supply sourced by various portfolio sellers and traders.

Brazil’s demand soars Severe, prolonged drought conditions not seen in almost a century, along with economic rebound, have spurred Brazil’s LNG imports to all-time highs and have propelled the country to the region’s top importer in the first six months of 2021. Brazil has imported 2.7 million t of LNG in the first six months of 2021, according to ICIS LNG Edge, more than three times what the country imported the same time a year ago – which was 742 000 t. In 2020, the country was cushioned by ample rainfall and hydropower generation, as well as lower demand as a result of COVID-19 restrictions. However, starting in March 2021, drought conditions have persisted in the central and south regions, where the country has more concentrated hydropower generation, particularly in the south and southeast. State-run energy company Petrobras’ dramatic acceleration of LNG imports in 2021 significantly changes the company’s LNG position from one year ago, when ample higher domestic gas production also kept the buyer largely out of the spot market. Due to its variable demand dependent on rainfall and hydropower reservoir levels, Petrobras solely relies on the spot market, although the South American buyer has one vessel, the 166 000 m3 Magellan Spirit, under charter to lift cargoes on a free on board (FOB) basis. Petrobras typically purchases on a slight premium to the ICIS Dutch TTF benchmark. Sources said previously that the premium was usually approximately US$0.10/millionbBtu above the TTF.

Brazil has also been importing power from Argentina, which subsequently supported LNG demand into Argentina

Figure 1. Brazil leads in LNG imports in the Americas as Mexico wanes.

and was one of the reasons behind the most recent buy tender, sources said. According to Brazilian grid operator ONS, Brazil will import power from 19 June through to 25 June from Argentina through the Garabi I and II power plants operated by Enel. Brazil imported no cargoes between June and September 2020, but imported seven cargoes in May 2021 and 14 in June 2021, an all-time high since the country began importing in 2008. The majority of the cargoes imported in the first half of 2021 came into Petrobras’ floating storage regasification unit (FSRU) in Guanabara Bay, which received 30 cargoes. Petrobras’ FSRU at Salvador received 14 cargoes. The company’s Pecem terminal in the northeast received two cargoes, with that region receiving more plentiful rainfall than in other parts of the country.

Brazil fires up private terminals Brazil has two privately-operated LNG import terminals, Sergipe and Acu, which so far have not received much cargo activity this year. However, this may change as the government has now mandated for utilisation of all thermal power plants to run. On 30 June, the 162 000 m3 Golar Glacier from the US Sabine Pass plant arrived at Sergipe – the first cargo that the terminal has received since May 2020.

Argentina’s winter extends

Figure 2. 2020 - 2021. Severe drought in Brazil ramps up LNG imports.

Argentina has also seen an increase of LNG imports, with 1H21 imports up 72% y/y, according to ICIS LNG Edge (Figureb3). Argentina primarily purchases LNG for its southern hemisphere winter, although this year, lower domestic gas production was another factor behind state gas distributor IEASA’s LNG buy tenders. Argentina’s state-run producer YPF discontinued its export project Tango FLNG after the producer declared force majeure in 2020 – less than a year into operations from the Bahia Blanca port. Bahia Blanca then resumed back into an import terminal in 2021. Decisions to cut back on upstream investment during the COVID-19 pandemic in 2020 have also had an impact on domestic gas production this year, as lower production was one of the main reasons to resume imports into Bahia Blanca. Labour strikes in the Neuquen Basin that began in April, primarily by health workers that looked to gain access to better care during COVID-19, caused disruptions in oil and gas logistics that had an impact on produced volumes, coinciding with the start of winter demand. IEASA has now issued five spot LNG tenders for 2021 delivery, with an import season that started earlier than last year and is now prolonged into September.

Chile imports increase Figure 3. Percentage change. Highest 1H21 growth seen in Brazil and Argentina.

August 2021

Chile’s LNG imports were the next largest in the Americas, as the country imported nearly 1.7bmillion t for the first six months of 2021, according to ICIS LNG Edge. This was an increase of approximately 38% compared with the same time last year.

Chile primarily receives LNG under long-term contract for its terminals Quintero and Mejillones, as Quintero offtakers receive term supply from portfolio seller Shell, while Francebased ENGIE is the majority owner of the Mejillones terminal and mainly receives LNG from fellow French supplier TotalEnergies. Chile’s gas imports via pipeline from neighbouring Argentina, which were resumed in 2016 with the increase of Vaca Muerta production, have dwindled this year due to the higher demand for gas in Argentina. This, too, led to Chile’s increased appetite for LNG. Consortium GNL Chile tendered for one spot cargo for late July for Mejillones as a result of increased thermal power plant demand, following lower-than-expected hydropower generation, but the award of the tender also coincided with the start of the rally of Asian LNG spot prices. It is unclear whether GNL Chile will tender again this year given the historically-high summer spot prices for LNG as a result of Asian demand and soaring European hub prices.

Mexico takes more US gas Mexico, once a key LNG importer in the Americas, instead has continued its downward trend in consuming LNG in 2021, given its proximity to the US and its reliance instead on gas pipeline imports. Given the increase of US pipeline gas imports and lower domestic demand, Mexico already saw its lowest amount of LNG imported in 10 years in 2020. Mexico imported 366 000 t in 1H21, approximately 61% lower than the same time a year ago. Increased cross-border pipeline capacity, particularly within the so-called

Wahalajara pipeline system connecting West Texas gas down through Guadalajara in southwest Mexico, brought more US gas down into the country. Mexico’s newest LNG terminal, the small scale project developed by New Fortress in La Paz, is due to have become operational in July. The project will supply two power plants operated by state-run electricity company CFE and is expected to help alleviate some of the soaring power prices seen in the resource-stranded Baja California peninsula. West Coast liquefaction developers, meanwhile, continue to market offtake capacity from various projects. The 2.5 million tpy Costa Azul LNG export project in Ensenada, under construction by US-based Sempra LNG, remains the only export project to be financially sanctioned in 2020.

Looking ahead With perhaps the exception of Brazil, the rest of the Americas is not likely to undergo any structural LNG import growth in the next few years. Chile has invested more heavily in renewables and is looking to the burgeoning hydrogen market, while other smaller projects such as El Salvador have continued to seek financing and have not progressed in its timeline. In the Americas, LNG is expected to be continually relied on in times of swing demand, particularly during lower rainfall, higher power demand-driven appetite, and to offset any domestic or border production disruptions. The flexibility of floating LNG terminals, particularly in Argentina and Brazil, also allows for the ease of transferring infrastructure if and when demand patterns shift.

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Scott Jago, STS Marine Solutions Ltd, UK, outlines the root causes of LNG composite hose failures and the procedures to elimate this risk.

he discovery of metal deformed in such a distinctive way is becoming a common sight to the technical department of STS Marine Solutions Ltd (LNGSTS). For those that do not recognise what is being observed in Figureb1, it is a damaged internal reinforcement coil of an LNG composite hose that failed when used for an LNG ship-to-ship transfer operation. It may be puzzling to the observer how it could possibly be manipulated, twisted, and contorted in such a distinctive way. Amongst the technical department of LNGSTS this has become known as the butterfly effect, due to the distinctive way the metal folds.

What is disconcerting is this is not a result of a hose pinch, crush, or a kink. But rather the result of unwanted conditions created inside the hose during the transfer process. STS Marine Solutions Ltd has had a dedicated LNG department since 2005 and has operated underneath the brand name of LNGSTS. Over the last 16 years, the company has been aware of numerous similar hose failures throughout the industry. LNGSTS has consulted on a number of projects post failure, on process and procedures to help eliminate the risk and root causes of LNG hose damage. To appreciate the forces involved in bending a wire into such shape, it is worthwhile considering that the internal and

Figure 1. Aerial section of damaged hose.

external wire helix of an offshore transfer hose are normally constructed out of an austenitic stainless steel with chrome, nickel, and molybdenum content – a high-grade stainless steel with superior strength and rigidity. Such strength and rigidity are demonstrated when these hoses are subject to acceptance testing.

Example of strength An impact test was conducted on an 8 in. LNG composite STS hose, with an impact weight of 325 kg at a height of 1.5bm, and a 4-bar internal pressure. The inner and outer wire deformed only by 40 mm. A crush test was conducted, with a crush weight of 7 t, on a 500 cm2 plate, and a 4-bar internal pressure. The inner and outer wire deformed only by 129 mm. When considering the aforementioned tests, the mind can only wonder what forces were involved to distort the internal wire in the way that is shown (Figure 2). It may be an easy assumption to make that some catastrophic breakdown in process or serious malfunction may cause this, but the next section of the article will detail how only subtle errors can lead to this. The butterfly deformation of the inner wire (i.e. the inward collapse of the wire from one side) is normally over a few windings of the coil – the buckled section is symmetrical from the most buckled middle wire. On top of the buckled geometry the wires tend to lean away from the buckled section’s centre. Even the buckled crests do have a deformation component in an axial direction. Adjacent to the buckled wires, the inner wire is toppled. The outer wire is never indented or (significantly) increased in diameter. This rules out that the damage is caused by external forces. The toppling of the wires is caused by an axial force, releasing the interlock of the inner and outer wires. Due to the geometry of the hose wall, the inner wire is restricted by the barrier (i.e. the fabric and film stacks) from moving in an axial direction. One point to bear in mind as the details for why toppling occurs, which is outlined next, is that as the internal pressure of the hose increases and the diameter of the outer wire and barrier increases, the reduction of interlocking strength of the inner wire occurs.

Root causes of failure Figure 2. Cross section of damaged hose.

Figure 3. Internal helical wire interlock release.

August 2021

With all the failures LNGSTS has seen, it is always one of two known common root causes that are identified as the culprit of the damage. It either relates to the lack of detail within the procedures regarding the hose (i.e. purging procedures, liquid freeing, etc.) or the awareness of conditions during certain transfer criteria, and lack of mitigation measures that should be used to prevent damage within the hose. These short sights in the finer details of hose procedures can lead to the following physical phenomena within the hose, both of which have the capability to damage the hose. z Liquid LNG at temperature and pressure conditions close to its boiling point, suddenly gets a temperature or pressure belonging to the gas phase and evaporates quickly. The most relevant effects and phenomena relating to this which are to be concerned about is flash evaporation caused by pressure drops and condensation induced water hammer (CIWH). Although the term relates

to conditions more commonly found with steam/water systems, the effect can be the same with LNG. z Rapid phase transition (RPT) of a relatively small volume of LNG close to the hose’s inner wall can cause such damage. Evaporation of the methane from the LNG changes the LNG’s composition locally (i.e. methane content drops with respect to the other alkanes). For a stable and safe operation, the Leydenfrost temperature, hose wall temperature, and super heating limit should be in a particular order. When the LNG temperature increases too fast (e.g. flushing too much LNG through a relatively warm hose), the particular order of the three mentioned temperatures can change and in particular cases cause a rapid and unstable phase change of the LNG which manifests itself as a sudden local ‘explosion’ type pressure build-up that generates local high pressure. Both similar in nature, these phenomena need to be avoided to ensure safe operation of a transfer hose. Though ‘sudden evaporation’ and RPT are acknowledged as different physical phenomena, it does not mean that they will occur (always) separately. There is evidence that they can occur simultaneously and/or after each other. By far the most common culprit that LNGSTS has identified as the cause to these failures is the liquid freeing procedure of the hoses after a transfer operation has occurred. A common method of pressure and release using nitrogen is employed in the industry and is generally the accepted method. The greatest dangers arise when this method is attempted on a hose which is still completely full of liquid. The hose is full of warming LNG, which is pressurised up using nitrogen usually between 4.5bbarb-b5.5 bar. This addition of pressure will effectively calm the LNG and bring it well within its liquid phase. Releasing the pressure to try and evacuate the hose of liquid has the opposite effect, removing the pressure quickly brings the liquid into what should be a vapour phase. The results of this can bring large, localised pressure spikes within the hose, reducing the interlocking internal/external wire forces. Combined with large axial loads due to the flowrate of the liquid draining this can cause the toppling of the internal wires. The second most common cause of failure is related to when flowrates for each transfer hose become lower than 50% of the hose’s maximum rated flowrate. This causes the inability of the hose to generate a natural back pressure within the hose and the vessel’s manifolds. This scenario can allow vapour to form within the hose due to the very low thermal throughput, and low liquid velocity allowing ambient heat to be absorbed. When vapour is allowed to form in a hose, a known effect called CIWH can occur. These CIWH conditions are caused as follows: Warm vapour is allowed to form within the hose, and this forms on the top of the flowing LNG. An indication of this can be lack of frosting of the top of the hose where the hose connects to the manifold. The warm vapour will normally cool and collapse and condense when in contact with the cold LNG. In addition, the colder liquid will create boil-off vapour when in contact with warmer areas of the hose.

The collapsing vapour volume will have to be replaced with liquid, and boil-off volume will have to create space by displacing liquid. This process is continuous in nature and can be a non-disruptive effect, a stable stratification can occur and a multiphase layer in equilibrium can form within in the hose. However, with slight pressure fluctuations, presence of LNG flow and the layout shape of the hose in an STS transfer, isolated pockets of vapour can occur. With an isolated pocket of vapour, the volume of vapour is more susceptible to pressure fluctuations within the pocket and the vapour can, in some circumstances, very rapidly collapse. Condensing rapidly, the impact of the liquid racing to replace the collapsing vapour can cause a shock wave within the system. This shock wave is normally brief but violent and contains dispersed two-phase flow at high velocities, in excess of the hose’s rated flow which can consequently damage the hose. RPT can be present in these conditions also and is theorised to be active within the collapsing vapour pocket, causing the butterfly deformation. In both mentioned instances, subtle changes and constraints to procedures can limit these effects to a safe level. This will prevent damage to the hose and ensure a safe, successful, and efficient transfer. Considering transfers can vary between different vessel types, different equipment, and different operational constraints, generic advice on procedural changes is not recommended. However, the technical team at LNGSTS is willing and capable to assist any concerned parties with system and procedural reviews.

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Bo Andersen and Marina Silva, Integrated Global Services, Inc., USA, detail an online CUI solution for ageing LNG plants, where production is maintained during critical maintenance.

hermal sprayed aluminium (TSA) provides lasting (>20byears) protection of carbon steel equipment within LNG facilities. It acts as a barrier coating, passivating the surface and galvanically protecting it against atmospheric and immersion corrosion mechanisms, such as corrosion under insulation (CUI). In the past, TSA applications were performed during turnarounds, disrupting schedules and other activities due to noise, fumes, and abrasive blasting. LNG plant operators were forced to make trade-offs between turnaround duration and asset integrity, as the amount and location of surfaces protected by TSA in turnarounds are limited.

Ageing LNG plants require work between turnarounds There has been a higher demand for prolonged TSA application outside of the turnarounds in the past years. Equipment is now a lot older. Pipes, vessels, and other process equipment face rapid deterioration of their original non-optimal corrosion protection.

How to increase the speed of maintenance and maintain production capacity? Maintenance and operations managers are under pressure to increase the maintenance speed and not to lose many production facilities, or at least the production capacity. As a result, they look at undertaking the critical maintenance while the LNG plant is online – in other words, without shutting

it down. That way, the managers will be able to reach their maintenance goal and maintain uptime simultaneously.

Safety considerations There are concerns regarding hot work, such as welding, abrasive blasting, and the open flame of TSA application, in many locations around the world. Temperature and humidity also need to be controlled to reach the optimal environment for the TSA application. Hot work that may produce sparks or open flames can be dangerous due to the risk of explosion, fire, and the release of poisonous gasses. It can be hazardous for personnel, equipment, and the entire plant.

Developing an online TSA solution Large national and international petrochemical companies have been actively looking for a safer TSA solution, which can be applied while the plant is in operation. Royal Dutch Shell has initiated a project to develop a safer online TSA solution. This proprietary patent-pending system incorporates five different elements, ensuring productivity and protection of LNG assets in the safest environment possible. These five elements can be broken down into smaller parts depending on the asset owner’s needs.

Figure 1. Thermal sprayed aluminium (TSA) provides lasting protection of carbon steel equipment within LNG facilities.

Figure 2. Corrosion under insulation (CUI) on piping is common in ageing facilities.

IGS shrink wrap habitat The main function of the habitat/enclosure is to contain hot work, grit/sandblasting, TSA, and potential gas leaks inside the work area as defined by the habitat. The secondary purpose is to provide protection and containment from adverse weather conditions such as sun, rain, wind, and snow. This makes it possible for the crew to work in virtually any type of weather situation. It withstands high winds, adverse weather conditions, and chemical exposure. It is costeffective and provides UV protection for long-term usage (more than 12bmonths). When installed by the professional installation team, the shrink wrap provides a drum tight fit around the work zone, making sure to contain everything, including gasses. The shrink wrap is flame-retardant up to 150˚C/300˚F and contains special additives that will self-extinguish within seconds if it ignites.

IGS automatic safety shutdown

Figure 3. IGS shrink wrap habitat.

August 2021

The second element is the proprietary and patent-pending automatic safety shutdown. The system is designed as an emergency shutdown system capable of giving audio and visual warnings based on the gas sensor readings. This enables either manual shutdown or automatic termination of any work inside or outside the habitat. Gas sensors are placed outside the habitat at the air intake and designated points to detect any dangerous gasses before they reach the inside. Additionally, the necessary number of gas sensors are placed inside the habitat to detect any possible gas leaks within the enclosure. The automatic safety shutdown is controlled by a programmable logic controller (PLC) unit. The automatic safety shutdown monitors gasses as well as pressure. If there is a loss of pressure within the habitat, all work is automatically shut down. Additionally, welding, grinding, power, blasting, painting, HVAC, and dust collection can also be controlled. If there is a detection of gasses or

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loss of negative pressure within the habitat, all electrical and pneumatic equipment will be shut down automatically. It is also possible for technicians to perform a manual shutdown if deemed necessary. The automatic safety shutdown will shut down all connected equipment. In which case, a shutdown activates the emergency gas jet extraction. The automatic safety shutdown controls all equipment through electrical connections and solenoid valves outside the classified exclusion zones or pneumatic controls within the classified areas.

Emergency gas extraction Figure 4. IGS automatic safety shutdown system.

The emergency gas extraction system is based on the venturi theory, working as a jet engine. It can remove large amounts of air and gas in a relatively short time. The emergency gas extraction system consists of hard ducts running from each habitat in use to a flame arrestor mounted on a high point where it will be safe to release gasses such as hydrocarbon or LEL into the atmospheric air (Figure 5). The emergency gas extraction system is controlled through the automatic safety shutdown. It automatically activates in the event of gas detection inside or around the habitat or the loss of pressure.

Certified safety technicians The fourth element is the IGS Certified Safety Technicians. IGS places all of its technicians through an intensive and thorough training programme to become certified habitat and safety technicians. This rigorous training ensures that all of the company’s technicians have the knowledge and experience to provide LNG asset owners with the safest optimal solutions in any situation.

IGS pressure solution

Figure 5. Emergency gas extraction.

The fifth element is the patent-pending IGS pressure solution. This solution ensures continual negative or positive pressure within the habitat to contain any possible hydrocarbon leak that might happen when performing blasting of the pipes and vessels. To provide a negative pressure atmosphere within the habitat, several HVAC units are utilised, which also provide dehumidification in tandem with the dust collection system. The dust collection system removes air at a higher rate than is introduced by the HVAC. The pressure is continuously monitored by utilising pressure gauges that are mounted inside the habitat. The pressure gauges are connected to the automatic safety shutdown.

Pilot project at an LNG producing plant Established in 1989 by NLNG, an LNG facility in Nigeria currently has six trains. The plant has a total production capacity of 22 million tpy of LNG and 5 million tpy of NGLs, which equals 6% of the global market.

Hot and humid

Figure 6. IGS TUFFss online TSA project at an LNG producing plant.

August 2021

Located in a hot, humid, and very salty environment, piping at this facility is prone to corrosion. Various types of paint and insulation have initially been used for corrosion protection. After 20 years in service, CUI has turned into a significant problem with many pipes about to burst. Ignoring the problem or having an insufficient solution could result in fire,

explosion, environmental damage, loss of life, loss of profit, or production loss.

CUI problem: Evaluating alternatives One option was to repaint the piping with the same or similar paints and coatings that have already failed once. Some new technology paints and coatings were also being considered. These paints would still need to be inspected and usually reapplied every 5 - 10 years. TSA was an optimum solution due to its long inspection cycle of >20 years, and proven reliability.

Online TSA pilot application TSA coatings applied in traditional ways without environmental controls would not be practical in this case. The scale of the work in total exceeded 360 000 m2. Applied during turnarounds, it would have taken over 30 years to protect all corroded piping. The plant would not have lasted 30byears in its present condition. The plant needed a solution that could be applied while the plant is live. The application would need to be climate-controlled during surface preparation and TSA application, with all grit and dust contained. The IGS TUFFss online TSA pilot project was first completed on train 1. The scope included a 50 m (160 ft) column and a two-level platform with two heat exchangers/ reboilers. IGS TUFFss online TSA was applied to a total area of 700 m2 on cold and hot surfaces. This on-site project began on 1 October 2016, and concluded in January 2018. The project was carried out in adverse weather conditions, including heavy rain, thunder, sandstorms, high temperature, and high humidity. This project succeeded in meeting and exceeding objectives by rigidly following all safety guidelines. The

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Figure 7. CUI problem area on piping. project utilised specially designed habitats to enable weather protection, climate, humidity, and pressure control. It was now confirmed without a doubt that it is possible to carry out the encapsulated TSA maintenance in a live environment, which will be of great importance to NLNG in the future as the work continues on the remaining six trains.

Summary As equipment within LNG facilities continues to age, the demand for maintenance solutions that can be applied all year round is growing. Plant operators are looking to companies such as IGS to utilise its global footprint and experience to deliver innovative solutions safely and efficiently. Preventing shutdowns and providing the work outside of turnarounds eases the pressure off the maintenance and operations teams, who can continue production while crucial maintenance work is being simultaneously carried out.

Kevin Young, Johnson Matthey, USA, explains the technology behind a new high capacity sulfur absorbent which aims to advance performance and reduce process costs.

ulfur in the form of hydrogen sulfide (H2S) is a very toxic and corrosive compound which needs to be removed from natural gas before it is converted into LNG – the form where it can be used by businesses and homes. As the world is transitioning to more low carbon sources, LNG is taking a central role in this process which is reflected in the ongoing growth in demand. Some sources of natural gas contain significant amounts of sulfur. Upon the combustion of sulfur containing gas, sulfur dioxide (SOx) can be formed which may lead to potential health issues such as respiratory and cardiovascular disease.

In addition, environmental issues arising from SOx emissions include the formation of acid rain that adversely affects ecosystems, as well as technical issues such as pipework corrosion or downstream catalyst poisoning, costing the industry billions of dollars per year as a result of catalyst replacement and process shutdowns. If sulfur impurities in gas are not effectively reduced to a very low concentration before use in other chemical processes, it irreversibly poisons the metal catalysts, reducing their activity, selectivity, and lifetime – being especially detrimental to those used for both catalytic reforming and fuel cells electrodes.

A variety of processes exist for the removal of H2S from gas streams, dictated by the concentrations of sulfur that need to be removed, and the volumes of gas that need to be processed. Johnson Matthey’s PURASPEC™ absorbents are well suited to polishing duties requiring removal of relatively low levels of H2S. The company’s fixed bed technology has been designed to offer a simple solution and a low capital cost for sulfur removal (Figure 1). The sulfur capacities of a PURASPEC absorbent are not sensitive to temperature or pressure within the typical gas processing operating conditions envelope, and are highly selective towards H2S removal from natural gas, CO2, and liquid hydrocarbon streams, with a robust performance within a wide compositional range and different flow-sheet locations.

PURASPEC absorbent performance is also not affected by the water content of the stream, provided it is run in a single phase and the material does not require water saturated streams to achieve expected sulfur capacities.

Benefits of granulated products To convert active raw material powders into a more useful form they are formed into granules (Figure 6). This requires the addition of binders to the active copper powders, to ensure the product acquires the desired characteristics, such as strength, porosity, density, and activity. Due to the inherent porosity combined with possible achievable strength of granules, granulation was chosen by Johnson Matthey (JM) as the preferred and optimum forming technique for all purification products, and the company has decades of experience in this area. With controlled addition of the active copper powders in the granulation process, the product has an exceptionally high capacity for sulfur in addition to a fast rate of reaction to pick up sulfur at low temperatures. In addition, the high strength and low attrition of the granulated product has benefits for the customer, including reduced risk of pressure drop as well as easy charging and discharging of the product. When assessing the effectiveness of a sulfur guard, the key specifications for performance are: z Total sulfur capacity – strongly linked to the active metal concentration. z Kinetic activity.

Figure 1. Typical layout of a PURASPEC absorbent bed.

The kinetic activity of the product will be influenced by factors such as particle size and porosity of the product, and this has an effect on the mass transfer zone (MTZ). The MTZ is the volume of material required to reduce the inlet H2S content to undetectable levels, and is the difference between the initial sulfur breakthrough and the total saturation capacity of the bed indicating the efficiency of the rate of reaction and sulfur removal, so the lower this value and the closer together these two points are, the better. To demonstrate this, Figures 2 and 3 show a fixed bed of product and its pick-up of sulfur over time. As gas containing H2S passes over the bed, a profile of how much of the bed is saturated is generated, with the darker grey colour indicating the copper sulfide forming from this reaction. For a period of time, no H2S is seen in the exit of the bed but as the product begins to saturate, H2S slip is observed until eventually inlet H2S concentration becomes the same as the exit concentration, i.e. the bed is saturated. For an ideal absorbent the preferable result is a long initial breakthrough time as well as short MTZ, which suggests the product is being utilised efficiently as this will translate into longer bed lives and reduced change-out of the vessel with fresh material.

How the sulfur absorbents work

Figure 2. Schematic showing gradual saturation of the bed of absorbent material with H2S.

August 2021

H2S reacts with the copper active sites on the surface of the granule forming copper sulfide. This causes a shrinkage of the primary crystallites, which generates porosity in the granules and, therefore, allows for easier access for the H2S to react further with the active copper in the bulk of the granule – i.e. no mass transfer diffusion limitation, which is

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especially important at low temperature operation. This process continues until the material is fully converted to copper sulfide and spent. This is associated with a change in colour from green to black.

The evolution of the technology

Figure 3. The bed exit H2S profile generated during processing of gas containing H2S. Note the MTZ is elongated on the graph as the test is an accelerated laboratory test using % levels of H2S in the feed gas.

Figure 4. Graph illustrating the improvement in performance of JM’s sulfur guard absorbent products.

JM has references in gas purification dating back to 1984 and has supplied products for both onshore and offshore applications in the gas processing industry. The initial purification product developed by JM was based on developments of the high temperature zinc oxide absorbents used in syngas markets. Such developments showed great improvements in low temperature performance over those original formulations but were still lower than ideal for the application. The first-generation copper-based mixed metal product, PURASPEC 1030, was developed in the 1980s and was successfully installed in numerous plants as a replacement for the previous zinc-based technology, showing vastly improved performance at low temperatures. During the 1990s, PURASPEC 1038 was developed as the next generation sulfur guard with an improved combination of composition and physical properties which improved sulfur pick-up performance by 50%. JM developed PURASPEC 1039 in the 2000s and it has a higher copper content than PURASPEC 1038, meaning it is able to remove higher amounts of sulfur per unit volume of absorbent. In addition, the use of enhanced manufacturing techniques allowed an increase in the density of the material while retaining good kinetic performance. This improved manufacturing capability also led the company to develop PURASPEC 1038A, JM’s current standard product. Since the launch of PURASPEC 1039, JM has continued to innovate in the area of sulfur removal, and now through a combination of improved manufacturing processes and control of the granule structure this has resulted in the launch of PURASPEC 1065, the highest sulfur capacity of any of the company’s products to date (Figure 4).

The latest product PURASPEC 1065 has been developed as JM’s new high capacity, high activity product. It is an extension of the company’s current offering and encompasses: z An increase in the amount of active phase in the product. z An increase in the product density.

Figure 5. Graph showing the comparative performance between JM’s sulfur guard absorbent products.

August 2021

The product also has a smaller particle size compared to the previous generation products to increase the geometric surface area in the bed and reduce potential diffusion limitations. As it has a relatively high density, this smaller size granule gives the product fast removal kinetics and low MTZ, ensuring a high sulfur pick-up per volume of the absorbent. The reduction in particle size could cause an increase in differential pressure (DP) in the purification vessel. However, the superior sulfur capacity allows the loading of smaller quantities of PURASPEC 1065 (in existing applications) to negate a

Figure 6. JM sulfur guard granules.

possible DP increase. For new applications, the company’s Technical Services team is able to advise on the appropriate vessel diameter to minimise the DP within duty requirements. This combination of changes provides a product which has a 25% improvement in H2S pick-up over its predecessor. This directly translates into a 25% reduction in the required bed volume of material (lower cost per kg of sulfur removed) or 25% increase in bed life for equivalent bed volume (less frequent vessel change-outs). Performance evaluations on JM’s bespoke test rig have clearly shown the benefit of PURASPEC 1065 in terms of total sulfur capacity and impressive kinetics. The initial H2S breakthrough at the exit of the bed for PURASPEC 1065 occurs at a much later time, alongside a sharp H2S exit profile and short MTZ. Comparative performance of PURASPEC 1065 vs PURASPEC 1039 and PURASPEC 1038A in JM’s accelerated laboratory testing can be seen in Figure 5. The H2S removal profiles show that despite having the highest density, PURASPEC 1065 has the lowest MTZ – which is slightly better than PURASPEC 1038A and approximately 15 - 20% lower than PURASPEC 1039. The improvement in performance and reduction in OPEX/CAPEX also offers positive environmental, health, and safety benefits. The use of smaller vessels to give the same bed life compared to the predecessor materials or a reduced change-out frequency of existing vessels yields a reduced carbon footprint from transportation of products. Less frequent change-out means fewer inherently hazardous operations being required to maintain continuous sulfur removal from a process.

August 2021

JM has developed this product over the past few years through rigorous lab, pilot, and full scale manufacturing trials, and subsequent characterisation and performance testing. It has been designed with the needs of the company’s customers in mind, with the intention to resolve problems such as increased sulfur content of their hydrocarbon feedstock and high OPEX due to change-out frequency. The product was launched in 2019 and since then it has been utilised in significant quantities by several customers in the gas processing field. PURASPEC 1065 has been designed to be an authentic solution where there are real constraints on either vessel size or bed life to provide the customer with a costeffective solution. As an example, PURASPEC 1065 has been implemented as a solution to a customer who has a floating production storage and offloading (FPSO) facility as a replacement for a liquid scavenger. As the H2S levels to this facility increased in recent years, the customer found that its current sulfur removal technology of injected liquid scavenging chemicals was not optimal and the operating costs with these chemicals had risen. Given the space constraints at the facility and increased levels of sulfur, JM’s high capacity PURASPEC 1065 was selected as the optimised solution following assessments by the process engineers with support from JM’s Technical Services team. As well as consistently seeing the benefits of PURASPECb1065 in the company’s own assessments, JM now has a written letter of recommendation from a further key customer confirming how well it has performed in their specific duty: “On behalf of bp, as owner of the Gas Sweetening Facility at Sullom Voe Terminal, Shetland, I can confirm we are currently making the transition from the PURASPECb1039 product to use JM’s PURASPEC 1065 for the desulfurisation of natural gas. We have carried out extensive trials on the new product and have seen a marked increase in our capacity and performance of the product. As a result, this has provided us with cost savings on bed change-out frequency and also allowed us to increase our capacity within the facility. Throughout the introduction and continued use of PURASPEC 1065, JM has provided consistent, strong, technical, and commercial support in optimisation of the facility to ensure the product is performing in the best possible manner. I have been hugely impressed with the above and beyond service and technical knowledge of JM over the last 12 months.”

Conclusion The effective removal of hydrogen sulfide from natural gas as LNG feedstock is essential to protect end users, the environment, and downstream process equipment. JM has a long history of offering robust and active products for this purpose. PURASPEC 1065 is the latest product with the highest sulfur capacity to date, which is a leader in the fixed bed absorbent market, benefitting the customer in terms of both a reduction in cost per kg of sulfur removed and in reduced OPEX due to less frequent change-out being required.

Note PURASPEC is a trademark of the Johnson Matthey group of companies.

Francisco Maza Luque, Repsol, Spain, takes a look at the innovations that are helping to make Spain the first port of call for LNG bunkering operations.

arlier this year, Repsol completed its first LNG bunkering that offset the emissions associated with the vessel’s LNG consumption. The spot operation inaugurated the commercial use of the new Cartagena bunkering facility in Spain and was co-ordinated exclusively by telematic means to enhance safety. The operation confirms Repsol and Spain as an attractive bunkering option. On 5 March 2021, Repsol completed an LNG bunkering operation to the vessel Fure Vinga in the port of Cartagena in eastern Spain. The operation, that supplied 420 m3 of LNG to the Swedish-owned chemical tanker with a length of

150bm and a beam of 23 m, lasted approximately four hours and was performed without incidents or delays. This novel supply of LNG to a ship for use as fuel was carried out at the facilities of Enagas, with the support of the Port Authority of Cartagena and the Maritime Captaincy of Cartagena. The bunkering operation inaugurated the commercial use of the new Cartagena bunkering facility, after the finalisation of recent modifications and a first pilot operation carried out in 2017, thanks to the collaboration between Repsol and Enagas. The combination of the extensive bunkering experience of an operator like Repsol

Figure 1. Chemical tanker Fure Vinga.

and the expertise that Enagas has accrued over the decades made this operation a success. The operation aggregated several innovative characteristics that made it unique and very different from other similar operations carried out in the past in different ports in Spain. These innovations have been the result of the extensive co-operation between different units within Repsol and all stakeholders involved, starting long before the operation took place. A very promising aspect of this procedure was the short time frame between the day that the bunkering operation was agreed and the day the Fure Vinga was supplied with LNG in Cartagena. Only one week passed, which was a new record for a spot operation of this kind in Spain. This was made possible because of all the work that was undertaken prior to even envisioning the operation, as well as the closer convergence of the LNG bunkering practices to those that are usually seen on the MGO and bunker fuel side. The co-operation and the extraordinary professionalism of the Swedish shipowner Furetank Rederi, owner of the Fure Vinga, was also very important when reacting to the request with such short notice. Repsol also decided to adapt its procedures to make it possible to co-ordinate all parts of the operation by

Figure 2. LNG bunkering operation to vessel Fure Vinga in Cartagena, Spain.

telematic means. Thus, there was no direct contact with the vessel’s crew at any time, contrary to the normal way to proceed in this kind of operation. To make this possible, it was essential to prepare a detailed plan and, during the operation, carry out a precise and agile co-ordination between the vessel, the operators at Enagas’ terminal, and Repsol’s personnel in Cartagena and Madrid, Spain. This way, the safety of the operation was guaranteed amid the current COVID-19 situation.

Lower LNG loading tariffs in Spain Repsol has been working for almost a decade on the elaboration and certification of a wide range of procedures, checklists, and operational standards for a large variety of potential bunkering operations in Spain. The company has engaged with many different port authorities to work out specific technical and risk assessments, and it has carried out numerous operations in different locations, ranging from the simplest truck-to-ship LNG bunkering supplies to dual fuel bunkering operations and terminal-to-ship supplies. In total, Repsol has offered LNG bunker solutions to 21bdifferent vessels, from tugboats to chemical tankers, with very different bunkering systems, connections, and procedures. Needless to say, one of the foundations of the operation is the presence that Repsol has in the Spanish Gas System, as well as the commercial and trading capabilities needed to source the LNG at a price that makes Repsol in particular, and Spain in general, an attractive bunkering option for a vessel to call at a Spanish port. The competitiveness of Spain as a bunkering location has recently received new incentives in the form of a very significant reduction of the LNG loading rates charged by the Spanish Gas System Operator. On 26bSeptember 2020, the Spanish supervisory agency, the CNMC, published the new rates applying to these types of services, reflecting an average discount of approximately 90% compared to previous rates. For this particular operation, there was a discount of 98%. Repsol also took advantage of the developments and modifications of the jetty used in the operation, carried out as a part of the CORE LNGas Hive project that is co-financed by the European Commission. It is led by the Spanish Port Supervisor, Puertos del Estado, and co-ordinated by Enagas. The project, in which Repsol also participates as a sponsor, is developing safe and efficient integrated logistics and supply chains for LNG in the transport sector (small scale and bunkering), particularly for maritime transport around the Iberian Peninsula. It contributes to the decarbonisation of the Iberian EU transport corridors of the Mediterranean and the Atlantic, and it is a step forward in the efforts to reduce emissions, promoting the use of clean energy for transportation in accordance with the roadmaps of the EU. One of the activities carried out under this project is the modification of the Spanish regasification terminals to supply LNG for ships, including the bunkering facility in Cartagena.

First time compensating total CO2 emissions Figure 3. LNG bunkering operations in Spain carried out by Repsol.

August 2021

The operation in Cartagena was also the first time that Repsol, as a supplier of LNG, has guaranteed the compensation of the total CO2 emissions associated with

the consumption by the vessel of this LNG. Emissions were compensated through the purchase of CO2 credits (verified emission reductions or VERs) in the voluntary carbon market. In this case, the credits purchased come from a project in Brazil with the main objective to avoid and prevent unplanned deforestation in native forests. Repsol has defined a very specific and demanding set of criteria for the selection of these projects, based mainly on the type of project, the standard under which it is certified, and the social and environmental benefits that the project brings at a local level. For Repsol, it is not only about reducing emissions and contributing to mitigating climate change. It also places a special emphasis on the standards such as the climate, community, and biodiversity standards (CCBS) Gold level that assess social and environmental impacts in detail, including the protection of biodiversity. This not only consolidates Repsol’s position as a supplier of LNG for maritime transport but also sets the milestone of a first compensated LNG as a bunker fuel supply. With this new bunkering operation, Repsol is completing its capabilities to serve the shipping industry in a more efficient way, offering reliable and agile LNG bunkering services as it has traditionally done with other fuels. This is a further step towards the company’s goal of achieving net zero emissions by 2050, offering shipowners the possibility of making their commercial routes more efficient and environmentally friendly. In line with this objective for reducing greenhouse gas emissions to the atmosphere, and in addition to the supply of carbon-neutral gas and LNG by compensating CO2 emissions purchasing certified credits, Repsol is also adding biomethane to its portfolio in the short-to-medium-term. It is developing the possibility to supply LNG with Guarantees of Origin of biomethane from European production (shortterm) and biomethane projects in Spain with a focus on value creation for final gas users (medium-term).

Figure 4. LNG loading from terminal regulated tariff at Spanish Gas System. New and former tariffs.

Figure 5. CORE LNGas Hive Project.

Figure 6. Pacajai REDD+ Project in Brazil.

New bunkering stations in northern Spain Additional steps are expected soon since Repsol is building two bunkering stations in northern Spain, in the cities of Bilbao and Santander. These facilities, each one with a storage capacity of 1000 m3 and a pumping capacity of 600bm3/h, are expected to be in operation in 2022 and 2023, respectively. They will allow LNG bunkering operations to be performed while other simultaneous operations are carried out within the vessels and the port area. Both facilities are co-financed by the EU under the framework of the Connecting Europe Facility (CEF) programme. Repsol is building these capabilities jointly with its partners and stakeholders in Spain with whom it shares the vision of Spain as an LNG bunkering hub in the future. Spanish ports and Spanish operators are demonstrating that they are able to compete with other European ports when offering these services. As LNG becomes an increasingly valued alternative for shipowners for use in shipping, Repsol is convinced that Spain will come to play an ever more important role in the reduction of emissions, in line with the regulation of the International Maritime Organization (IMO).

Figure 7. Repsol roadmap for decarbonisation.

Figure 8. General view of the LNG bunkering terminal, 3D model.

August 2021

Pádraig Kelleher, MAN Energy Solutions, Denmark, details the technology behind a new, low-speed, dual-fuel engine designed for LNG carriers.

AN Energy Solutions demonstrated its latest low-speed, dual-fuel engine – a MAN B&W ME-GA type designed for LNG/fuel oil running – at a ceremony live-streamed from the company’s Copenhagen Research Centre, Denmark, in March 2021. The new engine is an Otto-cycle variant of the company’s successful ME-GI engine. The ME-GA engine has already been specified in several LNG carrier new-building projects with the first order imminent, according to the company. Testing of the first, commercial ME-GA design is expected to begin by the end of 2021, with the first engine delivery following in early 2022. The MAN B&W ME-GA engine is aimed at vessel types and applications where low capital outlay is a priority, such as Aframax tankers. Furthermore, the engine will be Tier III compliant in gas mode without emissions-abatement equipment. The ME-GA engine features the following concepts: z The well-proven MAN B&W dual-fuel platform. z Unique gas admission concept with minimal installation and operating costs. z Well-known engine room design similar to ME-C/ME-GI engines.

Engine philosophy The ME-GA engine is a pre-mixed, dual-fuel engine type, where methane is admitted during the compression stroke (Figure 1). This allows for a low gas-supply pressure, which is advantageous for vessels with larger amounts of boil-off gas (BOG), such as LNG carriers. The ME-GA version features some of the most successful concept ideas from ME-GI and ME-GI Mk. II platforms.

Gas admission concept The simple supply and purging concept minimises installation costs. The gas admission system is designed to enable a safe and reliable operation at the lowest possible costs.

Supply and purging concept The safety and purge concept from ME-GI Mk. II has been adapted to the ME-GA version with the introduction of beneficial features. Rather than injecting nitrogen from the gas valve unit (GVU), the nitrogen is applied at the engine end, and the purged volume carried along existing piping. This simplified solution reduces the amount of pipework and components, and significantly lowers the volume, reducing nitrogen consumption.

Safe gas admission valve The safe gas admission valve (SGAV) placed in the cylinder liner has been developed as a unique and simple component, which provides both the ultimate safety against gas leakage into the cylinder and secures optimal conditions for gas admission. Since the SGAV contains a gas admission as well as a window valve in one unit, the safety against gas leakage into the cylinder is doubled. Basically, the improved safety eliminates additional requirements for complex monitoring as a safety precaution, as opposed to other low-pressure, dual-fuel, two-stroke engines. The SGAV design gives room for easy overhaul of the valve itself, along with maximum space for overhaul on the engine top.

Gas regulating valve In order to achieve a simple and easy installation of the ME-GA engine and the

fuel supply system, a hydraulically-actuated, gas pressure regulating valve has been developed. The valve is controlled directly from the engine control system, simplifying the requirements for control of the supply system. Moreover, the gas regulating valve enables depressurising of the system without dedicated blow-off

piping. The hydraulically-actuated bypass valve is of similar design to the ME-GI blow-off valve.

Pressure-equalised, three piston ring package MAN Energy Solutions’ experience with the development of piston ring configurations for different engine types, combined with know-how gained from ME-GI operations, has enabled the development of a rigid and reliable piston ring package for the ME-GA engine. A ring package similar to the wellknown, pressure-equalised, three-ring package for the ME-GI engine (Figure 2). The properties of the three piston ring package are achieved by combining the controlled gas leakage of the first and second rings with a gas-tight third ring. The advantageous combination ensures an even pressure distribution, featuring: z Minimum build-up of deposits in the ring grooves. z More robustness against ring collapse than typical applications with a gas-tight top ring.

Figure 1. Pre-mixed dual-fuel combustion.

These properties are the basis for obtaining satisfactory cylinder conditions on the ME-GA engine and for giving the large freedom to optimise the combustion process. The design of the ME-GI ring package has endured millions of running hours accumulated in service on MAN B&W G70 engines. Low wear rates show that the time between overhaul of piston crown and piston rings is well within MAN Energy Solutions’ guidance values.

Adaptive cylinder control

Figure 2. Design of the three piston ring package.

The ME-GA engine platform is being launched with MAN Energy Solutions’ new Triton engine management system. This system is being integrated with all new ME-GA engines, as well as ME-GI engines. The solution includes an adaptive cylinder control function, which is an integral part of the Triton system. The unique adaptive cylinder control (ACCo) system used on MAN Energy Solutions’ ME-C and ME-GI engines also ensures the best performance and the lowest possible fuel consumption at all times for the ME-GA engine. The system constantly monitors the maximum pressure, the compression pressure, and the mean efficient pressure on each cylinder, and automatically adjusts them if they deviate from shop test results. In this way, for example, counteracting the possible negative impact of varying fuel qualities and calorific values.

Pilot fuel One particular area of focus has been the pilot fuel oil consumption, given its connection with NOx emissions in gas mode for Otto-cycle engines. In gas mode, the ME-GA engine required no more than 0.5% pilot fuel consumption. The ME-GA design also includes a microbooster system, which allowed high sulfur fuel oil to be used for pilot fuel injection in Tier II gas mode.

Cylinder oil requirements Figure 3. Milestones in the development of the ME-GA engine. MAN Energy Solutions aims to start testing the first commercial ME-GA design by the end of this year, with the first engine delivery following in early 2022.

August 2021

The ME-GA engine is expected to have similar cylinder oil requirements to the existing ME-GI engine. While MAN Energy Solutions recommends the use of a BN40 Category II cylinder oil as soon as it becomes available, it would currently recommend a BN100 Category II cylinder oil.

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Combining the ME-GA engine with EGR Unlike other two-stroke manufacturers’ Otto-cycle low-speed engine after-treatment options, the ME-GA employs a high-pressure EGR system. While this requires a blower and small, associated parasitic load-increase, it means the system fits into existing engine rooms. EGR is an option available for the ME-GA engine to ensure Tier III compliance when running on diesel. EGR is an effective way of reducing NOx emissions from the diesel combustion process with only a marginal negative impact on the combustion process itself (specific fuel oil consumption – SFOC). Testing of EGR and the ME-GA engine in diesel mode as well as gas mode has revealed, as expected, that EGR efficiently reduces NOx emissions, also in gas mode. In addition, the test has shown that EGR is a strong and efficient tool for improving the gas combustion process of the pre-mixed, Otto-type engine. Specifically, the EGR application optimises ME-GA operation by:

z Suppressing pre-ignition (operation on different gas qualities is possible). z Suppressing excessive combustion rates (the improved cylinder condition gives better operating conditions for the piston ring pack). z Improving optimisation possibilities of specific gas consumption (SGC) due to the increased compression ratio and optimised gas admission. z Reducing the heat load due to the optimised gas admission. z Improving the SFOC in diesel-operating mode (NOx constraints are removed). z Reducing methane slip. The EGR application reduces SGC and SFOC compared to an ME-GA engine running without EGR. SGC is reduced approximately 3% in the complete load range, when operating in gas mode, and SFOC approximately 5%, when operating in diesel mode. EGR also significantly reduces methane slip by 30 - 50%, and improves the stability of the Otto-cycle combustion process.

Compliance with emissions regulations As the pre-mixed combustion results in low NOx emissions, the ME-GA engine is inherently Tier II and TierbIII compliant in gas operation mode. To utilise the dual-fuel potential (gas and diesel operation) in Tier III areas, the ME-GA engine requires application of EGR or SCR.

Optimal CAPEX

Figure 4. The MAN B&W ME-GA engine pictured at MAN Energy Solutions’ Research Centre in Copenhagen, Denmark.

Several of the ME-GA’s design features reduce CAPEX costs during vessel construction, for example, the separation of the GVU from the gas regulating unit within the design. By locating the GVU outside the gas-safe area, this eliminates the need to install a cofferdam box in the engine room, as the unit does not need to be specified to comply with gassafe-area rules. The ME-GA’s purging concept, as previously detailed, is derived from the ME-GI concept and also leads to CAPEX reductions.

Conclusion

Figure 5. Rendering of MAN Energy Solutions’ new 5G70 ME-GA low-pressure engine.

August 2021

For LNG carrier designs that benefit from an Otto-cycle engine concept, the market is hungry for an alternative. In current new-building projects, MAN Energy Solutions’ experience is that designs that feature performance and emission benefits via EGR are preferred. Within the LNG carrier market, contracting is expected to remain stable at approximately 70 ships per year with modern carriers with dual-fuel, low-speed propulsion and reliquefaction in demand. For those (yet undisclosed) LNG carrier projects where ME-GA has already been specified, a number of particular points have proven important, namely that performance and emission benefits are reliably delivered via MAN Energy Solutions’ integrated and proven EGR system; and additionally, the company’s long track record of taking new engine designs from concept to reliable worldwide engine operation. Moreover, the ME-GA engine’s easy tailoring for application aboard contemporary LNG carriers is advantageous.

Dean Standiford, VSL, the Netherlands, explains how insulating a flowmeter can affect the flowmeter temperature measurement value and how this can affect the mass flow output.

NG has traditionally been used to transport natural gas across the world to supply areas where it is not readily available. This is achieved using LNG carrier ships that are designed for cryogenic storage and with specific volumes based on the level of LNG in the storage tanks. Transport companies make level measurements after loading the ship with LNG and again when the LNG is unloaded. The difference between these two measurements is the total volume of LNG transferred which is used in the final energy calculation. There are many corrections made to each measurement in this process to obtain the corrected volume.

Correction tables for list and trim of the ship are used for the level measurements. Gauge tables are used to convert the level measurements to volume and LNG fluid properties are used to obtain the corrected volume. This is all applied twice, once during loading and once during unloading, to obtain the final transferred volume. Transferring a full load of LNG (typically approximately 150b000 m3) creates a large difference in the beginning and ending measurements, which allows the measurements and correction errors to be less precise without any commercial impact. The transition to clean energy has been driving the demand for LNG into new markets such as marine bunkering and land-based mid to small scale LNG trade. The transition of LNG into these new markets where smaller amounts of LNG is being transferred and measured has prompted a transition to new measurement methods utilising existing measurement technologies such as inline dynamic mass flow measurement. According to the latest edition of the GIIGNL LNG Custody Transfer Handbook 6th Edition 2021, “LNG flow metering using mass flow (Coriolis) meters and/or volumetric (ultrasonic) flowmeters is gradually being introduced into applications of LNG fiscal measurement in small scale operations.” Dynamic mass flow measurement is standard practice for most liquids in custody transfer following OIML R-117,

“Dynamic measuring systems for liquids other than water” and OIML R-81, “Dynamic measuring devices and systems for cryogenic liquids”. These standards describe the term ‘influence quantity’ as, “a quantity that is not the subject of the measurement but that can influence the value of the measurand…” noted as being relevant to electronic measuring systems. This article will discuss the flowmeter temperature measurement as an influence quantity that is relevant when using a Coriolis flowmeter for inline dynamic mass flow measurement. Specifically, how insulating the flowmeter can affect the flowmeter temperature measurement value and how this can affect the mass flow output.

Coriolis flowmeters

Coriolis flowmeters measure the Coriolis effect induced by fluid flowing through one or more tube(s) vibrating at their natural bending frequency. The fluid flow through the tubes causes the vibrating tubes to twist at their natural twist frequency. The vibrating and twist frequencies are influenced by the stiffness of the tube’s material, and the stiffness of the tube’s material is influenced by the tube’s temperature. The measured Coriolis effect is used to calculate mass flow using a calibration constant. The calibration constant is typically determined while flowing ambient temperature water through the tubes in a laboratory calibration system. During use, the calibration constant is corrected for other fluid temperatures, usually within the flowmeter transmitter, using the difference between the current temperature and the initial calibration temperature. The correction is based on the change in stiffness of the material due to a change in temperature, or Young’s modulus of elasticity. For 316 stainless steel this value is approximately 4% for every 100˚C, when derived in terms of mass flow error per ˚C. Coriolis flowmeters measure the tubes’ material temperature, not the fluid temperature, to correct the calibration constant. This is usually undertaken with a temperature sensor on the outside of the tubes, or on the flowmeter body close to the tubes. The temperature sensor relies on heat transfer Figure 1. VSL’s LNG mid scale loop calibration facility. properties between the fluid and the tubes’ material to make an accurate measurement. The heat transfer processes in cryogenics are essentially the same as for any engineering temperature range. Heat transfer at low temperatures is governed by the same three mechanisms present at ambient and elevated temperatures: conduction, convection, and radiation. However, due to the cryogenic condition of LNG there are other complications that lead to the inconsistency of the thermal properties, or mechanisms stated above. Within conduction, convection, and radiation are several variables contributing to these inconsistencies. Flowrate for conduction, ambient temperature for convection, and sunlight for radiation to name just a few. In addition, there is also the size of the flowmeter, tube Figure 2. Flowmeter under test (MUT) section of VSL’s LNG calibration geometry, installation location, and whether the facility. flowmeter is insulated.

August 2021

An LNG calibration facility

when the flowmeter insulation is removed. This becomes an influence quantity as it affects the mass flow reading from the Coriolis sensor. The temperature measurement bias is consistent between line sizes and has an overall negative impact on the mass flow measurement error. The temperature measurement error and temperature stability are also impacted by flowrate. The largest deviations can be seen at the lowest flowrates where there is less heat transfer from the fluid and more convection from ambient heat sources. Low flowrates also lead to a much longer cool down period before measurements can be made with acceptable repeatability. However, the temperature measurement bias remains even with longer cool down periods.

In 2019, VSL commissioned the world’s first SI-traceable mid scale LNG calibration facility utilising VSL’s primary LNG mass flow standard that was realised in 2014. The combination of these two facilities (Figureb1) gives VSL the ability to provide calibrations and performance testing of LNG flowmeters at the end user’s actual cryogenic conditions with a reference mass flow uncertainty of 0.17% (k=2). VSL’s mid scale loop runs LNG at flowrates from 4bm3/h to 150 m3/h (1800 kg/h to 67 500 kg/h) at approximately 5bbar (gauge) and -165˚C. The mid scale loop has two flow paths and can accommodate flowmeter line sizes from DN25 (1 in.) up to DN150 (6 in.) (Figure 2). Figure 1 shows a large blue structure that covers the two flow paths, or flowmeter under test (MUT), sections shown in Figureb2. During calibrations, the structure prevents most of the rain and radiation effects from the sun, but the flowmeters are exposed to wind and humidity. On a flowmeter without insulation, wind and humidity can affect the amount of frost build-up on the flowmeter body. Frost builds up on the flowmeter body and acts as an insulating layer, reducing ambient temperature effects. However, the amount of frost build-up can be extremely variable depending on the current outside conditions which can impact the insulating properties of the frost layer. Having performed multiple calibrations under cryogenic conditions, VSL has learned that both ultrasonic and Coriolis meters show a flow measurement bias when the meters are not insulated. Coriolis meters also indicate a bias in the flowmeter temperature measurement error

Conclusion As the transition to clean energy continues to drive the demand for LNG into new markets, it makes good business sense to utilise new measurement methods, such as inline dynamic mass flow measurement, to improve measurement accuracy during trade. However, cryogenic conditions are very different than reference temperature water used for most flowmeter calibrations, and a good understanding is required of all the influencing factors that are present. The new mid scale LNG calibration facility, with its low mass flow uncertainty (0.17%, k=2), enables VSL to perform SI-traceable calibrations on cryogenic flowmeters that match the end user’s process conditions. This leads to a better understanding of the cryogenic influence factors and an improved measurement accuracy in their installation.b

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arlier this year, Kongsberg Digital (KDI), BW LNG, and Alpha Ori Technologies signed a strategic digitalisation partnership to develop digital capabilities to enhance efficiency and reduce the environmental footprint of LNG carriers and floating storage and regasification units (FRSUs). The agreement encompasses several projects and includes utilising a common data management platform and developing maritime digital twins and digital processing models to facilitate operational excellence. BW LNG has been a partner with KDI for some time and the company’s ships, including LNG carriers, already contain an extensive array of Kongsberg equipment on board. This equipment manages and monitors the cooling, storage, and boil-off from the tanks. KDI also has systems for fiscal metering the gas – the custody transfer system (CTS), which is developed and sold by Kongsberg Maritime. The partnership with BW LNG is focused on how digitalisation and specifically digital twins can enable new ways of working in the LNG industry. KDI aims to develop solutions that bring data from various sources together and combine it into an overarching decision support system. This enables the optimisation of energy consumption of LNG carriers, and the gas production and export process on FSRUs. It is a large and complex value chain, and the challenge is to collect data from assets, contextualise it, and deliver critical insights in a decisionsupport context, enabling intelligent decisions around planning and maintenance.

An evolving sector The LNG industry is, relatively speaking, still an evolving sector. It remains a capital-intensive industry, and infrastructure build-out requires highly specialised equipment. Traditionally, upfront investments in such infrastructure have been supported by long-term contracts based on fixed-point delivery from point A to point B. Counterparties were known and deals were made on a long-term basis. More recently, with the development of a

more diverse market, that trend has started to edge in the direction of greater flexibility with rapid expansions and new markets emerging online. This has resulted in the need for more flexible arrangements between the parties and a requirement to manage optionality in terms of getting the most out of LNG, both commercially and operationally. The major trade routes for LNG are still intact, but China has emerged as a significant consumer recently overtaking Japan as the largest global LNG importer. On the supply side, there are the traditional locations such as Qatar in the Middle East, but recently the US has grown substantially.

Managing operations in an unstable and evolving market It is the evolving nature of the market that has encouraged prominent industry players to take more expansive end-to-end positions. For such a strategy to be successful companies require better insight, not just long-term and mid-term horizon planning, but real-time management and decision support. That is what KDI helps enable through digital twins. Through ecosystems of digital twins, the company can elevate operational data related to how a commodity is produced, stored, loaded, and transported on its way from point A to point B, touching upon every aspect of the value chain including the fuel consumption involved and the performance of the export and import terminals. This insight provides LNG operators taking these end-to-end positions with an integrated view of their LNG volumes and value chain, a discipline historically restricted to energy trading risk management (ETRM) systems, or in some cases custom bolt-on solutions. Digital twins deliver the necessary operational perspective that allows people to make more rapid near-term decisions. A digital twin of an asset in the value chain, such as an LNG carrier or import terminal, could inform the operator about the current inventory position. It can also provide an insight into the quality and the predicted quality of the LNG,

Haavard Oestensen and Andreas Jagtøyen, Kongsberg Digital, Norway, explain how the complexities of a volatile LNG market can be navigated with digital twins.

which is where the digital twin comes to the fore. With an integrated view that encapsulates real-time ageing calculations and support for digital custody transfers, it allows the operator to make informed decisions based on granular and high-fidelity data. In the shorter time horizon, it can advise a carrier to divert cargo to a different port or decide to carry out a ship-to-ship transfer based on intelligence on how that will impact the volume.

Creating a network of twins Achieving this requires not just a digital twin of the asset being managed but an ecosystem of digital twins representing that infrastructure from point A to point B, across a portfolio with operational optionality built in. The first step on this process is to make all the current information available. On top of this all the operational data points need to be layered in, including quality, location, commercial information, and technical supporting information regarding the facilities. The maturation of digital twin technology has allowed KDI to embed more than one twin at a time. With this ecosystem, data between digital twins can be shared and this can be leveraged across the entire portfolio to enable assessment of the impact – not only on the asset being directly managed but any indirect impact across the entire system.

Figure 1. Digital technologies are forecast to save operators between US$100 billion and US$1 trillion by 2025.

What KDI is delivering through this system of digital twinsbis the connection between OT and IoT on ownership. It fetches contextualised data from the different systems onboard the ship. It brings the data into a harmonised cloud platform, which is then available for various applications through an API. This is undertaken to fetch data from different sources onboard the ship, contextualise it, and put it into an asset model and harmonised model to compare data from one vessel to another. This data is then made available for different applications, like a digital twin or a performance optimisation tool. For the shipping industry, a digital twin is considered as more of an application, while as for the production plant or the oil and gas industry, it is more of a platform. It has greater granularity, and compared to oil and gas, they have a different purpose. But they have the same result in that data can be bridged from one part of the value chain such as maritime, into other parts of the value chain such as gas trading. Bringing data from a different application and making it available for the larger value chain and new stakeholders in the industry is what the company is working on.

The digital difference The transportation of LNGbis more complex than other typical cargo trades. This is in part because the gas onboard in the cargo tanks is also consumed as fuel for the vessel. When delivering a cargo at an import terminal, storage volume has decreased, the LNG may have a different composition, and there is less energy onboard for completion of the transaction. When using energy from the tanks for propulsion, it is essential to understand how much, to stay within specifications. Additionally, weather conditions can affect the rate of boil-off, and the amount of fuel used from the tanks will depend on the routing. Whatbhas made a real difference is the ability to layer operational information into a management portfolio. Operators finally find themselves with an avenue to tie in all that operational end-to-end data that is unique for LNG. The attempts that have been made up until this point have mostly centred on trying to get a better idea of quality, deliverability, and contractual options. KDI is now bringing operational reality into a particular value chain with high-cost infrastructure and a very low tolerance for errors along that value chain. If where the LNG is to be delivered has been miscalculated, the vessel can be diverted, but LNG will be consumed on the way to the next terminal. There will be a limited set of terminals that can take the LNG quality without degrading LNG that is already in the system on the other side. That is what is on the more visionary ends; KDI has the ambition to deliver into the market.

Conclusion

Figure 2. Kongsberg’s digital twin is a full facility virtualisation that leverages collected information to describe the current situation and predict how the asset will behave in its environment over time.

August 2021

In sum, with KDI’s digital twin technologies, the company is delivering the decision support to make intelligent choices based on improvements in both descriptive and predictive insights. Better insight and, in turn, decision support leads to efficiency in operations and shipping, putting those operators at an advantage compared to others; ultimately serving their markets with better quality. At the end of the day, it is all about meaningfully elevating operational data from across the LNG value chain to enable improved decision making.

Gregory Sudwoj, WinGD, Switzerland, discusses the importance of virtual seafarer training for the safe and effective operation of LNG vessels.

n March 2021, classification society DNV reported a record month for new-build LNG-fuelled vessel orders, taking the total for 1Q21 to beyond the final count for the whole of last year. The 265 gas-fuelled vessels on the orderbook (more if LNG carriers are included) will more than double the global fleet. While much energy goes into projecting the supply and infrastructure that will be needed to support that growth, less focus is placed on the extra demand it will create for seafarer training.

Training is crucial for seafarers embarking on service on LNG-fuelled ships. But while the International Maritime Organization’s (IMO) Standards of Training, Certification, and Watchkeeping (STCW) convention requires that engineers on gas-fuelled ships are trained in LNG bunkering, it does not require training in other LNG-related ship equipment, including engines, so far. Equipmentspecific training is therefore defined as ‘added value’ and left to the discretion of ship owners, operators, and managers. According to WinGD’s General Manager Customer Training, Operations, Gregory Sudwoj, the case for specific gas engine training is clear, and it is not necessarily about the fuel. “Marine engines in general are getting more complex and require more understanding from the crew to operate them in an optimal and safe way,” he says. “Training for the specific type of engine is getting more important, including for gas-fuel engines.” Much of the complexity comes with modern electronic control systems (ECS). For this reason, WinGD’s courses are categorised by control system rather than engine model. The ECS is essentially the brain of the engine. It is the key to understanding what happens with an engine, its operation and efficiency, as well as indications of failure and troubleshooting.

Figure 1. Full mission simulator.

Figure 2. WinGD training simulator room in South Korea.

August 2021

WinGD’s X-DF dual-fuel engine designs are available with two control systems, UNIC or the recently launched WinGD Integrated Control Expert (WiCE). Training across the entire portfolio can therefore be covered by two courses, making the training widely applicable. Crew members can move between vessels with engines of different sizes and still be familiar if the control system is the same. All new WinGD engines now use WiCE, meaning that in the future the whole dual-fuel engine series could be covered by a single course. As so often during the evolution of LNG in shipping, investment in supporting infrastructure comes in advance of market growth. WinGD is preparing for the anticipated boom in training demand in several ways. As well as extending the availability of its courses with training partners, it is also developing its cloud-based training platform, enhancing its engine room simulations, and adding new training programmes to meet emerging needs. The focus is on making training less burdensome, more valuable, and more flexible, both for shipping companies and for crew.

Expanding the training network The operational training course – which can be distinguished from maintenance courses and advanced operational courses offered by the company and its service partners – is a five-day programme that has traditionally been taught in classrooms at WinGD’s facilities in Winterthur in Switzerland, Busan in South Korea, and Shanghai in China. One early development has been to expand the training location network by working with authorised training partners. The cost and hassle of travelling is a limitation for whoever delegates crew members for training. With WinGD’s partners the company can make access much easier and wider, respecting the crews’ time, and removing unnecessary expense and complications from the shipowner. Today the network includes partners in major crewing markets in Asia (the Philippines and India) and Europe (Greece and Poland), as well as the important crew exchange hub of the UAE. In addition to the operational training courses, partners can provide further courses – for example covering the auxiliary machinery typical to modern engine rooms – using computer-based training. WinGD is in discussion with potential partners to further expand its list of locations. Another important means of improving accessibility – especially during the current pandemic – is cloudbased training. From the beginning of travel restrictions in March 2020, WinGD has been conducting training online. However, this was limited to instructor-led presentations which included video from the instructor’s simulation. The company responded fast and by the beginning of this year had developed a cloud streaming service capable of delivering a truly interactive training experience. Every participant can run their own simulation on their PC or laptop. When the instructor gives them tasks, he can see how the trainees are reacting. This is a completely new dimension and is a good substitute for classroom training. WinGD has tested the system in Asia

and Europe and is now building up the server infrastructure.

Simulation developments Full access to simulators is an important element of the cloud service. Simulation has been part of operational training since 2011, when WinGD worked with Unitest Marine Simulators to develop a simulation for the first X35 engine. Focusing on developing the software gives WinGD more flexibility in how the simulation can be used, ranging from personal computers to full mission simulator rooms with 18 touchscreens mounted on real marine consoles. Full mission simulators are particularly valuable where possible as they meet STCW standards for A-class simulators, meaning that time spent training in these scenarios partially counts Figure 3. Virtual X92DF engine room access. Image courtesy of towards experience needed in watchkeeping and other Unitest Marine Simulators. elements of the STCW syllabus. Two cases highlight the value that simulation can bring to WinGD and to the crews of its customers. In the first case, the company delivered software for a full mission simulator replicating the engine control rooms of nine gas-fuelled, ultra-large container ships being delivered for French liner CMA CGM. The vessels, the first of which are already in service, are powered by the largest Otto-cycle dual-fuel engines ever built – the 12-cylinder, 92 cm bore 12X92DF. WinGD developed software for the full mission simulator on which CMA CGM’s crew are to be trained in Marseille, France, once COVID-19 restrictions allow. The simulation is based on drawings of the vessel’s engine control rooms and roughly matches the number of decks on the vessel and other aspects important for familiarising crew. When it comes to the simulated Figure 4. Close-up engine access for detailed training. Image engine behaviour, the simulation is a complete match. courtesy of Unitest Marine Simulators. This simulator is based on the thermodynamic models of the engine that WinGD has verified, which The use of simulation in training continues to evolve differentiates the simulator from whatever other simulators and WinGD is also advancing its own use of simulation. The will appear on the market which would not be calibrated. latest step is adding virtual reality capability, so that WinGD believes it is important to have a true model with trainees wearing goggles can walk through the engine the true thermodynamic response. room and ‘dive into’ the engine structure. Another example comes from the LNG carrier sector, There are further innovations ahead. One area for where WinGD’s X-DF dual-fuel engines have a leading development is the range of training courses that WinGD market share. A skilled crew is particularly important on can offer. As crew are already booked in for five-day these vessels, which are very expensive assets with strict courses, it may make sense to extend the course to add on safety requirements. They are also at risk of spoiling their extra training. WinGD has already developed LNG bunkering cargo if they encounter unexpected delays. courses for ship-to-ship and shoreside bunkering. It is now Gas carrier crew do not require dedicated engine looking at courses for other equipment, including working training, but shipowners have more reason than those in with other LNG technology providers to develop new other sectors to want crew to be familiar with their specific training solutions. engines. WinGD started a project to build an engine room STCW-regulated training for gas-fuelled ships has simulator dedicated for LNG carriers the year. The project justifiably focused on safety and on areas such as should be completed by the end of this year and will bunkering where the potential risks are greatest. But enable gas carrier crews a more realistic training experience. gas-fuelled ships need to be operated efficiently as well as safely, and understanding the engine is one of the most Virtual reality assured ways of helping crew to do this. As the numbers of It is easier for WinGD to train the crew using the specific crew working on gas-fuelled vessels is set to rise set-up of the engine room. In the case of LNG carriers, this dramatically over the coming years, WinGD is making sure is pronounced because they have two main engines and that shipowners have all the training opportunities they there are some extra safety features installed in the engine need to deliver a crew capable of operating their assets room. effectively.

August 2021

Catie Williams, InEight Construction Software, USA, looks at the best practices for visualising data to help communicate information in a clear and effective way.

everal years ago, employees at InEight Construction Software were asked to implement a new cutting-edge set of visualisation tools for a big ERP implementation. At that time, most work that had been undertaken just involved reproducing existing Excel-based types of reports. After all, it was what people were most comfortable with and what they knew. It was traditional and seen as the way things had always been done. Whilst trying to gain buy-in and adoption from InEight Construction Software’s stakeholders, the system was met with resistance and a lack of trust for the visual style reports that the company made available. Over time, as comfort and maturity with the new system increased, tools such as Tableau® and Microsoft Power BI® were on the rise, and a shift started to form in the acceptance of using data visualisations for managing work. Today, with the right data visualisation tools that provide customisable, interactive, even sharable dashboards, comprehensive visualisations can be built to truly help clients and projects in ways that connect people and systems with new transparency and understanding. The speed at which decisions can be made when presenting information in a visual format is staggering in comparison to what it takes going line by line through pages of numbers. But creating effective data visualisations, that require little explanation and immediately draw attention and provide insights, can be

challenging. What follows are several best practices in creating data visualisations.

Colour and layout count When it comes to the topic of colour in data representations, especially within today’s best dashboards, it can be tempting to use lots of it because it looks appealing and can seem impressive. However, if everything has colour then nothing will really stand out. Thus it is wise to use colour sparingly for the best impact. The question that should be asked is what story is the data report or chart trying to tell, and will it communicate the right information that the viewer needs to see? It should not be used just for the sake of using it, but only when there is meaning behind it. For instance, when showing positive and negative values, what is the information that should pop out of that? If the information that the user should be aware of first is a negative number (so they can go and fix the issues represented by that number) then that is what should be seen first. In that case, having a bar chart or a tree map that has fairly muted colours, and something that catches the eye for the negative numbers, may be a good idea. The number of colours used should be limited, though, so the viewer is not overwhelmed. On the contrary, say only greys are used in a chart. There will likely be an almost knee-jerk reaction from the viewer that this chart does not have the information

they need. So again, colour is key. It is also important to keep in mind that approximately 8% of men (one in 12) and 0.5% of women (one in 200) have some form of red-green colour blindness.1 This is the reason that blue and orange are common colours in some tools to represent positive and negative in place of the more traditional green and red. Another very important visual element that should be kept in mind is how the viewer will read the chart. In the US, for instance, people read from left to right. Making sure to place the most important information in the top left and top right is therefore key. It is the most valuable real estate on a dashboard, and if there are only a few seconds to make an impression, that is a great place to start. Metrics that provide actionable information or require action are good contenders for occupying that space. The lower left and right can have more descriptive/informative information, but not necessarily a metric that requires immediate action. A good rule of thumb is to try out dashboards/visualisations on a non-practitioner and carry out some usability testing to understand where they are looking first, what is catching their eye, and what is not grabbing their attention.

Label for clarity Often overlooked are the texts included with the visualisation, such as labels or annotations. For example, a bar chart could be used, however, if it does not have meaningful and understandable labels such as chart title, axis labels, or a legend, a lot of the context behind it can be lost. Thus, the data labels are very important, especially with positive and negative values. Labels should be kept clear and not too dense. It is also a best practice to include an annotation that is brief but describes what is happening in the chart very clearly. For example, “Sales have trended down 10% over the last three months” is a fast, easy way to tell the viewer exactly what they should take from the visualisation. The text supports the visual that is telling that story, without being overwhelming or requiring a significant amount of analysis or effort to read. Positive and negative values can often be difficult to clearly label, so a beneficial trick for adding more clarity is using patterns and/or shapes. If a KPI dashboard has a user requirement that the KPIs are reflected as positive values, they could be made blue and a ‘+’ sign could be potentially included. Or if a project owner requires the use of red and green colours, the use of either an up or down arrow clearly indicates which is considered good vs bad. If negative numbers are used, the zero should be clearly marked. Symbols or patterns can also be used to reflect different categories in a visualisation. For example, if a scatterplot visualisation with different work categories is being used, and it is important to draw the difference between categories to the user, different shapes, such as a circle for one, then a triangle or an X for another, could represent the different categories. This allows the user to quickly realise that for Category A, it is always represented by a circle, and Category B is represented by an X. Whatever is decided, the choice of symbols and labels should be consistent.

Let communication choose the format Data visualisation is all about communication. As a result, what information is going to be to communicated should be thought about before the format is chosen. If an amount is to be communicated, it is very difficult for viewers to tell proportions by simply looking at an area, such as with a pie chart. People are much better at discerning differences from length than they are from an area. As a result, when an amount or a comparison is being communicated, bar charts can be very effective. Then there are bullet charts. These essentially look at where something is now vs where it was or what it is aiming for, plus what percent it is towards achieving its goal. If a comparison is being made between the current and the prior year, or prior year-to-date, different shades of grey backgrounds can show progress based on a quarter, a month or a period. Bullet charts usually require a quick explanation of what is being compared, but then people understand them quickly going forward. Sometimes too much information can muddy the waters, so the message should be kept clear and clean. A cumulative line chart can help with that and is something that can be combined with bullet charts. And if data is moving in a downward trend, a cumulative line chart can show very quickly where a real problem is, meaning this can be rapidly communicated out to stakeholders. The construction engineering industry always involves interacting with multiple hierarchies. Tree maps can be an effective way to display large amounts of hierarchical information, for example, ‘piping and insulation’ could be the top level of the hierarchy, and each level could go into a lower level such as ‘aboveground piping’ and ‘underground piping’, etc. This hierarchy is a method for tracking costs and productivity. One of

the codes could be drilled into and achievements or poor performance could be analysed. Looking across all projects, it is easy to see where the most issues are and a team can then be pulled together to determine if standard operating procedures need to be modified for that specific type of work, so it can start trending in the right direction. Another method of data visualisation that may not be as well-known as some others, is a chord chart, which can be used to see how many issues a project may have by category. These categories might be RFIs, change orders, safety incidents, quality issues, etc. A chord chart displays important information quickly, as it immediately shows which project has the most overall issues and which category of work is the largest. It shows which project requires immediate assistance and where focus is needed by issue category as an entire company. A chord chart is a great way to see relationships between two data points quickly. With today’s more advanced data visualisation tools, there is also a heightened level of interactivity. So, if one aspect of a particular chord chart should be the focus, a mark can be clicked on and it will highlight the peaks and then put everything else into the background. One final word about pie charts. With these traditionally multi-coloured charts, it can be challenging for viewers to figure out which piece of the pie is bigger than another. This visual is best suited for information that is binary, meaning true/false or yes/no. Comparing slices of a pie with two variables is relatively easy, and exact percentages or values typically do not matter, only which is bigger or smaller. What is difficult with a pie chart is when data that has an infinite amount of possibilities is used, such as category or status. This makes it harder to control how the visual looks and is interpreted — and the last thing a company wants when building visualisations is for the interpretation to be left to the user. Each visualisation should be purposeful, with the goal being when two different people view a chart, they both arrive at the same conclusion.

Understand growth and adoption

Figure 1. Orange-coloured metrics indicate areas of concern, contrasting other components on screen and drawing attention there first.

This article has covered what kind of formats to use and when, but there is a lot more to successful data visualisation than simply what things look like. It is the communication level that matters, and that is the one thing that data visualisation can do extremely well, but only with the right tools. There must be a shared narrative or a shared understanding. It is that shared understanding of what the information is saying that can help create a collaborative understanding across a project, especially for those not in the data field. Data visualisation is also about growing a business. Virtually every organisation where data visualisation has been adopted and promoted has grown organically. And once people start seeing that growth and what is truly possible, they start getting excited because now, they own it. Like any new concept or technology, when it comes to getting stakeholders to embrace data visualisation, it is really about trust and a feeling of ownership. It will not happen overnight, but if some of the best practices discussed here are incorporated into data visualisation, trust can built day by day, project by project, and well into the future.

References Figure 2. Place metrics at the top of reports to draw users to the most critical information.

August 2021

National Eye Institute, ‘At a Glance: Color Blindness, National Institutes of Health, NIH National Eye Institute’, https://www.nei. nih.gov/learn-about-eye-health/eye-conditions-and-diseases/colorblindness.

Nim Gnanendran Ph.D., NimblEng Energy Consultants, Australia, explains why mid scale LNG trains are an ideal size for the development of blue LNG concepts.

atural gas – being a low-carbon fossil fuel – continues to play a key role in displacing coal in the power generation sector. However, falling solar and wind power generation costs and changing global attitudes towards fossil fuel-based energy systems has seen the natural advantage of gas waning ever so quickly. With

global energy markets in transition towards low-carbon energy, there is a growing scrutiny of the carbon intensity of LNG produced from various sources and an appetite for sourcing lower carbon LNG. For the purpose of this article, blue LNG is defined as LNG produced with more than 90% of carbon associated with the production, liquefaction, and

transportation being captured and stored. This is analogous to blue hydrogen, where hydrogen is produced from natural gas with carbon capture and storage (CCS). The greenhouse gas (GHG) emission intensities of LNG supply chains into central Europe are shown in Figure 1, where it can be seen that liquefaction contributes to 30 - 40% of GHG emissions. CCS in LNG projects is inevitable as they provide direct means of emissions reductions. At present, carbon-neutral LNG cargoes can be procured where the associated carbon emissions with the production and delivery of the cargo is offset through the purchase of carbon credits. This seems a short-term measure to suit a small volume of trade while the debate continues around the veracity of such carbon credit schemes. A more prudent alternative for the industry is to fast-track the implementation of CCS projects within its operations to produce low-carbon petroleum commodities, including LNG, where there is already a growing market. The knowhow within the oil and gas industry in CCS technologies such as separating CO2 from gases, compressing it to higher pressures, identifying suitable geological locations for CO2 storage, constructing CO2 wells, injecting pressurised CO2, and monitoring CO2 in storage needs to be capitalised to ensure CCS is widely adapted. This article provides technical and commercial reasoning for mid scale trains to be used for implementing CCS in LNG trains along with a conceptual design of a mid scale blue LNG train. LNG projects in the capacity range of 1 - 2 million tpy were considered for monetising smaller stranded gas reserves with relatively short distance markets targeting integrated power projects in Southeast Asia in the early part of the 2000s. Several project developers using simple

liquefaction technologies began to explore this niche market, when large scale LNG projects were serving the high volume, high value, lucrative North Asian markets. Mid scale LNG, by definition, is a niche market, where ideally the compelling features of large scale LNG, such as efficiency and lower dollar/tonne cost can be combined with the attractive features of small scale LNG, such as simplicity and lower capital costs. The arrival of the US shale gas boom and LNG projects based on take-or-pay tolling contracts saw the advantages of mid scale trainbased LNG projects where project developers used standardised modular mid scale trains as viable alternatives. These projects used mid scale trains to better support multiple, small volume, short-term and mediumterm LNG sales contracts, offering flexibility, lower capital costs, and better overall project economics. In the recent past, mid scale LNG trains have also shown to be ideal for floating LNG (FLNG) applications. Golar LNG and Petronasled projects showed that 1 - 2 million tpy mid scale FLNG is ideally suited for commercialising stranded gas fields, while the large scale, complex Shell Prelude FLNG project has continued to be plagued with technical issues and delays. The success of mid scale LNG trains in FLNG applications also provides a pathway for adapting CCS in offshore applications, where deep sea floor carbon storage options can be utilised when geological carbon storage is not viable. A mid scale LNG project in many cases will produce first LNG four to five years earlier than large scale LNG projects, considering the entire project development cycle.2 Mid scale LNG also provides an ideal size to develop innovative low-carbon solutions such as combined cycle LNG.3 A mid scale LNG project with 1.0 - 2.0 million tpy capacity could provide an ideal scale for developing blue LNG value chains based on the CCS of LNG liquefaction plants.

LNG and CCS

Figure 1. LNG supply chain carbon emissions.1

Figure 2. A mid scale blue LNG process schematic.

August 2021

The petroleum industry of the future would be required to abate their Scope 1 and Scope 2 carbon emissions in a sustainable manner, other than look at offsets with tree planting schemes. While several measures are undertaken to reduce upstream methane emissions, it is prudent for industry to look at midstream and downstream emissions and act now rather than attract further scrutiny. LNG production is one of the most carbon intensive midstream processes within the industry, hence the adoption of CCS in LNG liquefaction facilities should remain a primary focus. The lessons from the coal industry failures in not investing in research in CCS technologies is proof, as the global energy transition threatens the immediate viability of that industry. The oil and gas industry needs to show visionary leadership in developing CCS projects now, beginning with reinjecting reservoir CO2 separated from feed gas in existing operations. The new phase of the Qatar LNG expansion with approximately 37 million tpy LNG capacity will include sequestration of the CO2 separated from the feed gas, thus setting a new benchmark for new LNG projects. LNG projects such as Gorgon LNG and Snøhvit LNG with higher CO2 content in the feed gas have been reinjecting CO2 separated from the feed gas in geological storage formations for a number of years. These CCS projects have

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faced several challenges including equipment failure due to corrosion and injection pressure management issues in CO2 wells, but have continued to provide vital learnings for the CCS industry. These learnings are critical for establishing CCS as a viable technology, not only for the oil and gas industry but for decarbonising the power sector and other energy intensive industries such as steel, cement, and chemical manufacturing. The CCS expertise gained by the oil and gas industry will also enable the establishment of CCS hubs, where industrial CO2 emissions can be collected, processed, and sequestered in depleted reservoirs which could also enable a new business stream for the industry in a low-carbon world. Further, the growth of the CCS industry will reduce the cost of blue hydrogen, i.e. hydrogen produced from natural gas using the steam-methane reforming (SMR) process with CCS, opening long-term markets for the gas industry in the hydrogen economy.

A mid scale blue LNG plant concept Carbon emissions from an LNG plant are associated with two main sources: z CO2 separated from feed gas. z Post-combustion CO2 associated with gas/power turbines in the plant. Smaller amounts of emissions are also associated with emergency flares and other fugitive emissions which are difficult to capture but can be managed by good engineering design and proactive operations and maintenance practices. Chemical solvents such as amines and physical solvents such as selexol have been used to remove CO2 from natural gas with up to 15 vol% to near zero levels as part of LNG production. The amine solution is contacted with the natural gas in an absorber column flowing in a counter-current manner to selectively absorb CO2 from the natural gas. The CO2 rich amine is then treated in a rectification column at higher temperatures to separate the CO2 and produce lean amine to be returned to the absorber column. The rectification column operates with a reflux drum, and the CO2 leaving the unit is water saturated and is at near atmospheric pressure. For postcombustion CO2 removal, several chemical and physical solvent-based plants with a similar configuration to natural gas CO2 removal plants are used. Typical flue gas from gas turbines contains 8 - 10 vol% CO2, 18 - 20 vol% H2O, 2b- 3bvol% O2, and 67 - 72 vol% N2. The CO2 content to be removed from the flue gas is typically five to seven times more than CO2 removed from feed gas in an LNG plant. Hence the energy requirements for a CO2 removal unit along with dehydration of the CO2 stream prior to compressing it to 70 - 100 bar to suit geological sequestration is significantly high. The CCS plant could add an overall energy efficiency penalty of a further 3b-b5% on top of the typical energy efficiency penalty of LNG plants of 10 - 12% operating with open cycle gas turbines. An efficient plant design is essential to overcome the increase in energy requirements with an LNG + CCS plant. One such option is to utilise a deep waste heat recovery system, such as in a combined heat and power (CHP) plant, where high-pressure steam is generated from the gas turbine flue gas to produce sufficient heat to meet re-boiler loads in amine and dehydration units and to power a steam

August 2021

turbine generator to supply plant electrical power requirements, as shown in Figure 2. An auxiliar boiler, not shown in Figure 2, can be used in part of the CHP plant for start-up. A typical combined cycle power plant can improve the power plant efficiency to approximately 55 - 60% compared to an open cycle gas turbine plant that operates at 35 - 40% efficiency. Configuring the blue LNG plant around an efficient gas turbine such as GE LM2500+G4, Siemens SGT-750, or GEbLM6000, with a rated capacity ranging from 35 - 45 MW, allows the gas turbine and CHP plant to be highly integrated in an LNG train with a capacity of 1b-b2bmillion tpy and a CCS plant. A two-in-one unit with two parallel gas turbines and liquefaction trains with common pre-treatment, a CHP plant, and a post-combustion CO2 removal unit can also be used to improve overall plant reliability and availability. As an example, a 40 MW gas turbine operating at 40% efficiency and using a fuel gas with a low heating value of 50bMJ/kg has an annual CO2 emissions rate of 0.21bmillionbtpy. A further 0.04 - 0.05 million tpy will be associated with the CO2 removed from a typical low CO2 content feed gas. This volume can be supported using a single CO2 injection well, and is a manageable volume for geological site selection and monitoring over a 25-year project life. As a comparison, the Gorgon LNG CO2 injection system is designed for 3.5b-b4.0bmillion tpy of CO2. The 40bMW turbine, when used to drive a single mixed refrigeration process with a refrigeration efficiency of 14bkW/tpd of LNG, can produce 1 million tpy of LNG. A waste recovery unit capable of recovering 17 - 18% of the energy from the turbine exhaust can power a CHP plant capable of supporting 13 - 14 MW of heat load and 2.5b-b3.5bMW electrical power, hence meeting all heat and power loads of the LNG train and the CCS plant. Similarly, other blue LNG plant concepts can be developed to utilise waste heat from gas turbines in the LNG train to supply heat and power for the CCS and LNG plants.

Key takeaways The oil and gas sector needs to lead the development of CCS technologies and CCS applications to reduce its carbon emissions while also ensuring the longevity of the industry in a low-carbon world. The cost of CCS must reduce significantly, similar to solar, wind, and battery systems, for its wider adaption. Mid scale LNG trains with 1 - 2 millionbtpy have proven scale to develop novel LNG applications in the past and would be an ideal scale for efficiently adopting CCS in LNG applications with compact, modular trains based on deep waste heat recovery systems. In the longer-term, lowering the cost of CCS is essential for the viability of the gas industry during this era of energy transition and increases the competitiveness of blue hydrogen in the hydrogen economy. The investments in blue LNG supply chains today will pave the path to blue hydrogen supply chains in the future.

References 1.

Nord Stream 2, thinkstep AG, ‘GHG Intensity of Natural Gas Transport’ (March 2017).

Linde Engineering, ‘Mid-Scale is Scaling Out’ (June 2019).

GNANENDRAN, N., and BAGULEY, J., ‘Optimising mid scale LNG’, LNG Industry (January 2020).

Harrison Thomas, Gasrec, UK, looks at how bio-LNG and bio-CNG are driving the transition towards cleaner, greener transport.

ith demand for alternative fuels among the transport sector skyrocketing, LNG-powered trucks have a huge part to play in helping operators meet their sustainability objectives. The technology has developed in leaps and bounds in recent times but there are still challenges to overcome to help fleets transition away from diesel. A recent report from industry trade body, the Gas Vehicle Network, showed a 78% increase in the sales of gas as a transport fuel during 2020. A significant spike in demand indeed, but the figures were of little surprise to anyone within the sector. Biomethane-powered trucks have been proven to return CO2 savings as high as 95%, as well as delivering a significant 99% reduction in particulate matter and 90% in NO2 emissions compared to their Euro VI diesel counterparts. These can be considered attractive statistics for businesses looking for a cleaner, more sustainable operation. While both bio-LNG and bio-CNG share these benefits, it is the former that is making the bigger impact, particularly for long haul operations. LNG is denser, therefore more energy

can be achieved on a vehicle than with CNG. One unit of liquid gas energy takes up three times less volume than one unit of compressed gas energy. With long-distance, heavy-duty trucks powered by electric still years away from being rolled out in any significant numbers, more and more operators are starting to accept the fact that bio-LNG currently offers the best route forward when it comes to cutting tailpipe emissions – which it will continue to do so for some significant time yet. This is a message that Gasrec – one of the UK’s leading fuel providers for gas-powered commercial vehicles – has been pushing for a number of years. The company supplies, builds, and operates bio-LNG and bio-CNG refuelling stations across the UK working with major blue-chip companies such as Tesco, Asda, Sainsbury’s, Ocado, and B&Q.

Picking up the pace As take-up for the technology soars, Gasrec projects that one-third of the UK’s 44 t heavy truck market will have transitioned to natural gas within the next seven years, with approximately 39b000 gas-powered HGVs on UK roads.

James Westcott, Chief Commercial Officer at Gasrec, explains, “Just a few years ago there were no real UK-spec gas trucks available, but following launches by three of the big manufacturers – Volvo, Scania, and IVECO – we are now seeing exponential growth. “We are already supplying more than double the volume of gas we were back in January 2020; and that is after volumes

shot up in 2019 too. Over the next year, there will be hundreds of new gas trucks coming on the market, as businesses look to build back from the COVID-19 pandemic greener and stronger.” To back up that point, at the end of 2020 Asda took delivery of 202 Volvo FH LNG tractor units, in what is believed to be the single largest order ever placed in the UK for heavy trucks running on renewable fuels. It is anticipated that plenty more companies will follow Asda’s lead throughout 2021.

Expanding supply

Figure 1. Gregory Distribution has installed a new temporary bio-LNG station.

Figure 2. Reed Boardall has recently upgraded to a permanent LNG facility at its Boroughbridge base in the UK.

Figure 3. Gasrec’s Daventry International Rail Freight Terminal (DIRFT) facility is the largest gas refuelling site in Europe.

August 2021

To meet this increase in demand, Gasrec has recently completed a £1 million upgrade to its flagship refuelling facility at the Daventry International Rail Freight Terminal (DIRFT). A team of engineers installed new fuel dispensers, new supply lines, and a new fuel management system, along with greater remote operability for the site – which has the capacity to refuel up to 700 trucks per day. The company also introduced its own fuel cards to provide better information to its customers and to prepare for further expansion of its station network. Additionally, the systems align the refuelling process more closely with diesel to make driver training easier and more familiar. Rob Wood, Chief Executive of Gasrec, says: “The investment reinforces our confidence in the growing demand for trucks running on renewable biomethane, which now represent nearly 5% of all new tractor unit registrations in the UK. “We have seen a huge influx of new customers at DIRFT over the course of the past 18 months. This demand has also led us to invest in our supply chain and to increase the number of LNG road tankers in our fleet.” Indeed, the company plans to increase the size of its tanker fleet by 300% over the next 12 months – having recently added its third cryogenic trailer from Bradford-based M1 Engineering, UK, and has two more in build for completion in the next few months. A further three tankers are projected to join the fleet in 2H21. Situated near the M1 motorway, DIRFT is Europe’s largest gas refuelling station and offers 24/7 access to fleets from across the UK, Ireland, and the continent. The site houses seven dispensing points, including four pumps and four storage tanks. It uses an independent supply pipe network to different dispensers, so in the rare event of a failure on one line, it can still operate via the others. New systems installed during the refurbishment measure every refuelling procedure with pin-point accuracy, including when it commences, how long it takes, and the gas condition throughout the process – providing valuable management data to help Gasrec optimise the flow of vehicles through the facility. “The upgrades will ensure DIRFT continues to hit our strict targets for safety, sustainability, refuelling speed, and uptime, plus it means we are best positioned to refuel the latest generations of vehicles,” adds Wood. In addition to the open-access facility at DIRFT, Gasrec currently operates eight permanent sites for customers around the UK – the latest installed at frozen food transport specialist Reed Boardall’s Boroughbridge base earlier this year. Designed by Dutch LNG experts LIQAL, the compact, prefabricated system required limited construction time on-site and supplies the same fuelling consistency and reliability as a fully-fledged LNG station. Capable of comfortably supporting Reed Boardall’s 30 gas vehicles, the facility has the scalability to grow as the business puts more gas trucks into service.

There are also plans in place to build more infrastructure at another site for the company in the next 12 months. “The big challenge for us now is to ensure the capacity is there to help keep up with the new orders of LNG-powered trucks,” adds Westcott. Logistics giants Gregory Distribution is another which is pushing ahead with the switch from diesel to gas. The business recently installed its first refuelling station at its depot in Cullompton, UK, as part of an ongoing trial into the suitability of bio-LNG to replace diesel in its fleet of more than 1000 trucks. Gasrec delivered the skid-mounted unit – used as a temporary solution for fleets exploring the option of bio-LNG – straight from the site at Reed Boardall, after the company upgraded to its new permanent station. “We use the pumped mobile refuelling station to seed new locations where we want to get bio-LNG into an area quickly,” explains Westcott. “The plan is to get a more permanent station at Cullompton, but the fast-moving nature of this industry requires a flexible approach and the fact that we were able to deliver the facility direct to Gregory Distribution, from Reed Boardall’s site in Boroughbridge, shows how quickly we can help our customers get this cleaner fuel into their fleets.” It is another example of how Gasrec is working intensely to make every aspect of the transition to gas from diesel as straightforward as possible.

Making improvements While the introduction of more infrastructure is undoubtedly the major focus, there are other areas of the process that also require smoothing out. “The resilience of our facilities, which was a major part of the upgrade work at DIRFT, is something we are constantly

Figure 5. More and more operators are making the transition to bio-LNG.

looking at, ensuring they are as safe and user-friendly as possible,” adds Westcott. “Then there is the lead time for equipment, that can be a big issue for us, as it can take a long time to build gas tanks, for example.” “Whatever the issue may be, we are always exploring ways to improve the experience for our customers. Working with LIQAL on the project at Reed Boardall was a great option as we saw real synergy in innovation and technology between our two companies. We are passionate about the benefits gas can bring to fleets and are open to working with partners which share our ambition and commitment to this cleaner, cheaper and more environmentally-friendly fuel.” As is to be expected with any relatively new technology there are still roadblocks to overcome, but those at the forefront of the movement towards a more sustainable transport industry have no doubt the hard work will be worth it in the end.

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15FACTS Argentina’s 1H21 LNG imports increased by 72% y/y

The Galápagos Islands’ giant tortoises can live for approximately one year without water or food

The Americas as a whole makes up approximately 5% of global LNG demand

...ON LATIN AND SOUTH AMERICA Argentina primarily purchases LNG for its southern hemisphere winter

The highest peak of the Andes is Mount Aconcagua, which stands at 22 831 ft

Easter Island has approximately 900 moai

The Amazon Rainforest spans across Brazil, Bolivia, Colombia, Ecuador, French Guiana, Guyana, Peru, Suriname, and Venezuela

Chile imported nearly 1.7 million t for the ﬁrst six months of 2021

Brazil imported 2.7 million t of LNG in the ﬁrst six months of 2021

In 2008, the festival ‘Día de los Muertos’ (Day of the Dead) was added to the UNESCO list of Intangible Cultural Heritage of Humanity

Brazil has won the FIFA World Cup ﬁve times

The golden poison frog found in Colombia contains enough poison to kill 10 grown men

New import capacity is expected to come online this year, such as the Puerto Sandino LNG project in Nicaragua and small scale imports into Pichilingue, La Paz, Mexico

Angel Falls in Venezuela is 979 m tall and is the

Mexico imported 366 000 t of LNG in 1H21 56

August 2021

highest waterfall in the world

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LNG Industry August 2021

Articles inside

Fuel for thought

Visualise the data

All aboard the blue train

Real-life training in a virtual world

Fitting the right engine

Putting Spain on the LNG map

Digital twins for A to B

LNG news

The butterfly effect

So long sulfur

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Activity underway in the Americas