LNG Industry - April 2021

April 2021

Atlas Copco Gas and Process introduces a different compression approach to cryogenic high-pressure BOG

ISSN 1747-1826

CONTENTS 03 Comment

APRIL 2021

27 Taking measurement technology to the max

04 LNG news

Sebastian Harbig, Vega, Germany, outlines the role of measurement technology in the LNG industry and how investing in state-of-the-art solutions can help LNG plant operators maximise their performance.

08 A new chapter for US LNG

Alex Dewar, Boston Consulting Group (BCG), USA, looks at how decarbonisation could lead US LNG in a new direction and help it remain competitive in the global market.

30 Check for a bumpy ride

Reinaldo Pinto and Ben Keiser, Applied Flow Technology, USA, explain the importance of flow and surge analysis in LNG plants.

35 With time comes wisdom

David J. Fish, Senior Vice President, Welker, Inc., USA, provides an overview of LNG sampling systems and their streamlined evolution over recent years.

40 Give it a little lift

Raphaël Poichot, Technip Energies Loading Systems, France, details how ship-to-ship LNG transfer has surpassed challenges and advanced operations.

45 Conform with the letter of the law Pierre Barere and Gilles Tissot, Opta-Periph SAS, France, address the suitability criteria of LNG probes/vaporisers and autosamplers, ensuring they comply with international standards.

08 13 The next big disruptor

Sarah Bairstow, Mexico Pacific Limited, Australia, reviews the emergence of North American LNG onto the global LNG stage and makes the case for Mexico to play a significant role in the future.

16 How to create a masterpiece

Tushar Patel, Atlas Copco Gas and Process, cess, USA, explains how n can meet the LNG high-pressure boil-off gas compression market’s need for reduced CAPEX and OPEX.

22 Safety starts on the drawing board

Chris Vandecasteele, Gaz-Opale, France, e, outlines how the Dunkirk LNG terminal can be considered a model of safety in the LNG world.

49 Staying ahead with Industrie 4.0

Jonas Berge, Emerson Automation Solutions, Singapore, discusses how LNG plants can embrace a new era of automation as the fourth industrial revolution comes to pass.

52 Myriads of modules

Gobind N Khiani MEng PEng, GAPV Inc., Canada, and Robert Weyer, Amesk Corp., Australia, assess how operations can stay uninterrupted by modularisation in LNG plants, addressing valves in particular.

56 15 facts on... the USA

ON THIS MONTH’S CO COVER The best of different technical T worlds: Process’ w orlds: Atlas Copco Gas and Proce high-pressure blends h ig gh h-pressure BOG compressor ble experience tthe he company’s decades-long expe with LNG w wit h cryogenic applications, and L and power generation markets. It iis CAPEX a solution that addresses the CAPE and OPEX requirements of today’s LNG industry and provides a reliability of more than 98%. Meanwhile, the compres compressor’s seals, impellers, gearbox, and beari bearings are pillars of the high-pressure BO BOG’s availability.

Learn more at: www.atlascopco-gap www.atlascopco-gap.com

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LYDIA WOELLWARTH EDITOR

COMMENT T

here is something in the psyche of humans that seems to make us desire the tallest, the fasted, the biggest, the most multi-talented things, irrespective of their shortfalls. Take the speediest passenger airline – Concorde – a short-lived thrill for a mode of transport twice the speed of sound. Or consider the manmade islands of Dubai, an act of human superiority over nature, yet most of the islands now lie empty or sinking.

Thinking of extreme size, and pictures of an enormous creation saturated the news recently when a containership 400bm long – taller than the Empire State Building in New York, US, if placed vertically – became wedged in the Suez Canal. The event drew much social media attention for its comedic, calamitous nature, but the disruption that unfolded in one of the world’s most crucial waterways for global trade, particularly the LNG industry, needs to be highlighted.

The Suez Canal in Egypt provides the shortest sea link between Asia and Europe, connecting the Mediterranean Sea to the Red Sea. It is reported that approximately 12% of global trade passes through this route, equating to 50bvessels per day. The goods carried by these vessels range from Ikea furniture and coconut milk to livestock and oil, to name a few. When the Ever Given – the vessel transporting nearly 20 000 containers to the Port of Felixstowe, UK – became stuck in the Suez Canal for seven days, the flow of goods it disrupted amounted to US$9.6bbillion/d.

At its peak, there was in the region of 370 vessels unable to transit either end of the Suez Canal whilst the Ever Given was jammed. According to Kpler LNG, there were 18 LNG vessels impacted by the extreme congestion, many of them holding expired ETAs for transit. Rasheeda, a Qatargas LNG carrier, was stuck waiting for the full

seven-day disruption – impacting the crew on board, the end consumers of the LNG, and adding to the delays at Ras Laffan, since eight LNG vessels caught up in the blockage belong to Qatargas.

The Suez Canal is a vital waterway because it provides the most direct route between continents. An alternative route passes via the Cape of Good Hope at the southern tip of Africa, which adds multiple days to a vessel’s journey, however, at least eight LNG vessels chose to reroute this way rather than wait idle for the Ever Given to be freed. To put into perspective the lengthy route detour, for a vessel travelling from Singapore to Rotterdam utilising the Suez Canal, the distance is 8440bnautical miles, whereas the distance rises to 11b720bnautical miles between the two locations when travelling via the Cape of Good Hope.

Whilst the Ever Given has now been released from its unwanted jam, the problems continue to unfold, with the vessel impounded and caught in a legal dispute between Egyptian authorities and the vessel’s owners regarding the financial implications of the incident. The compensation being sought by the canal authorities is in the region of US$900bmillion to US$1 billion.

Returning to our discussion on the biggest, fastest, and largest, it appears that disruptions and accidents are likely to occur more frequently than with something of more ‘standard’ build. However, there are lessons to be learnt to make sure events cause the least damage possible. With a highly-publicised incident such as the Ever Given, the shipping industry should now consider how fundamental enormous vessels are to the market, or at least develop and introduce more precautions to increase the safety of such megaships.

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LNGNEWS Australia

Santos announces FID on Barossa project

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antos, as operator of the Barossa joint venture, has announced a Final Investment Decision (FID) has been taken to proceed with the US$3.6 billion gas and condensate project, located offshore of the Northern Territory.

Barossa FID also kick-starts the US$600 million investment in the Darwin LNG life extension and pipeline tie-in projects, which will extend the facility life for around 20 years. The Santos-operated Darwin LNG plant has the capacity to produce approximately 3.7 million tpy of LNG. Barossa is one of the lowest cost, new LNG supply projects in the world and will give Santos and Darwin LNG a competitive advantage in a tightening global LNG market.

The project represents the biggest investment in Australia’s oil and gas sector since 2012.

The Barossa development will comprise an FPSO vessel, subsea production wells, supporting subsea infrastructure, and a gas export pipeline tied into the existing Bayu-Undan to Darwin LNG pipeline. First gas production is targeted for the 1H25.

At the end of last year, Santos announced the tolling arrangements had been finalised for Barossa gas to be processed through Darwin LNG and that Santos had signed a long-term LNG sales agreement with Diamond Gas International, a wholly-owned subsidiary of Mitsubishi Corporation, for 1.5 million t of Santos-equity LNG for 10byears with extension options.

Santos has also signed a Memorandum of Understanding with SK E&S and Mitsubishi to jointly investigate opportunities for carbon-neutral LNG from Barossa, including collaboration relating to Santos’ Moomba CCS project, bilateral agreements for carbon credits, and potential future development of zero-emissions hydrogen.

Malaysia

PETRONAS produces LNG from floating facilities

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ETRONAS has become the first global energy company to produce LNG from two floating facilities following the first cargo delivery by PETRONAS Floating LNG DUA (PFLNG DUA) on 24 March 2021. The cargo was loaded onto the Seri Camar LNG carrier operated by MISC Bhd for shipment to its LNG buyer in Thailand.

PFLNG DUA has a production capacity of 1.5bmillionbtpy of LNG and is operating at the water depth of 1300 m. The floater facility is currently located at BlockbH Rotan gas field located 140 km offshore Sabah.

This milestone confirms the viability of PETRONAS’ push in unlocking stranded and deepwater gas fields with floating LNG (FLNG) solutions that are more sustainable and economical compared with conventional solutions.

PETRONAS President and Group Chief Executive Officer, Tengku Muhammad Taufik said: “PETRONAS is proud of this significant milestone from our second floating LNG facility.

PFLNG DUA’s first cargo demonstrates our commitment to continue our pioneering efforts in providing more sustainable solutions to harness further value from LNG production through technological advancements. Similar to our flagship floating facility, PFLNG DUA’s mobility will allow us to unlock even more marginal and stranded gas fields in the future, providing PETRONAS with new and sustainable sources of LNG to meet the growing demand for cleaner energy,” he added.

With PFLNG DUA’s first cargo delivery, PETRONAS continues to extend its leadership in FLNG technologies, having introduced PFLNG SATU – the world’s first operational FLNG – in 2016. PFLNG SATU also completed the world’s first FLNG relocation when it was deployed in March 2019 to Sabah’s Kebabangan gas field from the Kanowit gas field in Sarawak.

Mexico

NFE to supply natural gas to CFE power plants

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ew Fortress Energy Inc. (NFE) has announced that it has signed a gas supply agreement (GSA) with CFEnergia SA de CV, a subsidiary of Mexico’s Federal Electricity Commission (CFE).

Under the agreement, NFE will provide the equivalent of an estimated 250 000 - 500 000 gal. of LNG (20b000b-b40b000bmillion Btu) per day to CFE’s CTG La Paz and

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April 2021

CTG Baja California Sur power plants in Baja California Sur, Mexico.

NFE will supply natural gas to the plant via the Company’s LNG receiving and regasification terminal in the port of Pichilingue, Baja California Sur, Mexico. The terminal is anticipated to be complete and begin the supply of natural gas to CFE in May.

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LNGNEWS Belgium

Greece

Gastrade, NER AD, and AD ESM sign agreements for Greek LNG terminal

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he Greek company Gastrade SA has announced the signing of the agreements for the co-operation of National Energy Resources (NER AD) Skopje and AD Power Plants of Northern Macedonia (AD ESM) with the Alexandroupolis LNG Terminal.

The agreements were signed by the Vice President of the Board of Directors of Gastrade, Mr. Kostis Sifnaios, the Executive Director of NER AD, Mr. Bajram Rexhepi, and the President of the Management Board and General Manager of AD ESM, Mr. Vasko Kovacevski, in the presence of the Prime Minister of the Republic of North Macedonia, Mr. Z. Zaev.

NER AD aims at acquiring a share in the share capital of Gastrade whilst AD ESM is interested in reserving capacity at the terminal on a long-term basis. The parties will work together on formulating the details of both agreements to be presented to their respective governance bodies for approval.

Gastrade is developing the LNG FSRU offshore Alexandroupolis in Greece, which will be a new, independent energy gateway for the markets of Southeastern and Central Europe.

The FSRU will be located 17.6 km southwest of the port of Alexandroupolis and will have an LNG storage capacity of 170 000 m3 and a natural gas supply capacity that will exceed 5.5 billion m3/yr.

The floating unit will be connected to the National Natural Gas System of Greece via a 28 km long pipeline, through which the regasified LNG will be transmitted to the markets of Greece, Bulgaria, North Macedonia, and the wider region from Serbia and Romania to Hungary, Moldova, and Ukraine.

This is a European Project of Common Interest (PCI - EU Regulation 347/2013), a priority project of the EU, which strengthens security of supply, diversifies sources and routes of energy supply, enhances competition, and supports the establishment of a natural gas trading hub in the wider region of Southeastern Europe, bearing obvious benefits for all final consumers.

The LNG Terminal in Alexandroupolis is expected to be operational in 2023.

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April 2021

LNG bunkering available through Port of Antwerp

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ort of Antwerp, Fluxys, and Titan LNG have celebrated the christening of a new LNG bunker barge: the FlexFueler 002. Owned by gas infrastructure group, Fluxys and physical supplier of LNG, Titan LNG, the FlexFueler 002 makes LNG as a marine fuel widely available to vessels bunkering in the port.

The FlexFueler 002 operates from its base at quay 526/528 and supplies LNG throughout the port and Western Scheldt. It is the third vessel to join Titan LNG’s expanding infrastructure in the Amsterdam-Rotterdam-Antwerp (ARA) region, operating in addition to the FlexFueler 001 and the Green Zeebrugge.

The demand for LNG is growing as its role in shipping’s energy transition is increasingly recognised. LNG reduces SOx and particulate emissions to negligible amounts, NOx by approximately 85%, and achieves significant greenhouse gas reductions. It also creates a pathway to decarbonisation through the introduction of bio-LNG and synthetic-LNG, which both use the same infrastructure and engine technology. Liquid biogas – from organic waste – and liquid synthetic methane – from green hydrogen and captured CO2 – are scalable solutions for the maritime sector, and the expanding LNG infrastructure in Port of Antwerp is fully future-proofed and able to supply carbon-neutral LNG.

THE LNG ROUNDUP X Qatar Petroleum to become 100% owner of Qatargas X Sacyr Fluor awarded contracts in France and Belgium X GTT and SDARI obtain AiP for LNG fuelled bulk carriers Follow us on LinkedIn to read more about the articles

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LNGNEWS China

Ghana

Total and Shenergy Group team up on Chinese LNG

Bureau Veritas completes classification of FRU

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otal and Shenergy Group have signed binding agreements for the supply of up to 1.4 million tpy of LNG from Total, as well as the creation of a joint venture (JV) to expand LNG marketing in China.

The JV (Total 49%, Shenergy Group 51%) will sell LNG, supplied by Total, to customers in Shanghai and throughout the neighbouring Yangtze River Delta regions, one of the main LNG markets in China.

Additionally, Total will supply LNG to Shanghai Gas, the natural gas subsidiary of Shenergy Group, for its distribution business.

“This deal with Shenergy Group is a great opportunity to partner with an experienced gas and LNG player with strong ambitions, as well as a unique entry point into the downstream LNG market in China.

This partnership is in line with our strategy to grow along the entire gas value chain,” said Stéphane Michel, President Gas, Renewables & Power at Total. “LNG is playing a key role in meeting the growing demand for natural gas, especially in China where we are pleased to contribute to the diversification of the energy mix.”

The LNG supply to the JV and Shanghai gas distribution business will be sourced from Total’s global LNG portfolio through a long-term LNG sale and purchase agreement ramping up to 1.4 million tpy for a term of 20 years. It will be delivered to Shenergy’s Chinese LNG terminals.

B

ureau Veritas has announced the completion of the classification of the Torman LNG floating regasification unit (FRU) at Tema port, Ghana, in sheltered waters. The unit is combined with a floating storage unit (FSU) for the delivery of gas to onshore consumers.

This development of Gasfin’s facility – involving the Torman LNG FRU and a Moss-type LNG FSU, both classed by Bureau Veritas – paves the way for the first deliveries of LNG to a terminal in Sub-Saharan Africa and will contribute to meeting Ghana’s growing cleaner energy demand. The volume that Ghana National Petroleum Corporation (GNPC) will be taking is equivalent to approximately 1300 MW of combined cycle power plant capacity.

The 95 m length, newly built FRU was constructed at CSSC Jiangnan Shipyard in China and fitted with two IMO Type C tanks, and has a storage capacity of 28 000 m3.

The LNG FRU is designed for a regasification capacity of approximately 1.7bmillion tpy of LNG and will be in operation for approximately 20 years.

The classification and certification scope, conducted by Bureau Veritas, included the design, review, approval, material certification, and construction surveys of the LNG FRU at Jiangnan shipyard, as well as Tema port. Additionally, Bureau Veritas Solutions Marine & Offshore ensured verification and surveys associated with the design, fabrication, and incorporation of the natural gas send-out heater skid system onto the Torman LNG FRU. During the unit’s service years, Bureau Veritas will be supporting Gasfin’s management.

05 - 06 May 2021

07 - 08 June 2021

23 - 25 August 2021

2nd CEE Small-Scale LNG Forum

The 7th International LNG Congress

Canada Gas & LNG Exhibition & Conference 2021

Warsaw, Poland

Madrid, Spain

Vancouver, Canada

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13 - 16 September 2021

21 - 23 September 2021

15 - 18 November 2021

Gastech Exhibition & Conference 2021

Global Energy Show

ADIPEC

Alberta, Canada

Abu Dhabi, UAE

Singapore

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April 2021

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Alex Dewar, Boston Consulting Group (BCG), USA, looks at how decarbonisation could lead US LNG in a new direction and help it remain competitive in the global market.

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he US has been a pioneer in low cost, flexible LNG. Since Cheniere announced the first US Gulf Coast LNG export project in 2010, more than US$60 billion has been invested in export capacity. That investment has resulted in rapid export capacity growth, vaulting the US to be the third largest LNG exporter globally. Much of this capacity has been developed on the basis of entirely new and innovative commercial models in LNG, including capacity tolling agreements and Henry Hub indexed contracts.

Looking forward, however, with the initial wave of US LNG projects now concluding, Golden Pass and Calcasieu Pass are the only greenfield projects that have been able to reach Final Investment Decision (FID). Substantial additional

export capacity has been proposed, but these projects do not yet have sufficient offtake or capital commitments to move forward. So, what are the prospects for bringing additional US LNG capacity to market? In the current global market context, BCG believe it will come down to the ability to compete on both cost and carbon intensity. US project developers have already demonstrated a unique ability to innovate on costs, now they must do the same to minimise and validate the greenhouse gas (GHG) emissions intensity of their LNG.

US LNG in an oversupplied market Despite recent short-term spikes in LNG spot prices, the structural market fundamentals

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indicate oversupply in the global LNG market through at least the middle of the 2020s. Structural LNG demand growth is set to remain strong, driven by Asian markets that are rapidly adopting natural gas to expand energy access and displace coal. However, the COVID-19 pandemic is likely to have a lasting impact. While LNG demand has been more resilient than other fuels through the pandemic, growth has significantly slowed in the short run and the pandemic has delayed some downstream gas infrastructure investments in importing markets. The result will be a similar growth trajectory to what was expected before the pandemic, but delayed by several years.

Meanwhile, LNG supply is still expected to grow rapidly in the next five years. Global liquefaction capacity has already increased 35% since 2015, and projects that have already taken FID will expand capacity by a further 15% through 2025 (65 million tpy). In addition, Qatar’s planned expansion alone will likely contribute an additional 47 million tpy to global supply by the late 2020s. As the lowest cost source of global supply, Qatar has the drawing power from both customers and partners to move forward with its desired capacity expansion.

Similarly, additional projects in Russia and Mozambique are also shortlisted to take FID in the coming years given their low cost of production and strong financial backing, which could add more than 50 million tpy additional capacity by 2030.

In this context, how is the US positioned for building additional LNG capacity, and what will it take to see more US projects move forward to FID in the next decade? During the years of rapid LNG demand growth, the ability to bring

new liquefaction capacity to market was often sufficient to market LNG. Today, with supply growth outpacing structural demand, price is the critical differentiator. And given the new supply and demand environment, market fundamentals suggest that the long-term, contracted LNG price is likely to remain in the US$5 - US$7/million Btu range for landed cargoes in Asia. As Figure 1 shows, proposed US LNG projects can compete at that price, but they are not the only ones that can. The bottom line is that there is far more LNG capacity proposed than the market can bear over the coming decade and it will be critical for new US LNG projects to find other ways to differentiate.

The new frontier: minimising GHG emissions intensity

Beyond trying to market their capacity in a structurally oversupplied market, new US LNG exporters are now facing another challenge. Concern is growing globally regarding the GHG emissions intensity of natural gas. As a significant emitter of CO2 and methane – which has 26× the warming impact of CO2 when released into the atmosphere – LNG is no longer seen as an inherently sustainable energy source and is thus coming under greater scrutiny.

Government policies and corporate actions are now increasingly penalising emissions embedded in supply chains. The EU has proposed a carbon border adjustment mechanism, due to be implemented in 2023, which will measure and tax GHG emissions within supply chains. And as corporations embrace net zero standards, they are increasingly measuring and reducing emissions in their own supply chains. In this environment, pressure will mount for LNG suppliers to measure, report, and reduce embedded emissions intensity.

Decarbonisation is therefore the sector’s rapidly emerging frontier. In October, the French government reportedly pushed trading firm Engie to back out of a potential US$7 billion, 20-year US LNG supply deal due to concerns about methane intensity. In addition, Pavilion Energy of Singapore has recently agreed multiple new LNG supply contracts whereby embedded emissions from the wellhead to delivery Figure 1. Estimated 2030 breakeven costs and production capacity by country. will be tracked and reported.

Measuring and reporting GHG emissions through natural gas value chains is not a trivial effort though. As Figure 2 illustrates, GHG emissions are distributed across the LNG value chain.

And while emissions from natural gas combustion are consistent across sources of supply, embedded emissions can vary widely among sources of supply, especially in the extraction and processing steps. A significant regional variability in upstream and midstream emissions can be seen, with a 2× difference between the highest and Figure 2. Average well-to-city gate pre-combustion carbon footprint of LNG lowest intensity producers. Key factors supplies (grams CO2e/MJ). driving this variability include upstream

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April 2021

asset types, methane emissions, feed gas composition, and the efficiency of liquefaction operations.

An increase in the measurement of embedded emissions will present an immediate challenge for US suppliers. Based on a comprehensive assessment of GHG emissions from different sources of LNG supply, BCG analysis shows that on average, the US is the most GHG intensive supplier. US LNG’s high GHG emissions intensity is largely driven by methane emissions, as shown in Figure 3. Methane represents a much greater share of US emissions than for other countries, largely due to significant upstream methane emissions observed in US shale production as well as the extensive pipeline network used to deliver natural gas to the Gulf Coast region from key gas producing regions in Appalachia and the Permian.

Immediate decarbonisation opportunities While the GHG emissions intensity of US LNG is high on average today, US LNG producers can take relatively modest steps to substantially reduce emissions or at least validate the low emissions intensity of their supply. Most methane emissions are negative to near zero cost to abate. For US producers, BCG estimates that reducing LNG emissions intensity to the global average could be achieved exclusively by addressing methane emissions and would likely only add zero to US$0.60/million Btu – less than 10% of the delivered cost of LNG even on the high end. Essentially, producers’ value from reducing emissions, avoiding emissions penalties, and being able to sell their gas would exceed abatement costs.

In addition to addressing methane emissions, US natural gas suppliers have other competitive opportunities to reduce CO2 emissions through the supply chain. For existing gas production, adding carbon capture in natural gas processing or liquefaction operations can potentially be achieved at break-even or even with a positive return, utilising the 45Q tax credit for carbon capture. Meanwhile, greenfield LNG project developers have a wide range of levers available to reduce emissions intensity, including electrifying liquefaction operations and integrating with renewable producers. Indeed, multiple project developers have proposed integrating these types of low emissions solutions into their project designs.

Going beyond direct investments in decarbonisation, US LNG producers have the flexibility of being able to develop their own natural gas supply chains. This flexibility can be used to optimise sources of supply to minimise GHG

emissions. Focusing on methane emissions, LNG producers can work with upstream producers to track and minimise emissions through their supply chains. They can also source natural gas from nearby producers in order to minimise emissions from pipeline transmission of natural gas. This has been a key argument for project developers based in Louisiana sourcing gas supply from the Haynesville shale or those in southern Texas sourcing from the Eagle Ford.

Some US LNG producers are already moving in this direction. Cheniere, one of the country’s largest LNG producers, has been actively working to reduce its methane emissions for several years now. In 2018, it co-founded the Collaboratory to Advance Methane Science (CAMS) to better measure methane emissions along the natural gas value chain. In 2019, the company began engaging its natural gas suppliers to help manage their emissions footprints. In February 2021, Cheniere announced that it would also provide emissions data on each LNG cargo to its customers starting in 2022.

A narrow window of opportunity

On the surface, US greenfield LNG project developers face an intractable challenge. They are attempting to reach FID in an oversupplied market without a distinct cost advantage relative to several other projects, while also requiring substantial new investment to finance their projects. At the same time, the embedded emissions intensity of LNG is coming under greater scrutiny while the US is the most emissions-intensive supplier when assessed on an average basis.

US LNG project developers have already innovated to make their commercial offers more compelling. They have adopted new, modular technologies and pioneered new contracting structures to minimise costs and maximise contracting flexibility. They must now adopt a similar degree of innovation to produce the least emissions-intensive LNG possible.

However, LNG developers must act quickly. Governments and consumers are already moving to address embedded emissions from LNG supply. More broadly, the credibility of US LNG is in question given high flaring and methane emissions from US shale production. US LNG developers also cannot wait indefinitely to reach FID. They must take decisive and distinct action if they are to proceed, making bold moves to minimise and validate emissions intensity of their LNG. The US is at a critical juncture for continuing to expand its LNG export capacity. It has established a market leading position with Qatar and Australia through the quick action of project developers converting brownfield import terminals to export following the shale boom. But to maintain that leadership position, US project developers must find a way to differentiate their offerings. They have already achieved what they can to innovate on cost and contracting flexibility. The next and critical horizon is to differentiate on the basis of embedded GHG emissions intensity. Failing to address GHG emissions will constrain the ability of the US to continue growing LNG exports, while proactively minimising Figure 3. Estimated embedded carbon intensity of loaded LNG and export capacity emissions could make the critical by country. difference.

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April 2021

Sarah Bairstow, Mexico Pacific Limited, Australia, reviews the emergence of North American LNG onto the global LNG stage and makes the case for Mexico to play a significant role in the future.

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orth America has taken the global LNG market by storm, propelled forward by technology that unleashed the shale revolution in 2011 and pivoted the US to a net exporter of natural gas by 2017. North American LNG export terminal developers have historically concentrated projects in the Gulf of Mexico, given its close proximity to Henry Hub and access to waterways that can accommodate the sizeable LNG tankers required for transport.

What many were not expecting was the next evolution of the global LNG market. By essentially optimising the Gulf of Mexico model, Mexican LNG is becoming the next big disruptor, and is very attractive for Asian markets. Asia-Pacific buyers are highly dependent on LNG imports for energy security, as LNG is critical for power generation and home heating across the region.

Asia driving future global LNG demand Asian LNG demand growth is forecast to more than double in the next 20 years, from 370 million tpy in 2020 to 745 million tpy by 2040. Emerging market growth, environmental pressure to switch from coal to gas power generation, and declining indigenous gas reserves are drivers behind this unprecedented growth.

With the market forecast to move into a structural shortfall from late 2024, LNG buyers need to contract and underpin new supply now, in order to establish supply certainty and avoid turbulent spot pricing. Construction of an LNG export terminal can take five years to build and fully ramp up, so it is key for customers to enter into long-term contracts now to ensure they can meet their supply needs. Price, certainty of supply, flexible contracting terms, price index, and supply source diversity are key drivers as these buyers seek new supply.

Benefits of Mexican LNG Mexican LNG export projects fulfil these requirements and can offer significant price advantages through access to surrounding basins; access to existing, underutilised

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pipeline capacity; price diversification; and a significantly shorter shipping route to Asia.

Close proximity to prolific natural gas supply from the nearby Waha hub in West Texas, US, provides significant cost benefits, with Waha pricing often trading at a significant discount to Henry Hub, the alternative consumer gas market for Permian gas. On average, Waha is forecast to average a price discount to Henry Hub of close to US$1/million Btu across the period 2025 - 2040. This differential is primarily driven by available production, available takeaway pipeline capacity, the cost to transport the gas to the East coast consumer market, and Permian natural gas being a byproduct of liquids drilling and therefore produced at low cost – the Permian Basin alone has 600 trillion ft3 of natural gas reserves remaining, of which approximately 90% are at break-even prices below US$0/million Btu (EIA, RSEG). As Permian production economics are oil driven, natural gas is a byproduct, and without a market may need to be flared. Providing an outlet for what would be otherwise stranded gas provides an alternative for producers to avoid flaring, compounding the environmental benefits. Access to an abundant gas supply also avoids the need to drill for new reserves and thus removes reserves reliance risk. Having the ability to buy gas from the market also underpins buyer access to volume flexibility, which has proven key in responding to unforeseen demand fluctuations and is something reserved-based integrated gas to LNG projects cannot offer.

Mexico is also connected to the Permian basin by a robust network of existing natural gas pipelines that have underutilised capacity and can be easily expanded, further minimising costs and environmental impact. Why send gas east to the Gulf of Mexico only to have to ship it all the way back west via tanker? Existing pipeline takeaway capacity from the Permian to the West coast of Mexico enables the direct flow of gas west, closer to Asian end markets.

Henry Hub was the first step in providing LNG pricing diversification away from the traditional Brent-indexed terms of global contracts. Buyers continue to seek diversification away from oil-linked contracts and are actively pursuing further US gas

diversification, including Waha indexation, which serves as an ideal natural hedge to high oil prices given Permian gas is an associated byproduct to oil. When oil prices increase, production in the Permian increases, which subsequently drives down associated gas Waha pricing for LNG customers. Mexican LNG projects not only offer access to advantageous Waha pricing, they also facilitate geographical supply source diversification from the often congested and weather affected projects in the Gulf of Mexico.

Beyond the benefits of access to low cost gas, Waha indexation, and existing pipelines, strategically located LNG export terminals on the West coast of Mexico almost halve the shipping cost to Asia and avoid the increasingly congested Panama Canal and weather impacts suffered by Gulf of Mexico projects. Northern West coast Mexican LNG projects provide on average a 10 day shorter shipping distance to Asia when compared with the Gulf of Mexico – and that is assuming the Gulf Coast projects are not encountering any Panama Canal disruptions or weather delays.

Shipping rates have recently exploded to an all-time high of US$350 000/d, further highlighting the economic benefits of the shorter shipping distance. In addition to the financial impact, LNG tankers are in transit for a shorter period of time, and in turn produce fewer emissions.

Asian buyers are also looking for alternatives to avoid transiting through the Panama Canal, which is becoming increasingly congested, with a recent tanker delay of 11 days in late 2020 as it awaited a transit slot. Using an average of US$100b000/d for a ship charter (assumes deliveries into Japan, 0.10% boil-off, speed 18 knots), this buyer would have incurred an additional US$1.1 million in costs and likely contractual penalties with its downstream customer for failing to meet its subsequent end market arrival time obligation. For those choosing the Cape of Good Hope as an alternative, approximately 14 days are added to the journey – assuming favourable weather conditions. The financial impact of delays are significant, and with no Panama Canal expansion currently planned and increasing Gulf Coast LNG production, a solution is not currently on the horizon to resolve the forecasted congestion, making Mexican projects even more attractive from a pricing and risk perspective.

The Gulf of Mexico also presents challenges due to its propensity for hurricanes and fog.

2020 was the most active hurricane season on record, a historic year with eight landed storms along the Gulf of Mexico, impacting shipping traffic and cargo timing. Furthermore, a record five named storms made landfall in the US state of Louisiana in 2020.

Figure 1. Existing pipeline infrastructure connectivity to Mexico Pacific Backed by strong fundamentals, Mexico is Limited (MPL). the next emerging market for LNG supply, providing: the lowest landed North American LNG price into Asia; a highly competitive landed price globally; and a more direct and de-risked shipping route into Asia, avoiding the Panama Canal, Calcasieu Channel, and highly-impacted hurricane prone areas.

The next generation of North American LNG Figure 2. LNG shipping routes to Asia.

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April 2021

Energía Costa Azul (ECA) LNG announced its Final Investment Decision (FID) in November 2020 for the company’s LNG export project located in Baja California, Mexico. The terminal,

which will be operated by Sempra LNG and IEnova, will include a single-train liquefaction facility with a nameplate capacity of 3.25 million tpy of LNG production, underpinned by long-term contracts with Total and Mitsui. The Pacific Coast project is designed to link natural gas supplies from Texas and the Western US to markets in Mexico and countries across the Pacific Basin.

First LNG production from ECA LNG Phase 1 is expected in late 2024. This was the only LNG project in the world to reach FID in 2020, further validating the advantages of a West coast Mexicobased LNG export project.

The next Mexican project to watch is an LNG export terminal being developed in Puerto Libertad, Sonora, Mexico, by Mexico Pacific Limited (MPL). The company’s anchor project, Mexico Pacific LNG, is a 12.9 million tpy export terminal with the compelling advantages outlined earlier in this article. The advanced stage project has received all major permits required to construct and operate the facility and MPL is already in advanced commercial negotiations with Asian customers. FID is expected later this year or in early 2022, with commercial operations due to commence in 2025, aligned with the forecasted period of LNG market shortfall. With only 4.3bmillionbtpy to sell under MPL’s initial Phase 1, the project is well placed to take its share of the 75 milion tpy incremental supply which is required by 2030 and the 375bmillionbtpy required by 2040.

MPL’s project site is well situated to quickly expand and achieve up to approximately 26 million tpy of liquefaction capacity in the future. As the 12.9 million tpy anchor project and layout represents less than 300 acres of a larger 1100 acre site, the base train design is repeatable; and advanced permitting and future permit modifications can accelerate growth plans.

Figure 3. Rendering of MPL’s anchor project – Mexico Pacific LNG – a 12.9 million tpy LNG export terminal.

Conclusion As the world continues its path of energy transition, LNG will continue to play a material role as a transition fuel while alternative energy and storage solutions for wind and solar options are sought. Energy transition is critical for Asia’s future. According to the UN’s Sustainable Development Report 2020, if China were to reduce its emissions to 2 tpy of CO2 per capita (equivalent to a total reduction of 69.2% from current levels), the world would be 31% closer to achieving the Sustainable Development Goals target on CO2 emissions. With much of Asia’s carbon net-neutral targets heavily reliant on coal-to-gas switching whilst new technologies are being proven, it is key for new LNG projects to be sanctioned in order to achieve these targets. Mexico-based projects offer not only economic benefits for Asia-Pacific gas buyers, but significant environmental benefits too.

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16

Tushar Patel, Atlas Copco Gas and Process, USA, explains how highpressure boil-off gas compression can meet the LNG market’s need for reduced CAPEX and OPEX.

T

he LNG industry has long been characterised by high CAPEX costs. Indeed, since the industry’s early days more than seven decades ago, the requirement to make sizeable investments has been a central tenet to the growth and development of LNG processing. Over the last half decade, however, there has been a larger focus on reducing CAPEX and OPEX. In addition to heat exchangers, various compressors (refrigeration, feed gas, boil-off gas, end flash gas, etc.), constitute a major part of the CAPEX and OPEX in large scale LNG plants. Driven by the desire of LNG plant users for lower costs, there have been advancements in the compression technology that is deployed throughout LNG plants. At the same time, any compression solution must be able to function without compromising the performance, and the reliability/availability and efficiency guarantee of an LNG plant.

A result of these market dynamics can be seen in highpressure boil-off gas (BOG) compressor technology, which has reduced CAPEX while also meeting performance objectives.

Generally, BOG compressors are essential to any LNG plant’s function and performance, whether it is large, medium or small scale. In fact, in some ways, the high-pressure BOG system is the most critical component of the entire LNG process. This is because of the inherent nature of LNG at atmospheric pressure, which begins to boil at approximately -165˚C and convert to gas. Therefore, this presents the central challenge when dealing with LNG: once the gas starts to evaporate, the pressure in the system consequently increases.

It then becomes imperative that the pressure is reduced, otherwise it will eventually cause serious plant safety and environmental issues.

17

So, in order to maintain the pressure in LNG tanks (where the LNG is stored at atmospheric pressure) at a required range, some measures need to be taken in order to handle the BOG. Some of the environmentally friendly options for handling BOG include either reliquefying it and putting it into

the tank; or to use it as a fuel, which requires advanced, reliable, and efficient compression technology.

Traditionally, BOG compressors are used on two parts of an LNG value chain – one is inside liquefaction plants, which can serve as export terminals, and the second is at the receiving terminal of regasification plants, which are usually served by either between-bearings centrifugal compressors or with reciprocating compressors to carry out BOG duty.

In their quest for lower CAPEX and OPEX, both LNG plant operators and process licensors have showed a willingness to accept a different technological approach, ultimately paving the way for a high-pressure compression solution.

An experience-enabled response to market needs

Figure 1. Experience in building fuel gas boosters for natural gas driven power plants contributed to the development of the high-pressure boil-off gas (BOG) compressor.

Figure 2. For decades, Atlas Copco’s Compander has been a hallmark of LNG reliquefaction duty, especially for LNG carriers. It combines compressor and cryogenic expander stages on one single gearbox and skid, providing important lessons learned for smart CAPEX and OPEX solutions in today’s LNG plants.

Figure 3. Reliability is essential for achieving the LNG plant’s overall performance objectives. Key design aspects such as seals, impellers, etc., help in safeguarding compressor availability.

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April 2021

Responding to a market in need of more CAPEX and OPEX-friendly solutions for LNG facilities, Atlas Copco Gas and Process moved to address this desire with its highpressure BOG compressor. This six-stage integrally geared turbocompressor has both cryogenic and warm compressor stages on a single gearbox and skid, which reduces the equipment’s overall footprint.

It is important to note that this high-pressure BOG compressor is not an entirely new solution, but it is instead a combination of proven technology used in different applications in the industry. Integrally geared compressor technology offers a different design approach to tackling a known challenge: the handling of BOG reliably and efficiently.

Experiences from the field in three key areas were factored into this solution. First is that Atlas Copco Gas and Process used its several decades of experience dealing with BOG (in low-pressure processes, to discharge approximately 3 - 5 bar), as well as other processes which operate at cryogenic temperatures (such as refrigeration).

Second is its experience with fuel gas boosters for gas turbine power generation. In this, high-pressure natural gas is delivered to the gas turbine combustor at constant pressure – something that requires very high reliability and availability due to continuous power production requirement by the grids.

Thirdly, the Atlas Copco Gas and Process team drew on its experience from other specific product solutions, notably its Compander, which combines compressor and cryogenic expander stages on one single gearbox and skid.

The team also has more than five decades of experience in one of the highly critical components of the rotating machinery: the seal and seal-support system. All three application areas mentioned earlier require extensive expertise in designing and building seal and seal-support systems that can operate in cryogenic temperature or high-pressure conditions. In 1975, Atlas Copco became the first in the world to implement Type 28 dry gas seals in the integrally geared compressors.

Companders used for reliquefaction duty on LNG vessels (and small scale onshore LNG plants) process nitrogen – the working fluid in the Brayton cycle. The most critical element in the process is the seal type used. In the Compander, both dry gas and carbon ring seals have been used in the past, while for fuel gas boosters specially designed dry gas seals have been employed. Now, this combination of dry gas and carbon ring seals has been successfully transferred and applied to the high-pressure BOG compressor, and it has been greeted with a high degree of market acceptance.

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Experience working with high-pressure compression is also rooted in the company’s expertise in building fuel gas boosters for natural gas driven power plants. In these applications, the suction pressure into the compressor is high and the discharge pressure is even higher – something that is very much comparable to a pipeline compressor. This experience was also applied to the high-pressure BOG compressor concept.

Inside integrally geared design A closer look at integrally geared compressor technology is pivotal to understanding the fundamental design of the high-pressure BOG compressor. The conventional centrifugal between-bearings compressors that are traditionally employed in liquefaction applications feature either a separate gearbox or a variable frequency drive to achieve the necessary rotational speed. In contrast, the integrally geared technology that is used for the high-pressure BOG compressors utilises high speed pinions in combination with low speed bull gear in the gearbox to achieve the necessary speeds. Along with the gearbox and compressor core, the lube oil system, seal-support system, and all the compression stages are built on one single skid.

However, whether a compression solution is integrally geared or not, designing the key components of a BOG compressor core does not come without challenges, many of which are dictated by physics. In this regard, a key design characteristic is to ensure that the cryogenic stage and the warmer stages of BOG compressors do not impact each other.

On the one side there is a cryogenic temperature of approximately -155˚C to -165˚C; on the other side (just several centimetres away) is a temperature of approximately 90˚C or 100˚C (inside the gearbox).

Underpinned by decades of experience, engineers know how important it is to manage the thermal stresses.

Figure 4. Cross-section of the high-pressure BOG core unit. Gears

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Subsequently, when designing the rotor, shaft, and impeller connections, it is vital to provide adequate measures to maintain the correct cryogenic and warm stage temperatures.

Even though every high-pressure BOG compressor is custom designed for each specific installation, insulation is also a vital factor in ensuring cold stage and warm stage integrity.

The basis of every centrifugal compressor is that it needs to provide kinetic energy, and it does this by increasing the velocity of the gas via rotating impellers. On the one hand, the importance of the impeller system is the same for both between-bearings and integrally geared compressors. On the other, because between-bearings machines have impellers mounted on the same rotor, velocity is, to a high degree, determined by the rotational speed of the impellers – which are somewhat restricted due to impeller tip speed limitations.

In contrast, the advantage of integrally geared compressors is that each impeller set is optimised by matching the impeller geometry with the optimal speeds. This ultimately provides greater velocity, resulting in higher head development (pressure ratio) with fewer impellers. Between-bearings machines, for example, run at a maximum of 8000b-b10b000brpm. An integrally geared machine runs anywhere between 10b000 - 30 000 rpm.

Reliability, efficiency, and availability In discussing the high-pressure BOG compressor, it is worth returning to the earlier question of reliability and a compressor’s ability to achieve the intended LNG plant performance. When assessing different compression technologies for LNG plants, this factor is of essential importance.

Reliability is defined as the probability that an item can perform a required function under given conditions for a given time interval. Availability is the ability of a system or product to be in such a state to perform a required function

Shafts

Impellers

Bearings

Seals

Figure 5. The combination of carbon ring seals (left) and of dry gas seals has been successfully transferred and applied to the high-pressure BOG compressor.

under given conditions at a given time interval. From an engineering perspective, reliability is seen as something like the measure of a product’s probability to operate without failure. Reliability, however, is also closely related to quality, and a compressor needs to function reliably and demonstrate a high-quality level. Measured according to industry standards and derived from field feedback, the level of reliability for the high-pressure BOG compressor can be greater than 98%.

While reliability is concerned with the probability of delivering the intended performance of the machine, efficiency and availability of high-pressure BOG compressor technology focus on ensuring that it delivers the intended performance at any given instance during a given time interval (applications include shiploading, unloading, or the hold mode of plants operating in either rich gas or lean gas scenarios). Availability refers to the time the machine is available and if it delivers the intended performance as per the design. In essence, this measure of availability is defined as running time vs downtime. Logically, if the machine is shut down, this affects its availability. Seals and impellers, as discussed earlier, impact availability performance, as do the gearbox and bearings. High vibration, for example, can be the result of errors in rotodynamic designs and/or manufacturing, assuming the process is set and stable. Such a scenario would eventually lead to a diminution of the gearbox, seal failure, and then shutdown. This underpins the necessity to custom design gears and bearings for each individual high-pressure BOG compressor installation and to take into consideration specific process conditions at the LNG plant.

The use of dry gas seals in high-pressure BOG compressors reduces gas leakage compared to carbon ring and labyrinth seals. This adds to both the machine’s efficiency and availability. Used ostensibly in the warm stages, though sometimes also in the cryogenic stages, high-pressure BOG compressors’ dry gas seals are advancements on those used for decades on cryogenic temperatures – as well as other high-pressure applications.

This includes fuel gas boosters, which are required to run for five years non-stop.

Conclusion High-pressure BOG compression addresses a general trend and desire in the LNG industry: leaner and more CAPEX- and OPEX-friendly solutions are in high demand. At the same time, they must meet the test of the highest of plant performance and reliability requirements. The example described in this article also serves as an example of how proven technologies and design concepts can be leveraged to develop different previously unknown approaches to BOG handling.

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22

Chris Vandecasteele, Gaz-Opale, France, outlines how the Dunkirk LNG terminal can be considered a model of safety in the LNG world.

T

he Dunkirk LNG terminal is located at the Western entrance of the port of Dunkirk, France, and is owned

by Dunkerque LNG. The company’s shareholders are a consortium of gas infrastructure group Fluxys, AXA Investment Managers, and Crédit Agricole Assurances, holding a 61%

share, and a consortium of Korean investors led by IPM Group in co-operation with Samsung Asset Management, holding a 39% share. Daily operations, inspections and maintenance are carried out by Gaz-Opale, a subsidiary of Dunkerque LNG and Fluxys.

Figure 1. Aerial view - East side.

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Design began in 2006, followed by a five-year construction period starting at the end of 2011. The terminal was commissioned in July 2016 and started commercial operations on 1 January 2017. With an annual throughput capacity of 13 billion m3 and a total storage capacity of 600b000 m3, it is one of the largest LNG terminals in Europe.

From the very start of the project in 2006, there was a strong focus on a safe, durable, maintenance-friendly design with limited operational constraints.

Involve the operators The future manager was included in the engineering phase as an expert by experience. This allowed the basic concepts to be tested fairly quickly against the safety and operational criteria.

As soon as the Final Investment Decision (FID) was taken, additional operational personnel were added to the team.

Proven technology was combined with new ideas with the aim of minimising the risks of operating an LNG facility. As soon as plans were available, risk analyses – such as hazard and operability analysis (HAZOPs) and layer of protection analysis (LOPAs) – were organised and adjustments were made where necessary. Such iterations in the design phase are much less costly than changes during the construction of the plant.

The Gaz-Opale team expanded gradually during the construction phase, which allowed the technicians and future operators to get deeply involved. They gained a large amount of knowledge and experience by monitoring the works and witnessing the tests. This way of working allowed for the commencement of training and the drafting of operational procedures at an early stage. As a result, the takeover on the 1 March 2017 took place very smoothly.

Safe by design Figure 2. Three 200 000 m3 capacity storage tanks.

Figure 3. Open rack vaporisers (ORVs).

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Key elements for the design were risk mitigation, maximum reduction of emissions, and operational flexibility. As the Dunkirk LNG terminal was a greenfield project on a vast terrain of 56 ha., its developers were able to opt for a less congested design. Larger safety distances and more open space in the process area reduces the risk of domino effects.

An example of this less congested design is the distance in between the storage tanks. The three full containment 200 000 m3 storage tanks are built above ground level with a mutual distance of 80 m and surrounded by a large retention area (Figure 2).

The design of the regasification area is nonconventional. Each of the 10 pumps is individually connected to an open rack vaporiser (ORV). These 10b‘trains’ are spread over five blocks. In between the blocks there is a safety distance of 30 m. Every train has a short LNG pipe connecting the high-pressure pump to the ORV, whereas conventional designs have one big high-pressure collector in between the high-pressure pumps and the vaporisers, resulting in a far larger amount of LNG at high pressure. The design with individual trains can significantly reduce this volume and consequently results in far better safety scenarios. The ORV technology also has a favourable impact on the operability of the process as the heat input is constant and LNG flows can easily be modulated. The less complicated design and lack of rotating parts make them more reliable and easier to maintain.

The jetty area covers more than 3300 m2 – an area greater than three times the size of a conventional jetty.

The large upper platform ensures good visibility during unloading and reloading operations, and for manoeuvring the unloading arms. The lower platforms are less congested, creating easier access to the piping and the valves. The ground floor is easily accessible for trucks and cranes.

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Figure 4. The jetty on the north side.

Figure 5. Aerial view from the west side.

The manned buildings such as the control room, the maintenance building, and the administrative building are located a large distance from the process area. This arrangement prevents gas from entering the buildings in the event of an accidental gas release.

All of the terminal’s large LNG pipes run above draining channels. Unlike conventional leak scenarios, guillotine failures of the LNG pipelines were taken into account.

Consequently, the LNG channels and impounding basins were designed for large spillage scenarios. In the case of a large LNG leak, these open concrete ducts will take the spilled LNG to collecting pits. These large capacity impoundments are equipped with foam generators which will temper the vaporisation process and limit the heat radiation in case of a fire. In addition, UL1709-certified fire walls were installed along the LNG pipelines. These walls limit the heat radiation on the pipe in case of a fire on an adjacent installation, and vice versa, thus protecting adjacent equipment in case of a problem with the pipe.

The send-out pipeline is located underground, which protects it from external risks such as physical impact, heat radiation in case of a fire on adjacent equipment, etc. In addition, these lines are built according to cryogenic specifications, in order to avoid pipe damage if LNG accidentally enters the send-out line.

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April 2021

To protect the storage tanks against leaks, several layers of protection are integrated. The 9% nickel steel inner storage tank is contained in a 1 m thick concrete outer wall and covered with a concrete roof. Overfilling is avoided by using a variety of level detection systems based on different technologies. At each alarm level, a series of safety actions is triggered. In the event of excessive pressure, various pressure relief systems will be activated, depending on the pressure level. In case the tank pressure drops below the minimum, an individual gas or nitrogen injection system will be activated. In the extreme scenario of overpressure and failure of all safety devices, the overpressure is relieved via the roof, leaving the concrete walls intact and as such avoiding an LNG spillage.

The site is also equipped with extensive fire, gas, and cold detection systems. The system was designed to detect LNG leaks, gas leaks, or fire anywhere on site, resulting in a vast network of detectors. In addition, the entire site is declared ATEX, meaning that all electrical equipment has to comply with the requested ATEX-level applicable for that zone.

Even though the northern region of France is considered to be an area with a low seismic risk (zone 1 area), very stringent seismic design criteria have been applied, such as the 10 000 years return period for safe shutdown earthquake (SSE) and 475 years return period for operating basis earthquake (OBE). These criteria put the terminal at the level of the nuclear design philosophy.

Last, but not least, is the high level of redundancy integrated into the terminal. By duplicating all vital systems or providing them with a back-up system, the terminal can be operated in a safe and reliable manner.

In addition, sufficient back-up has been provided for the process installations. This ensures more flexibility to carry out inspections and maintenance work.

Minimise emissions In order to avoid methane emissions, all relief points are connected to a high or low flow natural gas collecting system.

This even includes the high flow pressure relief valves of the storage tanks and the ORVs. This design philosophy makes the terminal a zero-methane emission facility.

The regasification process requires a great deal of heat.

The proximity of the nuclear power plant of Gravelines, France, has created an opportunity to recover a portion of the seawater used by the power plant as cooling water. This hot water is transported to the terminal through a 5 km tunnel and then pumped to the ORVs where it is used to regasify the LNG. The use of this heat source eliminates the need for a heating system at the terminal. This avoids thousands of tonnes of CO2 being emitted from the terminal every year. The very low emission levels of the terminal make it one of the most environmentally sound LNG facilities.

Conclusion An innovative approach was chosen for the design and construction of the Dunkirk LNG terminal. By involving the future operator from the start, optimisation was possible at an early stage and a solid foundation was laid for safe operation.

Sebastian Harbig, Vega, Germany, outlines the role of measurement technology in the LNG industry and how investing in stateof-the-art solutions can help LNG plant operators maximise their performance.

L

NG plays a decisive role in an economically and ecologically sustainable energy future, especially if it replaces more climate-damaging energy sources such as coal or diesel fuel. This is reflected by, among other things, the huge increase in global LNG production capacities in recent years and the number of large scale plants that will enter into operation in the near future. These plants use state-of-the-art technologies and processes for gas treatment, liquefaction, transport, storage, and regasification. But what role does level measurement technology play in all of this? And what are the state-of-the-art solutions here?

Challenges in cryogenic applications The main objectives of LNG plant automation are increased safety, availability, and reliability. In order to ensure stable operation, the deployed measurement technology has to

overcome multiple challenges. These are, on the one hand, troublesome product characteristics, such as: cryogenic temperatures, low dielectric values, fluctuating densities, and turbulent processes. And on the other hand, factors that make installation problematic and costly, such as: high tank mounting sockets, standpipes or stilling wells, shut-off valves, and insulation systems.

For historical reasons, conventional differential pressure systems dominate in the LNG industry, especially in the area of level measurement. These are connected to the process via impulse lines and thus decoupled from the cryogenic liquids. But, alongside the classic differential pressure transmitters, state-ofthe-art pressure sensors with oil-free, ceramic-capacitive measuring cells are now gaining ground in some applications.

The so-called CERTEC® measuring cell of sapphire-ceramic® is designed to be a mechanically robust and dynamically resilient 27

Figure 1. Differential pressure and process pressure transmitters.

pressure measuring cell, characterised above all by notable long-term stability, chemical resistance, extensive overload and pressure shock resistance, and abrasion resistance.

The challenges associated with pressure transmitters lie in the implementation of complex piping, the maintenance requirements, and the influence of density fluctuations on the measuring result. In these areas, technologies such as noncontact radar sensors or guided radar sensors have proven to be viable alternatives. Although they are often somewhat more expensive to acquire than pressure transmitters, these technologies are virtually maintenance free and can reduce the total operating costs, due to their reliability and high installation flexibility. This article will take a closer look at the advantages of a non-contact radar sensor.

80 GHz radar sensor performance

Figure 2. Various solutions for level measurement in cryogenic tanks.

In order to avoid negative influence from internal installations or turbulence in the tank, standpipes or stilling wells are usually installed. When using the new 80 GHz high-frequency sensors, such accessories can be dispensed with and costs saved. In fact, these sensors achieve their best performance when they can measure freely inside the vessel. Especially in cases where interrupting the production process means considerable work and greater costs, shut-off devices are mounted directly on tanks in order to separate the installed measurement technology from the ongoing process. The signal focusing of free-radiating 80 GHz radar sensors enables simple mounting on a ball valve and operation without causing interfering reflections that can negatively affect the measurement. Reliable measurement is thus guaranteed.

Further advantages of non-contact radar measurement include the following: z Precise measuring results, unaffected by density and temperature fluctuations. z Not sensitive to build-up and condensation on the antenna. z Chemically highly-resistant PTFE antennas ensure a long service life for the sensors. z The high accuracy of ±1 mm easily meets the requirements of the industry.

Figure 3. Level measurement and high alarm in Type C tanks.

Installation flexibility with guided radar sensors

Figure 4. Measurement technology from VEGA is used worldwide in the most advanced LNG plants, for example in the US, Russia, and Australia.

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z Simple set-up and diagnostics possible via smartphone or tablet.

April 2021

As already mentioned, a typical requirement in LNG plants is for it to be possible to separate the sensors from the main process, via a valve, without causing an interruption – i.e. without partially or fully shutting down the plant. In answer to this requirement, as an alternative to free-radiating radar sensors, guided radar sensors are available, which can be mounted in combination with bypass systems on the side of a tank. The valves installed between the tank and the bypass allow the sensors to be isolated from the process during operation.

Due to their low operating frequency, guided radar sensors are specialised for use in standpipes and stilling wells as well as bypass systems. Different rod, cable, and coaxial versions are available, which are selected according to the desired installation configuration and process requirements. With its high installation flexibility, the cable version has the ideal prerequisites for use in standpipes or stilling wells, as well as measuring points with

limited installation space. The rod version is particularly suitable for use in external chambers and in combination with magnetic level indicators. Especially in the latter case, the user has access to not only the electronic level signal, but also to an additional level visualisation directly on-site that does not require external auxiliary power. In the coaxial version, the radar signal runs exclusively along a rod in a perforated tube and is therefore completely unaffected by external influences.

The ambient conditions in some LNG applications are often unstable. Measuring instruments are exposed to rapid level changes, volatile atmospheres due to evaporation, as well as significant temperature, pressure, and density fluctuations.

Know-how is crucial, and the continuous development of sensor software enables safe and reliable use of free-radiating and guided radar sensors even in critical applications.

Further advantages of guided radar sensors include: z Precise measuring results, unaffected by density and temperature fluctuations. z Maintenance-free, as there are no moving mechanical parts. z Flexible mounting options, e.g. for easy replacement of existing displacer systems. z Reliable measurement of interfaces between two liquids. z Simple set-up and diagnostics via smartphone or tablet.

Vibrating level switches for cryogenic liquids In addition to continuous level measurement, there is often a need for point level detection, whether as overfill protection in

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tanks or dry run protection for pumps. These point level sensors must also be able to meet the stringent demands of the industry.

Vibrating level switches are universally applicable and suitable for all liquids. Whether as a compact version or with a tube extension, they aim to detect the limit level reliably with millimetre precision. The wide range of applications is unique in terms of process temperature (-196˚C to 450˚C) and process pressure (-1bto 160 bar). Tuning forks can also be used for densities as low as 0.42 g/cm³. Further advantages of this measuring principle include: z Minimal work involved in set-up and commissioning, as it is a plug and play solution requiring no adjustment. z Precise and reliable function due to medium-independent switching point. z High operational reliability through continuous monitoring of the sensor element for corrosion, damage, line break, and vibration frequency. z Higher system availability, as a function a test can be carried out at the push of a button during operation in compliance with IEC 61508 and 61511.

Conclusion The key to greater safety, higher availability, and maximum reliability lies in the selection of the right technology, the ideal configuration, and the correct set-up and commissioning of the sensors. Certain applications may be more suitable for radar sensors, whereas others more suited for pressure transmitters, or in some cases a simple point level detector may suffice.

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Reinaldo Pinto and Ben Keiser, Applied Flow Technology, USA, explain the importance of flow and surge analysis in LNG plants.

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L

NG is a common cryogenic application, requiring temperatures well below -160˚C (-292˚F) to maintain the liquid phase. By maintaining a liquid phase, the transport of natural gas becomes economically viable, occupying hundreds of times less volume than transport in the gaseous phase. While LNG is more convenient and essential for long distance transport, operating a cryogenic system requires additional consideration to ensure safe operation.

As with many other fluids, ensuring hydraulic requirements are met is a core design step. While steady-state operation is the most important and most frequent operating point in a system, it would also be unwise to solely base a design around smooth operation. Instead, considering transient concerns such as surge pressures and their resulting transient forces should be just as important. Especially in the

case of LNG, where hazardous fuel breaching to atmosphere can result in dire consequences, the additional steps of transient analysis should be part of every design process.

This article will review a case study of a hydraulic analysis of an LNG plant expansion performed by Chicago Bridge & Iron Company (CB&I) for an LNG plant that was built in 1999.

The problem CB&I was tasked with performing a hydraulic analysis of an LNG plant expansion. The plant was built by CB&I in 1999 and, at the time this case study was written, the owner requested an increase in the send-out rate to the pipeline. The flowrate needed to be increased by almost 60%, rising from 64 800 ft3/hr (1800 m3/hr) to 102 600 ft3/hr (2900 m3/hr).

One of the customer’s main concerns was the send-out line to the boil-off gas (BOG) condensers and the possibility

31

of pressure surges, as the level control valves close within 3 sec.

Methodology CB&I’s process engineer used a dynamic simulation and analysis software to model and analyse the expansion. Given CB&I had designed the original facility, piping isometrics and a 3D model of the plant were readily available.

Without a benchmark for the original design, the process engineer had to create two models for the plant – one for the pre-expansion and a second for the desired expansion. The pre-expansion model included a flow of 64 800 ft3/hr (1800bm3/hr), with the send-out coming from Tank A using

Figure 1. Hydraulic model.

Figure 2. Resultant volumetric flow of the system.

Figure 3. Resultant maximum and minimum pressures.

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three in-tank pumps all rated for 24 200 ft3/hr (690 m3/hr) at 535 ft (160 m) of head and 76.5% efficiency.

The expansion model shown in Figure 1 included a flow of 102 600 ft3/hr (2900 m3/hr), with the send-out coming from Tank A and Tank B using six in-tank pumps (one is kept in a standby configuration and is not operating) also all rated for 24b200 ft3/hr (690 m3/hr) at 535 ft (160 m) of head and 76.5% efficiency.

Steady-state analysis As a first step, the volumetric flowrate was evaluated to make sure the new arrangement met the flow requirement of 2900bm3/hr. As can be seen from the model in Figure 1, the pipe P16 is a pipe that delivers the full system flow. The pipe results in Figureb2 verify that pipe P16 delivers 2906 m3/hr when operating five pumps in parallel (while the sixth pump is in standby).

The system flow is not the only thing that should be examined. There are many other factors to evaluate with the steady-state operation before performing a surge/ waterhammer analysis.

Firstly, the pump performance should be compared between both scenarios to see if there are any potential reliability issues that may occur. In some cases, simply adding more pumps in parallel does not necessarily always increase the system flowrate. The additional flow that is added depends on the overall resistance of the system. For piping systems that have heavier frictional resistances that the pumps must overcome, it is possible to quickly run into a situation where there is a significant amount of diminishing return with additional pumps.

Not only is there potential for diminishing return on flow with additional pumps, but they also tend to operate at lower flowrates individually as the pumps compete to deliver flow.

As individual pumps operate at lower flowrates, they deviate from their best efficiency point. When pumps operate further away from the best efficiency point, pump reliability issues may present themselves.

The net positive suction head (NPSH) is also important to evaluate. Pumps require a certain amount of NPSH to avoid cavitation inside the pump. This is determined by the pump manufacturer and is the net positive suction head required (NPSHR) curve that is provided along with the rest of the pump performance curves. The net positive suction head available (NPSHA) to the pump must be greater than the NPSHR by the pump to avoid cavitation. The more NPSHA that is greater than the NPSHR, the more margin there is above pump cavitation conditions.

Another important analysis to perform for an LNG system would be a heat transfer analysis. It is imperative that system temperatures remain very low, so the LNG remains in a liquefied state. Heat losses through the piping can be significant if the pipes are not insulated well. Also, pumps can potentially heat up the system fluid slightly due to pump inefficiencies.

All these points are just a few examples of necessary factors to evaluate with a proper steady-state flow analysis to ensure the system is functioning safely and properly.

These examples include, but are not limited to, validating system flowrates and pressures, evaluating pump efficiencies/best efficiency point proximities/NPSH, and heat transfer. Once this is completed and these aspects of the

Figure 4. Resultant maximum forces.

Figure 5. Resultant transient forces at the expansion loop. system are well-understood, then it is critical to perform a waterhammer/surge analysis of the piping system to evaluate sudden system upsets to normal steady-state operation.

Waterhammer/surge analysis results It was determined that with the increased flow, the pressure in the system would remain below the design pressure of 15.5 barG (225 psig) (Figure 3). This reduced the concern of pressure surges resulting from valve closures.

That said, large pressures are not the only concern. Low system pressures can also be problematic. Due to the nature of pressure wave reflections in a waterhammer or surge situation, low pressure wave reflections are also present. System pressures can drop below atmospheric pressure which can be a problem for some piping systems. Sub-atmospheric pressures can possibly cause leaks and contamination of the fluid in the piping system.

Cavitation can also be a major issue in piping systems. When the system pressure drops to vapour pressure, a vapour cavity will begin to form. As the system pressure increases again, the vapour cavity will collapse, which leads to very large pressure spikes. This is similar to balloons popping inside of the piping.

The maximum theoretical pressure surge upon an instantaneous event is given by the Joukowsky equation, also known as the instantaneous waterhammer equation. The Joukowsky equation is presented as: ∆P = –рa∆V Where ∆P is the instantaneous pressure surge, р is the density of the fluid, a is the wave speed, and ∆V is the instantaneous change in velocity.

When cavitation occurs, it is possible to see large pressure spikes that are larger than the maximum theoretical pressure that the Joukowsky equation would predict, as demonstrated in previous studies.1 The LNG mixture of the case study discussed in this article has a vapour pressure of -0.36 barG, or 0.65 bar (9.42 psia) in absolute pressure units. This is a relatively high vapour pressure and, therefore, there is a higher-than-normal likelihood that the LNG system may cavitate if low system pressures reach vapour pressure.

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When cavitation is shown to be present in the model of the piping system, a much deeper analysis of the results is required.

A presentation from 2018 provides some helpful guidance in evaluating cavitation in piping systems when it is present.2 As seen in Figure 3, the minimum pressures in the given flow path are considerably above the LNG’s vapour pressure. Therefore, cavitation is not present when the valves are closed linearly within 3 sec., as discussed previously.

A valve closure is not the only type of transient event that should be considered. Cavitation is possible in a pump trip scenario as well. Not only do low pressures exist from normal low pressure wave reflections, but the system pressures also drop when the pumps go offline in the pump trip event.

Cavitation is a phenomenon that should be avoided as much as possible. Vapour cavity collapse causes high spikes in pressure as discussed before. Also, extensive cavitation that is longer sustained or widespread throughout the system causes very chaotic behaviour which can be difficult to predict reliably. The more constant that the cavitating behaviour occurs, the more the system fluid exhibits a two-phase flow phenomenon, which is very difficult to predict, even with the best mathematical models available. Cavitation is more likely to be present in LNG systems due to higher vapour pressures.

Forces Since there was no benchmark for the pre-expansion flowrate, the project team requested additional information regarding the stress to which the system would be subjected. Comparing the two models, different points in the systems were analysed and the changes in subjected forces were determined.

The maximum force was found at the expansion loop. The force data was provided to a different group to perform a stress analysis of the system. The group determined the forces would increase using the new surge conditions but would remain within the design parameters.

Conclusion When performing a hydraulic analysis of a plant expansion, more than just checking that the new flow requirements are met, other elements such as the safety of the plant must be considered. In this article a case study is described, where additional elements were included in the hydraulic analysis such as: steady-state analysis to evaluate system flowrates and pressures; pump operation for best efficiency point proximity; NPSH comparisons; and heat transfer analysis. The waterhammer/surge analysis evaluated maximum and minimum surge pressures due to valve closure and possible pump trip, transient forces, and dynamic stresses created by a valve closure. The results helped address the plant operator’s main concern that the pressure surges due to the level control valves’ closure did not create a hazardous condition.

While this case focused on cryogenic LNG, these considerations are essential to safe operation in all hydraulic systems, regardless of the fluid in the system.

References 1.

WALTERS, T.W., and LEISHEAR, R.A., 2019, ‘When the Joukowsky Equation Does Not Predict Maximum Water Hammer Pressures’, Journal of Pressure Vessel Technology, Vol. 141.

2.

STEWART, M., WALTERS, T.W., and WUNDERLICH, G., 2018, ‘A Proposed Guideline for Applying Waterhammer Predictions Under Transient Cavitation Conditions: Part 1: Pressures & Part 2: Imbalanced Forces’, 2018 ASME PVP Conference.

David J. Fish, Senior Vice President, Welker, Inc., USA, provides an overview of LNG sampling systems and their streamlined evolution over recent years.

L

NG is natural gas that has been cooled to a liquid state (liquefied) at approximately -260˚F, for shipping and storage. The volume of natural gas in its liquid state is approximately 600btimes smaller than its volume in its gaseous state in a natural gas pipeline.

LNG = liquefied natural gas.

Hugely important to note, it is natural gas in liquid form. It is not a mysterious or unique hydrocarbon. It is natural gas that has been produced in the traditional manner and that has been processed and liquefied for transportation purposes, with the expectation of being vaporised and returned to natural gas for commercial consumption. At -260˚F it is at approximately 600 to 1 in volume. 1 ft3 of LNG is equal to 600 ft3 of natural gas.

This makes marine transport feasible and profitable. Hence, when it is vaporised, it will be natural gas again.

The history of sampling In the late 1970s and early 1980s, LNG sampling became a product line of Welker Engineering Company (known today as Welker, Inc.). Welker was well

35

known in the natural gas sampling arena as the leading innovator of sampling technology, with unique self-purging sample pump designs and constant pressure sample cylinders. Several LNG tankers and a small number of LNG terminals in the US were successfully equipped with Welker LNG systems, which the company had designed essentially around what is now referred to as Figure 2 in ISO-8943.1 It was patterned after the work undertaken to that point by the US National Bureau of Standards and work completed in Japan under H. Tanaka, along with a basic understanding of LNG and the need to revaporise completely in order to take a natural gas sample. ISO-8943 was not available until 1991.

Shortly thereafter, the LNG market left the US shores and became more of a European and Southeast Asia initiative. As the market increased and the need for systems increased, Welker developed a system that incorporated existing natural gas sampling technology with sample pumps and constant pressure sample cylinders. Through the company’s overseas partners, a large number of these systems were assembled with Welker components and design input in Europe and Southeast Asia, and with the success of the design, it was included in the ISO standard ISO-8943 as Figure 3, which was first published in 1991.1 With the strong return of the LNG market to the US, the American Petroleum Institute’s (API) Committee on Measurement Quality (COMQ) recognised the need for an LNG standard in its portfolio to address new technologies entering the market. With permission from ISO, API used

Figure 1. Typical vaporiser and accumulator.

ISO-8943 as the basis for a modified version to the standard, and from 2020 it has been available as API Chapter 8.6.

Along with ISO-8943 and API 8.6, a very valuable document for the LNG measurement world is the GIIGNL LNG Custody Transfer Handbook, latest edition.

It is well known and acknowledged that during the cryogenic process of taking natural gas to LNG, there are impurities and components that are of interest to be removed, and certain process systems monitor for the presence of those and/or the purity level of the LNG. With a different focus, the sampling systems of ISO-8943 and APIb8.6 are designed for the revaporisation of the LNG, and on the heating value of the transported product and the commercial value of the shipped and received product via custody transfer.

Previous studies found that accurate and precise composition determination of LNG mixtures (and other cryogenic liquid mixtures) requires a sampling measurement system (SMS) which contains:2 z A sampling probe which draws a sample without altering the composition. z A sample conditioner which completely vaporises the sample. z A gas analyser which accurately and precisely analyses the sample.

LNG sampling systems LNG sampling systems are located at both loading and unloading facilities. What is loaded is compared to what is discharged at the destination. Boil-off gas (BOG) or ageing (BOG during transport) and other aspects of measurement and transportation have an impact on the custody transfer transaction. BOG will typically be the light ends of the product. Having accurate samples at both ends of the LNG sale will increase the validity of the numbers that come from the gas chromatograph. Proper accounting for BOG can be a significant monetary issue and is recognised as a naturally occurring process.

Custody transfer issues most often centre around the quality and quantity of the product. The sampling system is directly connected to the quality concerns. Of the two, quality and quantity, quality is generally the most difficult one to resolve. A well-designed system can reduce those conflicts. A properly designed system should assure the operator that all the LNG sample that has entered the probe tip at the sample point will come out the back end of the system.

Most typical LNG sampling systems are comprised of a probe to direct the sample flow from the pipeline to the sampling system via specialised tubing runs to maintain the liquid state of the sample. The sampling system is comprised of an inlet check valve; a heated vaporising chamber; an impingement block or device to encourage further vaporisation of any last-minute liquids; an accumulator vessel; outlet regulation and flow control; and sample cylinders or valving direct to the analyser.

Probe importance Figure 2. Typical LNG sampling system.

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As early as 1978, it was understood that the need to keep the LNG sampling line sub-cooled and insulated

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Figure 3. Sample cylinders for sample transfer to a laboratory.

until it was past the inlet check valve to a system was to prevent premature expansion.2 As soon as LNG begins the revaporising process, and even at a cold temperature, there is the possibility during the natural expansion process that components of interest could be pushed back into the pipeline and not directed through the sampling system to be detected by proper analysis.

It was not until 2012 that technology was available to address that concern. A new probe design with a cryogenic check valve at the point where the LNG sample entered the probe in the pipeline assured that all the sample would only continue to and through the sample system. This eliminated any reverse flow back into the pipeline that would occur with typical probes, and the vaporisation process no longer carried the concern of losing components of the LNG. The cryogenic LNG sampling probe is a probe with a unique and patented designed check valve at the probe tip.

Typical systems have probes, but those probes simply divert LNG out of the pipeline and direct the flow to the sampling system located in a cabinet nearby to the pipeline and sample point. To assure that reverse flow does not occur, the sample lines must be maintained all the way to the entrance of the cabinet and the entrance check valve, at or near -260˚F. If the LNG in the sample line begins to expand due to temperature loss, some components (most likely the heavier components) may be pushed back to the pipeline and lost to the sampling system. The cryogenic probe eliminates that concern, in that when the LNG enters the probe tip, the expansion process – if it occurs prior to reaching the sampling cabinet inlet check valve – will only close the probe tip check and prohibit return to the pipeline.

The probe tip check is therefore assuring that all the sample from the pipeline will travel to the sample cabinet, the vaporiser, and ultimately the chromatograph or sample cylinders for the laboratory. Premature vaporisation concerns are removed from the sampling system.

A special container for spot sampling applications has also been developed in recent years for the LNG market. It is

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designed around the concept of the constant pressure cylinder. Using the flowing LNG present at the sample point, the cylinder is chilled to cryogenic temperatures prior to taking the sample.

Acknowledging the expansion factor and the working pressure of the cylinder, a reduced amount of sample is directed into the sample chamber. The contents are transported to a lab where the cylinder is allowed to warm completely, allowing the sample to expand and vaporise in the sample cylinder. During the expansion process, the pre-charge on the cylinder is used as a cushion and slowly bled off, adding volume to the expansion needs.

From the cylinder the sample can be injected directly to the analytical device.

The user knows that nothing was lost in transfer from the pipeline to the lab.

Nothing is left in the tubing, accumulators, heaters, etc. The cylinder will have a special application for special circumstances, but will provide the user with unquestionable integrity regarding the sample taken to the lab.

As technology has improved and innovative and proven designs have entered the market, systems will have variations of the aforementioned systems and improvements.

Welker and other sample system manufacturers have designed and streamlined various aspects of LNG sampling during the last 10 - 15 years.

The LNG sampling industry has made significant advances in the last 10 years and the relevant standards and guidelines are being frequently improved to keep up with, and allow for, new technology in the marketplace. System designs and improvements in technology are beginning to allow for reduced size in the process. The fundamental imperative is the total and complete vaporisation of the LNG sample and its delivery to either sample cylinders for laboratory analysis or directed to an on-site gas chromatograph. Size and complexity are not the key – effective and complete vaporisation are. This is where technology has stepped in and made improvements.

As natural gas becomes more and more in demand as a clean burning fuel for home, commercial, and industrial use, the LNG market will increase as a means of transportation and custody transfer for this proven commodity. The quality of the product and the integrity of the measurement of the LNG will continue to be of foremost importance for the LNG market. Improved technology in both the volume measurement (metering) and the quality measurement (sampling) of LNG will serve the industry for years to come.b

References 1.

ISO-8943 - Refrigerated light hydrocarbon fluids — Sampling of liquefied natural gas — Continuous and intermittent methods – Latest Edition

2.

PARRISH, W.R., ARVIDSON, J.M., and LABRECQUE, F.F., 1978, ‘Development and evaluation of an LNG sampling measurement system’. National Bureau of Standards (USA). Thermophysical Properties Div.

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Figure 1. STS LNG transfer with marine loading arms on a FSRU.

Raphaël Poichot, Technip Energies Loading Systems, France, details how ship-to-ship LNG transfer has surpassed challenges and advanced operations.

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T

he first ship-to-ship (STS) LNG transfer occurred in March 1984 in the Persian Gulf between two large LNG carriers, the Norman Lady and the Hilli Episeyo FLNG, under the initiative of the Abu Dhabi Gas Liquefaction Company.

LNG transhipment, or direct transfer of LNG from two vessels moored in a side-by-side configuration, was seen as a valuable alternative to conventional loading/unloading at LNG terminals.

At its start, LNG transfer was managed with hoses placed on a plywood floor built and attached between two ships. All operations were manual or managed with a ship crane without any safety devices across the transfer system. With such an arrangement, calm sea conditions were essential to prevent any dramatic consequences.

The LNG industry moved forward over the next 20 years with the emergence of FSRUs in the 2000s as STS LNG transfer operations continued to be managed with hoses. Most of the installations at that time were located in sheltered waters or in very calm weather areas, with only a few unloading operations per year as the

41

FSRU was used as a seasonal and complementary source of energy. Soon, the hose-based transfer solution was improved: the hoses were suspended between the two ships bending on their self-weight in a catenary shape. Safety systems such as emergency release systems (ERS) were integrated across the transfer lines, improving the level of safety to the minimum required for such critical operations.

As more FSRUs became operational and installations increased, new parameters appeared in the selection process of LNG transfer systems, including availability in severe weather conditions, compatibility with higher transfer rates, greater compliance with local safety regulations, etc. As some FSRU operators were inclined to replicate the performance and safety standard level of jetty operations, a few FSRUs were equipped with marine loading arms, which had been used for decades on conventional LNG terminals.

With floating LNG (FLNG) technology emerging, the oil and gas majors also turned toward marine loading arms to manage STS LNG transfer more efficiently: z The unloading frequency is generally higher with FLNG than with FSRUs. With its remotely operated manoeuvring system, marine loading arms preserve the operator safety especially when the connection/ disconnection operations become repetitive.

Figure 2. Ship-to-ship (STS) LNG transfer with hoses on a FSRU. Image courtesy of Excelerate.

Figure 3. Articulated Rigid Catenary Offloading System (ARCOS).

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z The offloading function on a FLNG is highly critical and imposes reliable transfer systems. Marine loading arms have demonstrated outstanding track records in the LNG industry for years. z Most of the FLNGs were deployed to operate remote gas fields where severe environmental conditions require robust transfer systems. The structure of a loading arm, separated from the product line, offers a smoother and predictable transfer of loads resulting from sea motions.

For more severe offloading conditions, the marine loading arm technology evolved with targeting systems, i.e. an integrated mechanical assistance to guarantee safe connection and disconnection in offshore conditions. Such a targeting system is composed of fibre rope stretched between the floating facility and the LNG carrier to guide the loading arm toward the LNG carrier flange in dynamic conditions. It was deployed first on the gravity-based structure of the Adriatic LNG terminal in Italy, operating since 2009. It was then applied to all offshore FLNGs, to some FSRUs, and to exposed jetties.

LNG transfer solutions: Performance and comparison These days when it comes to STS LNG transfer solutions, the industry is divided into two camps: cryogenic hosebased solutions and marine loading arms.

Cryogenic hose-based solutions are used in more than two out of three FSRUs, which also have low offloading frequency on a monthly basis. It is a lean, simple and cost-effective solution, which can be easily replaced or removed if damaged. The integration of the hose solution onboard is relatively simple since it does not require any structural reinforcements of the receiving platform.

Operators have become familiar with its operating procedure and in past years demonstrated its simplicity and convenience.

On the other hand, flow performances are limited by the technology. The pressure drop and heat transfer in a hose are much higher compared to rigid pipes. These are sources of additional boil-off gas that need to be addressed onboard the FSRUs during the transfer, with induced limitations of the transfer flowrate possibly resulting in a longer STS operation. The technology also is limited in diameter, requiring more lines to achieve a reasonable flowrate, hence the repetition of lifting operations to connect and disconnect the lines with all the accessories. A standard hose installation is generally composed of 8b-b10bhoses to achieve a flowrate of 10b000bm3/hr. This may become a safety issue should the unloading frequency increase.

The drainage operation is based on vaporisation with water sprayed on hoses – a tedious operation relying on the temperature of the sprayed water. Equally the purging operation is impacted by the permeability of the hose section creating gas pockets across its layers, which significantly extends the time to reach an acceptable level of gas inside the hose before safely disconnecting.

In certain conditions, the advantages of hoses are predominant and remain the most preferred STS LNG transfer solution for floating facilities moored in sheltered waters, with LNG carriers calling on a monthly basis. Hoses

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also offer the flexibility for the FSRU to relocate to another site after a few years should its charter contract end. With marine loading arms, such transits must be considered at the design phase.

Marine loading arms are generally required for facilities where fast transfer operations are expected, as the rigid technology brings high-flow performances and the MLA geometry the benefit of gravity drainage.

Latest technology solutions The LNG industry is rapidly evolving as demand increases for low-carbon sources of energy. The STS LNG transfer solutions are adapting to offer higher operating performance and improved safety standards.

The development of new types of hoses may advance the operating performances of facilities installed in sheltered waters. A recently developed solution, called the Articulated Rigid Catenary Offloading System (ARCOS), mimics the behaviour of hoses using rigid technology.

ARCOS is a self-supported, fully rigid transfer system composed of three 16 in. articulated piping assemblies made of stainless steel pipes and field-proven cryogenic swivel joints equipped with full bore ERS – the same ERS used on marine loading arms.

ARCOS is adapted to FSRUs, FSUs, and FLNG vessels located in calm to mild weather conditions, i.e. up to Hsb=b1.5bm. The solution improves the flow performance with a transfer rate up to 15b000 m3/hr with three liquid lines, reducing operational time by as much as 40% from connection and transfer to drainage and disconnection.

On the safety side, with two times fewer lines than hoses, the risks of crushing hands and dropping objects are significantly reduced – a great asset for frequently performed installations. ARCOS also includes a SIL2 rated drift detection system, offering reliable emergency shutdown (ESD) capabilities.

In addition, transportation is facilitated since the ARCOS lines are stored on a skid and shipped by standard ISO containers, optimising costs and delivery time. The skids also are used to safely support the ARCOS lines onboard the vessel during maintenance.

ARCOS offers the combined advantages of hoses and loading arms, creating an enhanced operating and safety performance for STS LNG transfers in sheltered to mild waters.

Conclusion

© REMBE® | All rights reserved

Despite being part of the LNG landscape for decades, rigid articulated pipe technology shows a great potential for improvement. It is perfectly adequate for the implementation of intelligent features used in other industries that can transform an elementary mechanical system into a more autonomous, smarter, and digitalised system.

The field of possibilities ranges widely from preventive maintenance to automation, and from constant position monitoring to advanced human machine interfaces (HMI), all with the goal of significantly reducing investments and operational costs. The transformation has begun in earnest as the automatic connection of marine loading arms to a ship is now available, paving the way to safer unmanned operations.

Gallbergweg 21 | 59929 Brilon, Germany F +49 2961 50714 | www.rembe.de

Pierre Barere and Gilles Tissot, Opta-Periph SAS, France, address the suitability criteria of LNG probes/vaporisers and autosamplers, ensuring they comply with international standards.

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he suitability criteria of LNG probes/vaporisers and autosamplers have to be carefully checked to be in full compliance with recognised international measurement standards including ISOb8943, EN 12838, and the GIIGNL handbook. Ignoring these field proven criteria could lead to uncertain

measurements, inaccurate performances of the sampling, and latent damages of equipment. This article aims to address the major suitability criteria and their conditions of application.

As the first and fundamental recommendation of the ISOb8943 standard in paragraph 6.9.2: The line from the

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Figure 1. Simplified low flow vacuum probe.

Figure 2. Comparison between the Bill of Loading and the Bill of Unloading.

Figure 3. C2 abnormal downward slope.

sample probe to the inlet of the vaporiser shall be maintained in a sub-cooled state.

This means that partial vaporisation (fractionation) is not admitted even if followed by active sub-cooling reliquefaction, operated upstream of the vaporiser to improve repeatability – as represented in Figure 1.

Such unsuitability to the protocol introduces uncertainty in the measurement due to the thermodynamic state equilibrium variations into the probe. A product reliquefied further to the phase transition cannot be representative of the original LNG sample’s true value.

As reliquefaction systematically produces acceptable repeatability, how can one ascertain that the LNG is maintained in the liquid phase right up to the vaporiser?

The first approach to identify the standard compliance with a sub-cooling state consistent at all points of the length of the probe, is to check the thermal conductivity of the insulation material and the sample vaporiser flowrate.

According to ISO 8943 P21/28 Chapter 8, the required LNG vaporised flowrate for sub-cooling compliance of a probe/vaporiser not vacuum-insulated is 20 kg/hrb=b27b000bNl/hr and as the vaporised sample flow is reverse proportional to enthalpy rise, smaller flowrates can inevitably result in phase transition, producing thermodynamic state equilibrium variations.

It is relevant to note that in the GIIGNL handbook, paragraph 6.5.3 considers for the flowrate of high vacuum technology probes/vaporisers to drop to 1000 - 1500 l/hr for the vaporised sample flowrate.

When available, the most significant observation is the sample analysis comparison between the Bill of Loading and the Bill of Unloading. In the example in Figure 2, the sampling systems are located on both sides of export and import terminals – the content of C1 at loading is 93.28% in comparison with 93.23% at unloading. This deviation of 0.05% is confirmed by the predictive model (Molas) of ageing during ship transportation.

Quite often, with unsuitable probes/vaporisers, some aberrations are reported by users and third parties, for instance methane measurements at unloading import terminals can exceed the methane measurements recorded at loading export terminals.

Most frequently, this typical error is due to a C2 abnormal downward slope, as represented in Figure 3.

From this observation, if during a transfer (loading or unloading) the value of ethane decreases, then the unsuitability of the LNG probe/vaporiser to give the measurement true value is definitive.

Another phenomena related to active sub-cooling probes regards dry ice formation plugging the probe, with a peak of carbon dioxide greater than 500 ppm during the transfer. The presence of this frost (de-sublimation) is another sign that LNG has not been maintained in the liquid phase right up to the vaporiser.

Continuous probe developments

Figure 4. Patented vacuum LNG probe/vaporiser.

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The continuous Opta-Periph probe/vaporiser suitability criteria have been carefully checked by the pre-eminent export and import terminals and found to conform and be in full compliance with recognised international measurement standards ISOb8943, EN 12838, and the GIIGNL handbook.

Further to the success of the only patented vacuum LNG probe/vaporiser (Figure 4) developed and continuously enhanced during the last decade, there have been many notable performances of the ISOPROBE 8100 in the market, with more than 250 of these probes in action on worldwide installations in the LNG industry.

According to Figure 5, the vacuum thermal insulation – from the probe tip inside the LNG pipe to the vaporiserb– along with no heat absorption at the probe flange, is a guarantee that the LNG sample remains in sub-cooled conditions the entire way to the liquid to gas converter.

For a routine inspection facility, the automatic vacuum generator Vacauto 8100 has been developed and can be retrofitted to old probes.

To comply with hazard and operability (HAZOP) rules, low temperature embrittlement damages are prevented by automatic shut-off valve.

Continuous sampling system z ISO 8943 paragraph 7-4-1 e)bOuter compartment of Figureb6 is to be filled with natural gas and not by motive air, nitrogen, or neutral gas such as helium. z ISO 8943 paragraph 7-4-1 d)bIn cases where a waterlesstype gas sample holder is used, prior to initiating the sampling it shall be confirmed that there is no leakage of gas between the inner and outer compartments within the gas sample holder. z ISO 8943 paragraph 7-4-1 a) Prior to initiating the sampling, any residual gas from the last operation that may remain in the gas sample holder shall be completely purged.

LNG autosamplers LNG automated sampling systems require thorough checks to ensure they conform and comply with the recognised international measurement standard ISOb8943.

Basic difference between continuous and intermittent sampling system Continuous auto-sampling gives the guarantee that 100% of the population has been sampled and a capacity can be recovered, instead of in intermittent sampling.

In intermittent sampling, grabbing system accuracy confidence level is determined by the number of samples. Considering the population sampled by the grabber, the confidence level to reach an accuracy of 0.15% on a CH4 peak has not been proven to match with the 95% confidence level of continuous auto-sampling.

Figure 5. Vacuum thermal insulation.

Table 1. Different types of the ISO 8943 autosampler comparison common view Continuous water seal type (Dome sampler)

Continuous waterless type

Intermittent sampling type

Sampling method

Continuous sampling method

Continuous sampling method

Discontinuous sampling method

Accuracy

Relatively high compared to intermittent type

Relatively high compared to intermittent type

Relatively low compared to continuous types

Endurance

Use of water may cause corrosion and friction. However, there are no particular problems, even if using over an extended period of time

Water is not used; no corrosion by water

Water is not used; no corrosion by water

Initial purchasing cost

Relatively high compared to continuous waterless or intermittent type

Relatively low compared to continuous water type

Relatively low compared to continuous water; same as continuous waterless

Maintenance cost

Relatively high compared to continuous waterless type

Lowest compared to continuous water seal and intermittent types

Relatively high due to fast motive parts

Size

Relatively big compared to continuous waterless or intermittent type

Relatively small compared to water seal

Smaller than continuous types

Cleaning

Not required

Not required

Required after each time of sampling

Utility

Instrument air (intermittent) Nitrogen (maintenance) Demineralised water (maintenance)

Instrument air Nitrogen (maintenance)

Instrument air (intermittent) Helium (intermittent)

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z Gathering sampling data/analysis data as required per ISOb8943. z From the acquisition of the gas chromatograph molecular fractions measurement and the pipeline pressure and temperature, determination of the pressure/enthalpy polynomial by Peng Robinson state equations, as well as continuous checking of the sub-cooling compliance with the ISO 8943 standard. z Enabling ‘start’ and ‘stop’ monitoring during stable conditions as per ISO 8943, and also ‘pause’ if conditions change.

Figure 6. Left: ISO 8943 holder. Right: patented Opta-Periph holder.

The patented Opta-Periph ISOSAMPLE 8100 continuous waterless sampling system presented in Figure 6 is fully compliant with the ISO 8943 standard.

Required data from sampling and analysis The prime target of the ISOQUALIF statistical basis software – which deals with data information collected by the sampler control station – is to qualify the LNG sampling/GC package at the site acceptance test (SAT). The main operations of the software include:

z Identification and rejection of outliers – samples which are not representative of the true cargo composition as per API Manual of Petroleum Measurement Standards, Chapter 13.1 (2006), and ASTM D6299 (2008).

Later on, the system is used by the terminal operators as it gives them the ability to create and supply an analysis loading document with relevant data.

Conclusion In conclusion, it is of fundamental importance that international measurement standards including ISO 8943, EN 12838, and the GIIGNL handbook instructions are strictly followed and not only skimmed. Without strict adherence to these, there is high potential that a repeatable measurement will be inaccurate, moreover, claiming for compliance requires total fulfilment of the instructions.

THE ONLY TRUE VACUUM PROBE VAPORIZER IN FULL COMPLIANCE WITH ISO 8943, EN 12838 AND GIIGNL HANDBOOK

MORE THAN 250 TAKE-OFF POINTS WORLDWIDE

Jonas Berge, Emerson Automation Solutions, Singapore, discusses how LNG plants can embrace a new era of automation as the fourth industrial revolution comes to pass.

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n recent years, many plants along the entire LNG value chain have struggled to meet their operational excellence goals, often due to the way work is carried out. Digital transformation is a new approach to overcoming many of these challenges by adopting new digital ways of working. To this end, industry leaders are deploying digital operational infrastructure to enable these new work practices. Several best practices have emerged for the architecture, execution, and implementation of change management involving this transformation. Many are different from what was originally thought. As a result, plants are now able to meet their operational excellence goals one by one.

LNG value chain challenges Offshore installations, onshore well sites, liquefaction plants, floating LNG (FLNG) vessels, pipelines, LNG carriers, storage and regasification terminals, power plants, and chemical plants are all facing higher corporate and global market expectations and the need to stay compliant with ever-changing policies. On top of this, they must find a way to remain operational even during a pandemic.

These expectations are fundamentally tied to operational excellence, i.e. the need to increase revenue, reduce risk, and reduce cost. Plant challenges include scheduled and unscheduled downtime and maintenance costs due to equipment failure, and loss of containment.

High energy cost and flaring is an issue in some plants, and incidents are low but need to be reduced down further across the board. Off-spec product can occur due to unforeseen process upsets. For offshore and other remote installations there is a high cost of travel and accommodation for personnel and contractors. Most companies already have operational excellence programmes in place, but struggle to achieve their goals with their current approach. Their success is held back by too many manual work practices involving energy management, reliability management, maintenance management, production, quality management, and safety management.

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revolution was about computing power, and now the fourth industrial revolution is about the power of data.

Plants deploy a fourth generation of automation as their enabler for the fourth industrial revolution. Several best practices stand out among plants that have been successful with implementing digital transformation and applying fourth generation automation technology.

Discovery workshop Figure 1. Visualisation of a digital operational infrastructure (DOI) technology stack.

Starting by investing in a new data platform (hosted in the cloud) with 5G Internet of Things connectivity and AI is not the right way because not all of them may be required. Best practice is to start digital transformation with a discovery workshop to uncover operational challenges in the plant. Based on these actual plant challenges, the solutions can be chosen. Mostly it will be readymade solutions, but in some cases new solutions are co-created by solution providers, such as Emerson, and the user.

Agile design thinking – iterative process

Figure 2. Operational dashboards and notifications displayed on mobile devices.

Digital transformation of the LNG value chain To achieve operational excellence, plants could add more staff or contractor heads, replace piping and vessels, change machines and equipment, make a plant expansion, or make changes to the process technology – but that would be very costly and disruptive. Instead, plants now opt for digital transformation with Industrie 4.0, which is easier and carries a lower cost than making physical changes to the plant or adding personnel.

Digital transformation means moving from manual and paper-based ways of working to new, automatic, digital, softwarebased, and data-driven ways of working. For instance, personnel used to collect data manually, reading gauges or using portable testers. Now data collection is being automated using permanent sensors. By collecting data more frequently, developing problems are detected sooner, making plants more predictive. And since it is automatic, personnel also become more productive. Analytics software helps personnel diagnose process and equipment problems, and recommend action: this is descriptive and prescriptive analytics.

Similarly, instead of taking field notes in a paper notebook, field operators can use an industrial tablet or phone. And instead of a manual mustering headcount, personnel carry a tag that automates the mustering roll call. Rescue locating shows a missing person or man-down on a plot plan in software so first responders can rescue them quickly, without the need for search parties to go back into the plant. Geofencing systems sound an alarm when personnel stray into a high-risk area, maybe during high-risk activity, and each worker can be equipped with a distress call button. These are just a few examples of how work is changing.

Fourth generation automation The first industrial revolution was about steam power, the second industrial revolution was about electric power, the third industrial

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All plant operations cannot be changed in one go. Personnel cannot absorb that much change, and it would be taxing on resources and capital. With too many projects there is a risk of getting stuck in ‘pilot purgatory’. Best practice is to develop a roadmap where solutions are deployed in phases. Over time, solutions for reliability and maintenance; integrity; energy and emissions; safety and health; and production and quality come together to transform the entire operation. Once the roadmap is completed, start over with a new workshop to tackle a new set of issues.

Build shared digital operational infrastructure Solutions must not be deployed in isolation. Best practice is to build a shared digital operational infrastructure (DOI) benefitting all operational departments across the entire plant (Figure 1). At the highest level are the operational dashboards, notifications, and reports. The information in them in turn comes from the underlying application framework: software Apps for condition and performance monitoring energy management, as well as other analytics. Below that is the data management platform: this is the plant’s existing historian which mainly focuses on time-series process data, but it is extended, not duplicated, for the management of the new equipment data.

The most interesting fact is that most plants keep their data servers on premises within the plant, not in the cloud. The foundation is the data sources: the plant’s existing sensors, plus new data sources such as wireless sensors to automate data collection. All of this does not have to be deployed at the same time, it is best introduced piece by piece as problems are solved.

Operational dashboards provide an at-a-glance overview of each person’s area of responsibility: on-the-go, on their tablet, wherever they are, even when working from home – thus they are always aware (Figure 2). While operational reports tend to be lagging key performance indicator (KPI) snapshots, dashboards are leading real-time operational indexes. Personalised operational dashboards can also be displayed on a laptop, desktop, or a large video wall in a fleet management centre or control room. Operational notifications pop up on the phone of the person responsible when a problem starts to develop, so they can take swift action to prevent it. Dashboards and notifications are personalised based on each person’s role and responsibilities,

so they do not get spammed with notifications that are not relevant to them.

The information in the dashboard comes from underlying analytics software, which in turn receives the raw data from existing systems, but also from many new sensors.

Scalable architecture A scalable architecture starts with the plant’s existing historian as the data management platform, so plants can economically start digital transformation as small as a single use case. It would not be practical to spend millions on a new software platform before the first solution can be developed. After the first use case is completed, plants then add solutions over time, plugging in more Apps and sensors. Best practice is to follow the NAMUR Open Architecture (NOA) where the digital operational infrastructure is a second layer of automation for monitoring and optimisation, on the side of, but integrated with, the existing automation for the core process control.

The NOA approach preserves the safety and robustness of the plant’s existing control system. The control system remains as is, it does not have to be replaced. This new digital operational infrastructure includes the sensors, wireless networking, analytics software, and dashboards. This is the fourth generation of automation.

Digital workforce enablement

are looking for. As the technician holds the device up and looks ‘through’ the screen, there is a graphical line in their field of vision that points them in the right direction. There are AR markers which appear to be floating above the equipment with information telling if the process line is depressurised and cool before work starts.

Personnel in some plants do not have time to look at the analytics or manage the software and server themselves. In this case, they can subscribe to IIoT-based connected services. The sensors on the equipment send their data to analytics software running in the cloud, which eliminates the need for lots of contractors on-site. The service provider’s experts extract and review the report from the analytics before sending it to the team on-site to act. The report lists steam traps to replace, pumps to overhaul, and heat exchangers to clean. The service provider also manages the server and software and flags any issues with the sensors themselves.

Operational excellence Plants that are digitally transforming with Industrie 4.0 are seeing results benefitting multiple operational departments.

The maintenance and reliability departments are seeing greater availability, reduced maintenance costs, extended equipment life, greater integrity, shorter turnarounds, and longer time intervals between turnarounds. The process energy team sees lower energy consumption and cost, reduced emissions, and reduced carbon footprint for sustainability. The health and safety group sees fewer incidents involving personnel and environment, faster response times, and lower incident costs for overall lower risk. The production department sees reduced off-spec product (higher quality), greater throughput/capacity, and reduced operations cost. Compliance and productivity are also improved.

The existing maintenance, reliability, integrity, energy management, safety, production, and quality engineers and technicians cannot become data scientists or programmers.

Therefore, technology must be selected thoughtfully to avoid making the skills gap too wide. Moreover, most plants cannot afford to hire a pool of data scientists or programmers. Best practice is therefore to provide easy-to-use tools such as readymade, purpose-built, engineered analytics based on LNG 4.0 fault-trees and first principles for equipment such as pumps Until now, plants along the LNG value chain have been and compressors, thus lowering the skills threshold. These Apps struggling to meet their operational excellence goals; mostly predict equipment failure and fouling so personnel can act early. due to their manual ways of working. Digital transformation is The Apps can be deployed, used, and supported by the existing now overcoming these challenges by adopting new digital ways engineers and technicians with little or no re-skilling. Apps are of working. These new work practices have been enabled by a web-based, so personnel can work from anywhere, even from new digital operational infrastructure. By adopting best practices home during a pandemic. that are quite different from what was originally encouraged, For the not-so-well-known problems, machine learning data plants are now able to meet their operational excellence goals science tools are used to extract hidden knowledge from existing one by one. It is time to start the digital journey for the plant by data in the historian, collected over the years. This provides the conducting a discovery workshop. capacity to connect the dots; and to build a model which is then used for prediction of product properties, process upsets, or other This article was first presented at the Gastech Virtual Summit 2020. issues.

Before connecting the dots, however, the dots need to be collected. Sensors are used to automate data collection instead of manually reading mechanical gauges and using portable testers in field operator rounds. Plants may need hundreds of additional sensors to automate the data collection. Wiring those sensors in an existing plant would not be practical, therefore, wireless sensors are used instead.

Many of these sensors are also non-intrusive so no cutting, drilling, or welding is required either; the sensors can be installed while the plant is running.

Once analytics predicts a problem it must be settled in the field. It can be time-consuming to find a small piece of equipment in the plant. Augmented reality (AR) software Figure 3. Digital transformation drives operational excellence installed on a tablet or phone which is approved for all across all operational areas. hazardous areas, guides the technician to the equipment they

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Gobind N Khiani MEng PEng, GAPV Inc., Canada, and Robert Weyer, Amesk Corp., Australia, assess how operations can stay uninterrupted by modularisation in LNG plants, addressing valves in particular.

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odularisation for industrial projects continues to grow at a rapid pace.

Initially only considered for projects in remote areas, modular execution is now very common across the industry. The tighter space constraints in modules give new challenges to engineers, especially in allocating adequate space for a facility’s access, operations, and maintenance. Piping and valves are an important aspect that must be carefully considered and can vastly affect module size and layout. Piping and valve sizing, function, set-up, orientation, and weight all affect design requirements. Furthermore, automated valves take up more real estate and affect module layouts, especially large actuators. Performance and safety also play a key role when valves are installed in a module.

Plug and play engineering must be technically sound and achieve the requirements expected for a facility to operate safely, deliver the specified product, and achieve the target production. One key aspect to successful modularisation is adhering to the concept that modularisation drives layout, rather than layout driving modularisation. Radically different design concepts in plug and play or modular units compress the size of a facility through plot plan reorganisation by process blocks and require all engineering disciplines to be re-focused and aligned to support this goal. Advanced modular design concepts have demonstrated a reduction in facility footprints of 30%, with associated savings in material quantities.

A key consideration (and difference in modular execution) is the ability to obtain early reliable vendor data, particularly with respect to piping and valve instrumentation and controls. The project team must also work to an advanced (early) schedule. Careful weight management is needed to control module size and prevent shipping and installation surprises. Additionally, modular execution plans must maximise installation, pre-commissioning, and testing prior to shipment of completed modules to the jobsite (a plug-and-play approach). An often overlooked area is the impact of specifications on the plot space required for the valves. Piping systems are designed to American Society of Mechanical Engineers (ASME) codes or Canadian Standards Association (CSA) standards and the client’s specifications. Civil structural beam sizing and connection designs are designed to CSA S16 Standard.

Vessels are designed and calculated in accordance with ASME Code Section VIII, Divb1bor 2. Electricals are designed to the Canadian electrical code and the client’s specifications. The valves fit in between all of these and need to be carefully evaluated per American Petroleum Institute, International Organisation for Standardisation, and CSA standards in terms of size, weight, shape, and tolerances, including functional requirements. These evaluations are undertaken early in the engineering sequence to avoid surprises later.

LNG plants contain a significant amount of piping that is characterised by one or more of the following: large diameter, high design pressure, cryogenic

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temperatures, stainless steel, high velocity gas flow, large diameter-to-thickness (D/t) ratios (sometimes exceeding 100), and load cases not explicitly addressed by design codes.

These have presented challenges and exposed some of the limitations in existing piping design codes and standards. ASME B31.3 Process Piping was originally developed to serve refineries where the piping is generally carbon steel, low pressure, hot, and handles liquids. LNG plant piping often has high design pressures, cryogenic temperatures, gas flows, significant use of austenitic stainless steel, and larger diameters.

In the case of a module, it is easy to generate pipe spool drawings in-house. Piping isometrics, fabrication drawings, bill of materials, etc., can be developed automatically, providing large savings while maintaining a high level of material accuracy.

Additional tools, such as procurement practices and tracking systems, are available to ensure that all material or specialty purchased, engineered-to-order equipment are according to client’s specifications.

For challenging scopes of work, special considerations are required. For example, fabrication of nine 24 in. isolation sectioning valve assemblies, six 5D field bends, and one set of 30bin. × 24 in. pig launcher and receiver barrels can be difficult. In this scope, the responsibilities included are valve assembly welding, hydrotesting, non-destructive examination, electrical and mineral insulated heating cables, and fabrication of custom heat-traced and insulated structural assemblies that are welded directly to the pipelines. This work can more easily be facilitated and installed in a modular fabrication yard than at the jobsite.

Preservation of piping and valves for transportation from module yards to site, as well as any additional waiting time at site before start-up, presents a particular challenge. Preventing corrosion during this lag time requires consideration of both the surface being protected and potential corrosion mechanisms.

While vapour phase (fogging type) corrosion inhibitors are effective at preventing internal corrosion, they may require degreasing and stripping by the end user – particularly for cases where cleanliness is critical or where such an inhibitor has been over applied. Stainless steels are more susceptible to microbiologically induced corrosion (MIC) and chloride stress corrosion cracking (CLSCC). Often the problem is residual water from hydrotesting. The difficulties lie in drying piping, as well as the time period where residual water in stainless steel is open to atmospheric conditions prior to start-up. Use of corrosion inhibitors in the hydrotest medium or pressurising with an inert gas (such as nitrogen) are possible mitigation methods. However, sometimes more radial methods are required: z Avoiding hydrotesting altogether (by pneumatic testing). z Use of non-metallic piping materials.

Preventing external metal loss due to corrosion under insulation (CUI) in modularised piping also requires consideration.

Insulated piping in continuous operation at temperatures above 175˚C is normally not coated or painted, since the operating temperature is high enough to avoid CUI. However, if there is a long period of one to two years (between putting on insulation in a module yard and plant operation) where the pipe is insulated but at ambient temperature, there is a significant risk of CUI occurring. In this case it may be better to apply a coating, only insulate at site, or include an extra corrosion allowance to cover the waiting period.

Pneumatic testing is common in LNG plants as it avoids the issues caused by residual water from hydrotesting. However, the compressibility of the gas creates a stored energy hazard which is normally managed using exclusion zones based on ASME PCC-2.

There have been some notable changes to ASME PCC-2 recently: z Since the 2015 edition, exclusion zone calculations must now consider both blast wave and fragment throw (previously only blast wave was considered). z Prior to the 2018 edition, stored energy was based on total volume being tested. From the 2018 edition, 8× diameter can be used for piping.

These changes recognise the hazard posed by fragment throw while providing a more realistic calculation of the potential stored energy that can be instantaneously released by a piping system.

LNG plants contain many potential sources of piping vibration such as rotating equipment and high momentum/velocity internal fluid flow.

While the preferred solution is to eliminate potentially harmful vibrations or reduce it to acceptable levels, the B31.3 piping code has historically been silent on quantitative assessment criteria for high cycle fatigue. Appendix W High-Cycle Fatigue Assessment of Piping Systems was introduced in the 2018 edition of B31.3. This welcome addition to B31.3 is subject to owner’s approval; this should be viewed as another alternative rather than a mandatory replacement to other methods such as ASME OM-3 or weld geometry fatigue curves.

Further improvements are expected and some predictions of future piping developments that will benefit LNG plants include: z Increased use of shell modelling for large D/t ratios. z Advances in stainless steel welding. z More use of non-metallic piping. z Focus on dynamic loads due to fluid transients (in progress with the development of ASME B31.3 D).

Valve design and selection Valve design in modules requires special considerations especially due to tighter space constraints. Important design aspects that impact valve size and surrounding space requirements include valve service pressure and temperature, flowrate, pressure drop, the flow media’s fluid and chemical properties, packing design, seat design, actuation alternatives, special cleaning, compliance with technical standards, and integration within the modularisation system. Additionally, flow analysis is an important aspect in selecting the proper valve to fit into the constrained module space.

Aside from the technical engineering specifications and standards used in specifying valves, many operating companies provide ergonomic (human factors engineering) requirements as well. These can sometimes create conflict with technical specifications or result in clashes in closely packed spaces. An example of such a conflict is on lever operated quarter turn ball valves. If a limit is placed on both lever length (to avoid clashes with surrounding equipment) as well as maximum force (a longer lever reduces the required force) to open the valve, then in some cases – especially if the force limit applies at maximum differential pressure – it may not be possible to achieve both requirements and a choice must be made which requirement to forego. The other option would be to employ a hand wheel and

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gearbox system, but this may create clashes if space for a gearbox was not allowed in the original layout. The sooner valve manufacturers can be engaged in order to flag any potential conflicts with specifications, the more chance there is of avoiding costly hardware changes later.

Flow media characteristics are an important factor in the valve selection analysis. The principal aspects include fluid properties, chemical reactivity or toxicity, and abrasiveness.

Valves can often dramatically change the flow, not only directly within the valve, but also downstream of the valve.

Furthermore, changes in the fluid’s properties caused by temperature or chemical changes may also dramatically alter the flow characteristics.

Pressure drop is a key criterion in valve selection. An increased pressure drop across a valve means higher costs for pressurising the fluid system. Higher pressure drops decrease a valve’s life expectancy and may even damage the rest of the fluid system. High pressure drops across open valves should be avoided. The geometry of a valve’s internal flow path is designed in a way that the pressure drop happens in the flow path that changes direction. For example, inline ball-and-plug valves have lower pressure drops than valves with angle bodies, such as needle or diaphragm valves. A measure of a valve’s potential pressure drop is the coefficient of velocity (Cv) factor. The Cv value is the flowrate a valve will allow, in gal./min. of water at ambient temperature, with a pressure drop of 1bpsi.

Flowrate and velocity are closely related to the pressure drop. Increasing the flowrate or velocity to compensate for a low Cv carries the penalty of increased pressure drop and higher costs. More power (i.e. energy or money) is required to push the extra fluid through the valve.

Turbulence is another important factor in proper valve selection. The degree of turbulence depends upon the flowrate and velocity, as well as the fluid’s viscosity, which is controlled by the fluid temperature. As the temperature increases, the viscosities of all liquids decrease, while the viscosities of all gases increase. The classic Moody diagram can be used to estimate turbulence in a fluid system.

z Special painting, inspection, and quality assurance/quality control (QA/QC) requirements can be easily achieved in a modularisation yard, either in-house or with nearby subcontractors.

Valve installation considerations

z When preheating, welding, or stress relieving, do not allow body temperatures to exceed 205˚C at any point beyond 3bin. from the weld. Use tempil sticks to check temperature.

Module assembly, when performed by a qualified company, can support condensed project schedules and deliver the expected safety, quality, and productivity that is driven by working in a more controlled environment. This controlled environment affects valve installation in a positive manner.

Benefits of installing valves in a module yard instead of a site include: z Complete system function testing is undertaken prior to shipment, allowing any faulty valve to be repaired and/or replaced.

Figure 1. Identification of vented end (VE) on a ball valve.

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Areas that need special attention include: z Valves are shipped from the factory fully open and with end protectors. They should remain in this condition until installation. They should be stored in a dry place, preferably indoors, and away from extreme cold/heat. Valves contain elastomeric seals which deteriorate with heat and age. z Valves should be installed as far as possible from sources of extreme heat, vibration, and pulsation. The piping system should be equipped with a pulsation dampener if a reciprocating pump is being used. Vibration and pulsation cause premature wear of the valve’s internal parts. z Check weld end valves carefully on soft seats prior to welding pipe into weld end. In many cases it is necessary for manufacturers to provide welded pup pieces on soft seated valves with welded ends where the pup piece is long enough to avoid heat damage to the seats. It is important that the length of these pup pieces is standardised as far as possible and communicated to the designers planning the piping layout. z Protect valve stems to avoid stem bending or damage. The valve stem and stuffing box are protected by avoiding any possible damage towards potential stuffing box leakage. z Align bolt holes between flanges to avoid any gasket damage. Order sufficient spares on valve gaskets, seals, bolts nuts, and trim. z Lift the valve so that the body supports the load. The journal and the end connection necks are suitable places to attach lifting slings. Do not lift valves by the operator hand wheel or the operator. z Fully open the plug during the installation of ball valves.

If the plug must remain in the closed position during ball valve installation, coat the exposed surfaces of the plug with grease to protect the plug from damage due to weld splatter.

z Valves are welded into final position in the piping. Cover the valve seal area (ball-to-seat area and the seat-to-end connection area) with 1 in. wide masking tape. This covering helps prevent any foreign material from becoming lodged in this area. Clean and pig the piping system before operation or pressure testing to remove any foreign material. z For uni-directional valves, care must be taken to ensure correct orientation. For some valves (e.g. check valves) the orientation is obvious as the arrow on the valve must be aligned with the flow direction. However, there are cases where orientation can be confusing. An example of this is ball valves in LNG service where a hole is drilled in one side of the ball to provide cavity relief. The side of the valve on which the cavity relieves to is referred to as the vented end (VE). The design documents (P&ID and Isometrics) usually show ‘VE’, whereas the valve body marking often indicates the directionality of the valve with an arrow – where the base of the arrow is at the VE, while the tip of the arrow is

at the other end (Figure 1). This arrow can be misinterpreted to mean flow direction (e.g. as in the case of a check valve), resulting in the valve being incorrectly installed in cases where the VE should be the downstream side (e.g. the downstream isolation valve of a relief valve to flare). Valve body markings consistent with the design documents would reduce the chance of incorrect installation.

Valve pre-commissioning and site commissioning Opportunities to improve project value continue into precommissioning and commissioning. At the module yard, to the maximum extent possible, modules should complete their testing, pre-commissioning, and preservation prior to shipment to site.

From design to shipping and everything in between, modular facilities provide real value. Modular facilities can save time and money and simplify a project by handling all aspects of the project under one roof. These aspects can include special requirements or a customised engineered solution to meet the project’s custom requirements. In a module yard, the project teams are all in the same facility, allowing for seamless communications between office and shop floor.

In a module yard, a journeyman level of performance can be achieved with minimal direction and supervision. 100% traceability is easy to attain by providing material test reports, registration numbers, certificates of conformance, statutory declarations, material safety data sheets, etc.

In a modular yard, valves are staged along with the required materials for installation, such as flanges, bolts, nuts, gaskets, seals, spares, etc. After installation, valves are required to be inspected, hydrotested (QA/QC by chart and witness), cleaned for debris or dirt, tagged with required process, and readied to ship as a single module. This process includes required documentation such as mill test reports, other testing records, installation and operational manuals, etc.

Electrical or pneumatic connections are present for motorised valves. Additional items are required, including tubing and quick connectors, electrical cable or air supply, etc. These items add up quickly and require additional time, effort, and logistics. Performing these activities at the module yard’s controlled environment is of great benefit.

To ensure flow measurement accuracy, it is essential that the pipework on the inlet and outlet is straight, is the same diameter as the valve, and has a minimum length equivalent to five diameters on the inlet and three diameters on the outlet (for example, check valves). In the case of a double regulating or commissioning valve installed near a pump outlet, the straight lengths of pipework between pump and valve inlet are a minimum of 10 diameters and are greater if possible. Much of this work can be avoided once valves are part of a modularisation package and delivered in a fabrication yard situation where wastage, quality, and safety checks can be performed in a more timely manner with better controlled costs.

Once material marshalling in a modular yard is completed, the similar valve packages can be templated. These templates support efficient production. Moreover, they also support accurate cost estimating, procurement, scheduling, and material control, and drive efficiency by bringing all of the required elements together. Progress is then easily managed and reported to the client.

Summary The design of a module provides additional complexities which challenge the traditional design and project execution methods and need to be effectively addressed. Valve design is an important aspect that needs to be considered as valves can be 15% of the overall project value. Challenges include meeting specific client requirements, operating parameters, installation location, etc. However, overcoming these challenges will deliver success and positive project results.

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15FACTS

Texas experienced temperatures as low as -18˚C in February, the coldest in over 30 years

Annual US LNG exports are projected to exceed pipeline exports in 2022

The first baseball world series began in 1903

600 trillion ft3 of natural gas reserves remain in the Permian Basin

THE USA

The bald eagle is a national symbol of the US

The first ever ship-toship LNG fuelling of an Aframax tanker was completed on 15 March 2021 outside the Port of Canaveral, Florida, by Sovcomflot and Shell

Sally Ride was the first American woman in space, launching the Challenger space shuttle in 1883

The Statue of Liberty was installed on Bedloe’s Island in 1886 The US is the third largest LNG exporter globally

Japan, South Korea, China, Turkey, and the UK were the top five destination countries for US LNG in January 2021

Since Cheniere announced the first US Gulf Coast LNG export project in 2010, more than US$60 billion has been invested in export capacity

The Empire State Building, NYC, has 102 stories The US is the third largest country in the world, covering over 9.83 million km2

The Forbes World’s Billionaires list 2020 shows that the US has 614 billionaires, the

The Grand Canyon became a UNESCO World Heritage Site in 1979 56

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