LNG Industry June 2021 issue by PalladianPublications

June 2021

ISSN 1747-1826

CONTENTS 03 Comment

JUNE 2021

29 No situation too extreme

Scott Moreland, QUADAX Valves, USA, outlines the design considerations of valves to be used in applications with extreme temperature requirements.

04 LNG news

32 It's all about 5 star quality

08 Canadian LNG's last best

Todd O’Neal and Jay Park, TMEIC Corporation, USA, provide a Japanese view of lean manufacturing methods, and explain how excellence in manufacturing can assure reliability.

chance?

Tom Choi and Chris Goncalves, Berkeley Research Group, USA, examine whether a net zero energy policy in the US will be Canadian LNG’s last best chance to scale up exports.

38 Mitigating moisture in cryogenic systems

Allen Dickey, Owens Corning, USA, explains how insulation can mitigate vapour drive and protect LNG facility function.

43 Ready for anything

Ralph H. Weiland, Optimized Gas Treating, Inc., USA, explores how to respond to changing process conditions in amine treating.

46 The power of AI

08 16 Receiving the gift that is LNG

Serafeim Katsikas, METIS Cyberspace Technology, Greece, explains how a recent commercial breakthrough adds specialised gas carrier operations to the range of vessels benefitting from AI-based data acquisition, real-time performance monitoring, and intelligent analytics solutions.

51 Balance the BOG

Maksym Kulitsa, Independent FSRU Operations Consultant, Ukraine, and David Wood, DWA Energy Limited, UK, detail the advantages of keeping boil-off gas well balanced.

56 15 facts on... Canada

Allen Yeh, CTCI Corporation, Taiwan, considers the construction of LNG receiving terminals and the factors that must be understood prior to investing in these terminals.

21 Silencing the sound und waves

Jos Oude Luttikhuis, Howden, the Netherlands, herlands, explains why gral to reduce noise selecting the right cooling fans is integral emissions in LNG plants.

25 Designed for stormy rmy seas Andy Foreman, Amarinth Ltd, UK, discusses sses the NG vessels challenges of designing pumps for FLNG stationed in some of the world’s most hostile environments.

ON THIS MONTH’S CO COVER TMEIC's Fuchu Works Factory nea TMEIC's T near Tokyo, Japan, Ja JJap aapan, a develops and manufactures power electronics e lectronics products. TM T MEIC's industrial-scale power ele TMEIC's electronics p roducts have been serving a varie products variety of industries for decades. TMEIC continues to be at the foref forefront in developing and implementing the latest technological innovations to ensure ensur that its products provide the quality and re reduced carbon footprint that its customers demand. www.tmeic.com

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LYDIA WOELLWARTH EDITOR

COMMENT

n 2020, when trying to look ahead beyond the days of the global pandemic, June 2021 for me was going to be all about Daegu, Korea, and the World Gas Conference (conducted by the International Gas Union), but alas the event is now destined for 2022. Instead this month, the International Gas Union has gifted the industry with its 12th annual World LNG Report – a source of deep insight and varied knowledge into the unusual year the industry has experienced. According to the report, LNG has had a remarkable capacity in traversing through the global crisis, achieving an increase in trade of 1.4 million t from 2019’s figure, enlarging the shipping fleet by an additional 35 new vessels, and increasing global regasification capacity by 19 million tpy – to select just several impressive feats achieved by the industry. Eloquently described by the President of the International Gas Union, Joe M. Kang, “It is because of our industry’s frontline – those who run the production plants and terminals, sail ships, manage pipelines and ports – that the lights stayed on, buildings were heated or cooled, families were able to prepare meals, medical professionals were able to treat patients, and the world was able to switch to working remotely, seamlessly.” Bringing focus to those employed in the LNG Industry and the value they provide is incredibly topical, particularly the need for companies to upskill their people. In recent conversation with Schulte Group as part of LNG Industry’s Spotlight sessions, attention was drawn to maintaining high levels of safety in the industry and the importance of ensuring seafarers are receiving specific training and development. On a similar tangent, a session with Linde Engineering explored the use of virtual reality training and the benefits of centralised knowledge to avoid the dreaded brain drain. These Spotlights, plus more, can be viewed on our website, and I strongly encourage you to take a look.

Having discussed with Schulte Group how the LNG industry keeps safety as a key priority, it was interesting to read recently about experiences at the opposite end of the scale – namely the safety of employees from multinational company Amazon. A study in the US which considered data from 2017 - 2020 discovered that Amazon workers had 5.9bserious injuries per 100 people.1 Essentially, if you work in an Amazon warehouse you are more likely to be injured than workers in other warehouses, and also the injuries will be more serious. Amazon has since stated that it invested more than US$1bbillion into workplace safety in 2020, so perhaps the company is learning that speed isn’t everything and valuing worker safety is responsible and economically beneficial. It is common knowledge that Amazon warehouses are run by a team of humans plus robots, and during the last year, the acceptance of digitalisation and reduced manual processes has become more normal within the LNG industry. The World LNG Report explains how operations have adapted to minimise human involvement, whereby cargo loading and unloading can now take place with no interaction between vessel and external crews. Moreover, relying on digital documents rather than paper-based files is also more commonplace. In fact, this isn’t solely a new shift for the LNG industry, with employees across the world now working from home and unable to access the speedy, vibrant colour printers found in office buildings, and equally unable to physically pass hard copy documents from one colleague to another. The LNG industry has proven its resilience and flexibility during the last year, and while this month I cannot write about the great plans of food and culture I had in mind for Korea, the positivity from the World LNG Report inspires confidence that 2022 will be a year to remember. 1. BBC News, ‘Amazon warehouse injuries ‘80% higher’ than competitors, report claims’.

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LNGNEWS Australia

Sparrows Group secures contract with Chevron Australia

parrows Group (Sparrows) has secured a contract with Chevron Australia for work on the Gorgon and Wheatstone natural gas facilities. Sparrows will support the safety and reliability of Chevron’s onshore and offshore lifting operations by providing inspection and maintenance services for cranes and lifting equipment. The significant award, which marks Sparrows first large contract in the Pilbara region of Western Australia, will see the company hire local personnel including lifting engineers, mechanical and electrical technicians, rope access, inspectors, and crane supervisors. Sparrows will manage the routine inspection, maintenance, and recertification of a variety of crane types located at both facilities, including offshore pedestal, fixed plant, bridge, gantry, and monorail cranes. In addition, lifting and rigging equipment for operations will be supplied, inspected, and maintained by Sparrows and delivered in accordance with Chevron’s safety requirements. The Chevron-operated Wheatstone and Gorgon facilities are two of Australia’s largest resource developments and are among the world’s largest natural gas projects. Stewart Mitchell, CEO at Sparrows, said: “The upkeep of maintenance and inspection is paramount on production facilities like these to ensure the safety of critical lifting operations. Australia is a key region for us, and it has huge potential given the importance of LNG as an energy transition fuel. Currently we are working on several LNG facilities across Australia, and we aim to expand the delivery of our specialist maintenance, repair, inspection, and NDT services to our customers here.”

Vietnam

Stena and Delta Offshore Energy announce FEED agreement

tena Power & LNG Solutions has announced it has been awarded a contract by Delta Offshore Energy (DOE) to provide front-end engineering design (FEED) for usage of Stena’s jettyless LNG transfer and regasification solutions. DOE will employ Stena’s Jettyless Floating Terminal (JFT) and Self-installing Regas Platform (SRP) to assist in providing energy to the 3200 MW power plant project to be located at Bac Lieu province in the Mekong Delta, Vietnam. A Technology License Agreement was previously reached in August 2020 for DOE to utilise Stena’s proprietary jettyless technology. Svein Hellesmark, Chief Technology Officer, Stena Power & LNG Solutions, said: “The FEED agreement is a pivotal milestone in our service provision to DOE for this important, large scale energy infrastructure project in Vietnam. Our jettyless LNG-topower technology has been created to meet demand for more flexible LNG import and export terminals, such as is required for the hugely exciting Bac Lieu LNG to Power Project.” Bobby Quintos, Managing Director of DOE added: “The JFT and the SRP are key components of our LNG-to-power solution for Bac Lieu. They allow us to position the LNG receiving terminal offshore, and thereby to minimise the project’s impact on land and on the coastline of Bac Lieu. This is a benefit of great value to the province because the coast sustains shrimp farms, mangroves, and salt beds, all of which are important to the regional economy and environment.” The JFT and SRP will be located approximately 40 km off the Vietnam shoreline. The FEED will include detailed model testing to ensure optimum performance with the environmental conditions in the Mekong Delta.

China

GTT receives order for membrane full containment LNG storage tanks

TT has received an order from its partner China Huanqiu Contracting & Engineering Co. Ltd (HQC) for the design of four very large membrane full containment LNG storage tanks. This order is part of the new co-operation agreement related to the Tianjin Nangang LNG terminal, signed in March 2021 between BGG and GTT. It completes the order for two similar

June 2021

tanks signed in June 2020 with HQC. GTT will design the tanks of all the four latest generation membrane storage tanks related to the Phase II of the project. Each tank will offer a net capacity of 220 000 m3 and will be fitted with GST® technology, developed by GTT. The tanks will be delivered in 3Q23 in the Tianjin south port Industrial Zone.

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LNGNEWS Canada

Woodside to exit Kitimat LNG

oodside has decided to exit its 50% non-operated participating interest in the proposed Kitimat LNG (KLNG) development, located in British Columbia, Canada. The exit will include the divestment or wind-up and restoration of assets, leases, and agreements covering the 480 km Pacific Trail Pipeline route and the site for the proposed LNG facility at Bish Cove. Woodside will retain a position in the Liard Basin upstream gas resource. Woodside will work with Kitimat Joint Venture participant and operator Chevron Canada to protect value during the exit. Chevron announced its plan to divest its 50% interest in KLNG in December 2019. The costs associated with the decision to exit KLNG are expected to impact 2021 net profit after tax (NPAT) by approximately US$40 - US$60 million. These costs will be excluded from underlying NPAT for the purposes of calculating the dividend. Woodside Acting CEO Meg O’Neill said exiting KLNG will allow Woodside to focus on the successful delivery of higher value opportunities in Australia and Senegal. “Following Chevron’s decision to exit KLNG and subsequent decision in March 2021 to cease funding further feasibility work, Woodside undertook a comprehensive review of our options for the project and our wider development portfolio. “The Kitimat LNG proposal was designed to develop a new source of LNG to supply Asian markets in the latter part of this decade. However, we have decided to prioritise the allocation of capital to opportunities that will deliver nearer-term shareholder value. “Woodside is focused on working towards the targeted Final Investment Decision for the Scarborough LNG development in Western Australia in the second half of 2021 and the continued successful execution of our Sangomar oil project offshore Senegal. “Retaining an upstream position in the prolific Liard Basin provides Woodside a low-cost option to investigate potential future natural gas, ammonia, and hydrogen opportunities in British Columbia,” O’Neill said.

June 2021

India

Total to supply LNG to ArcelorMittal Nippon Steel

otal and ArcelorMittal Nippon Steel (AMNS) have signed an agreement for the supply of up to 500 000 tpy of LNG until 2026. The LNG will be sourced from Total’s global portfolio and offloaded either in the Dahej or the Hazira LNG Terminal, on the West Coast of India. AMNS will use the LNG to run its steel and power plants located in Hazira, Gujarat state, India. “We are pleased to partner with AMNS and to supply the growing industrial LNG demand in India, a country that aims to more than double the share of natural gas in its energy mix by 2030 compared to today,” said Thomas Maurisse, Senior Vice President LNG at Total. “The supply of LNG will contribute to the reduction of AMNS’s carbon emissions, in line with Total’s ambition to offer its customers energy products that emit less CO2 and to support them in their own low-carbon strategies.” This agreement strengthens Total’s relationship with AMNS and contributes to the decarbonisation of India’s steel industry, which still relies heavily on coal. Total is the world’s second largest privately owned LNG player, with a global portfolio of nearly 50 million tpy by 2025 and a global market share of around 10%.

THE LNG ROUNDUP X KBR to support Nigerian FLNG project X IDB Invest to finance Invenergy and BW LNG project in El Salvador X Gas and Heat SpA signs contract with Astilleros Armon Gijon shipyard Follow us on LinkedIn to read more about the articles

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LNGNEWS Nigeria

Australia

JGC awarded pre-FEED contract for FLNG in Nigeria

INPEX forms partnership with FEnEx CRC

GC Holdings Corporation has announced that JGC Corporation, which operates the overseas engineering, procurement, and construction (EPC) business of the JGC Group, has been awarded the pre-front end engineering and design (pre-FEED) contract for a floating LNG (FLNG) facility project in the Federal Republic of Nigeria as planned by UTM Offshore Ltd, a local private company engaged primarily in crude oil sales and construction equipment leasing, and the Nigerian National Petroleum Corp. This project calls for the pre-FEED of a FLNG facility with a production capacity of 1 200 000 tpy using gas from the Yoho gas field owned by ExxonMobil and the Nigerian National Petroleum Corp. After the completion of the pre-FEED, then FEED and EPC phases are planned. This will be the first FLNG facility in Nigeria and is a milestone project. There are numerous undeveloped small scale offshore oil and gas fields not only in Nigeria but also in other African countries, with various projects planned including FLNG plants. JGC Corporation is currently executing the EPC of two FLNG facilities: for PETRONAS in Malaysia, and for Coral FLNG SA in Mozambique. Through the awarded project, the company aims to expand its business into the African region, which is expected to grow in the future, and contribute to the further development of industry and infrastructure.

apanese energy company INPEX has signed an agreement with the Future Energy Exports Co-operative Research Centre (FEnEx CRC) – the newest industry partner to join the world class research and development of new technologies that will lower the cost and carbon emissions of energy production in Australia. The partnership with FEnEx CRC involves research funding of AUS$1.5 million, supporting studies on efficiency of LNG production value chains, digital technologies, and new hydrogen energy and export to market. INPEX President Director Australia Hitoshi Okawa said he was pleased to partner with FEnEx CRC to undertake studies to research and develop innovative solutions for producing clean and sustainable energy in Australia with important benefits for energy importers, including Japan. “As a proud member of the Australian business community for more than 30 years and the operator of Ichthys LNG, INPEX is pleased to support high value research and development to lower our carbon footprint, consistent with the Paris Agreement,” said Mr Okawa. FEnEx CRC research is supported by a grant from the Commonwealth Department of Industry, Science, Energy and Resources through the Co-operative Research Centres programme. The CRC will champion industry-led research, education and training to strengthen the sustainability of the LNG sector and develop a complementary hydrogen export industry in Australia.

23 - 25 August 2021

13 - 16 September 2021

21 - 23 September 2021

Canada Gas & LNG Exhibition & Conference 2021

Gastech Exhibition & Conference 2021

Global Energy Show

Vancouver, Canada

Singapore

www.globalenergyshow.com

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04 - 06 October 2021

15 - 18 November 2021

30 November - 01 December 2021

ILTA

ADIPEC

Houston, USA

Abu Dhabi, UAE

21st World LNG Summit & Awards Evening

https://ilta2021.ilta.org

www.adipec.com

Rome, Italy

Alberta, Canada

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June 2021

Tom Choi and Chris Goncalves, Berkeley Research Group, USA, examine whether a net zero energy policy in the US will be Canadian LNG’s last best chance to scale up exports.

he Canadian natural gas industry faces the dilemma that its one export customer, the US, has diminished need of its supplies as US domestic shale gas production continues to surge. Despite rapidly growing US gas demand and rising volumes of US pipeline and LNG exports, US imports of Canadian gas have declined sharply during the past decade. Due to diminished demand, Canadian prices have languished with the benchmark AECO-C Hub price often trading well below US$2/million Btu, and at a steep discount to the US benchmark Henry Hub. The obvious solution for Canadian gas producers is to develop access to alternative markets, which for Canada means LNG. With declining demand from its one neighbour, the only hope for Canada to monetise its vast natural gas resources is to convert it to LNG for shipment to foreign markets that offer much higher prices. Led by ravenous appetite for energy in China, India, and Southeast Asia, global LNG demand has grown approximately 50% over the past decade. To be sure, Canada has formidable competition. During the last decade, several other countries with sufficient gas supplies to develop world-scale LNG plants have done so to seize the opportunity to capture a piece of the growing and lucrative LNG market. Australia has emerged as a global LNG export leader by developing LNG terminals in Queensland, as well as further development in the Northwest Shelf. The US has six LNG export terminals already fully operational, with two more under construction. Russia developed LNG liquefaction capacity in the Arctic region to complement its Sakhalin terminals so that Russian

LNG can competitively reach both European and Asian markets. Australia and the US are now challenging Qatar to be the top LNG exporter, with Russia aspiring to join these industry leaders. Not to be outdone, Qatar announced a major expansion of its massive LNG export capacity to firmly entrench its primacy in global LNG. The tiny country has a built-in competitive advantage based upon its access to the North Field – the world’s largest non-associated natural gas field. Meanwhile, numerous Canadian LNG projects have struggled to reach Final Investment Decision (FID) and Canada has yet to export any LNG. In efforts to connect LNG terminal locations to gas-producing areas, numerous Canadian LNG developers have been hamstrung by national and provincial regulations, negotiations with First Nations tribal groups, and infrastructure challenges. While Canada has an extensive natural gas infrastructure system, there is limited pipeline capacity from the gas producing areas to the planned coastal LNG sites. Expansion of the pipeline system would require clearing the daunting and costly challenge of crossing the Rocky Mountains which separates the producing areas from the British Columbia coastline. Thus far, only LNG Canada has managed to achieve FID. Canadian LNG’s lack of success comes despite Canada being strategically well positioned for LNG exports to Pacific Basin markets. It offers all the prerequisites to develop a successful LNG project: abundant low-cost natural gas supply, available infrastructure (not just gas infrastructure, but also roads, electricity, and accommodations), established regulatory structure, access to

skilled labour, and political stability. The importance of the last point is underscored by the recent troubles that Total has encountered in Mozambique. Above all, Canada is blessed with prolific, low-cost, natural gas-rich formations, such as the Montney, Duvernay, and Horn River basins. Including all types of resources, the Canada Energy

Figure 1. Estimated resource potential by formation. Sources: Canada Energy Regulator and US Geological Survey.

Figure 2. Canadian natural gas exports and imports. Source: BRG analysis and US Energy Information Administration (EIA).

Figure 3. Canadian gas export revenues. Source: BRG analysis and US EIA.

June 2021

Regulator (CER) estimates that Canada holds almost 1400btrillionbft3 of marketable gas. Natural gas producers in Canada are sitting on massive resources that they cannot monetise because low demand has depressed Canadian gas prices to the point that production is economically difficult to justify. One exception is the Montney formation, located in northeast British Columbia, which has experienced explosive growth during the past decade and now comprises almost half of the total natural gas production in Canada. A combination of tight gas and shale, the Montney formation is estimated by the CER to hold 567 trillion ft3 marketable gas, equivalent to approximately 100 years’ worth of supply at Canada’s current production rate. The significant resource volume of the Montney dwarfs the much better-known Marcellus/ Utica and Haynesville/Bossier formations in the US (Figure 1). Furthermore, Western Canada has a significant geographic advantage to Asian markets as compared to the US Gulf Coast (USGC). For example, the shipping voyage from Kitimat, British Columbia to Shanghai, China takes approximately 10 days less than it does from the USGC, even using the most efficient route through the Panama Canal. The time savings translates to not only reduced shipping costs but also increased ability to respond to the region’s dynamic short-term market needs. In fact, by the time a tanker from the USGC reached Asia to meet a supply shortage, the need and opportunity might have dissipated. For example, Asia was hit with a colder than average winter this past January that shot up prices well over US$20/million Btu for a brief period. Canadian LNG could respond to such Asian market needs and sales opportunities more quickly than US LNG supplies. The urgency for developing LNG export terminals for Canadian producers is clear from examining Canadian exports to the US. Canada continues to be a net natural gas exporter to the US, but the volumes are on a downward trajectory, as shown in Figure 2. While Canadian gas exports declined by 2.4% per annum during the decade from 2010 to 2020, Canadian imports increased by 1.8% per annum. Not only is less Canadian gas needed in the US, but some regions of Canada have imported more US gas and displaced Canadian gas. For example, sharply rising gas production from the Marcellus and Utica formations in the Eastern US has reversed the pipeline flow and reached Canadian markets. The result is that net Canadian exports have declined steeply to the tune of 4.1% per annum. Compounding the pain, natural gas prices have simultaneously plummeted, producing a precipitous drop in Canadian gas export revenues, which fell by 10.7% per annum from 2010 to 2020, as shown in Figure 3. Of course, 2020 was a particularly painful year with the outbreak of the coronavirus, but it only continued the downward trend of the previous years. Sharply higher prices in 2021, including the JKM spiking to an all-time high in January, indicate that the market is finally emerging from an extended period of market oversupply and price malaise. The price recovery could be attributed to some countries’ initial rebound from the coronavirus pandemic, as well as the resiliency of natural gas and LNG demand during the pandemic, and supply impacts wrought by the pandemic such as substantial delay in the FID and COD scheduled for new LNG projects, upstream production declines, and increased capital discipline for oil and gas producers. However, the price rebound may prove fleeting due to the massive new LNG export on the horizon. For example, Qatar, the global leader in LNG, is poised to reassert its dominance by expanding its export capacity by 33 million tpy and also is partnering in the Golden Pass LNG terminal, which will add another 16 million tpy.

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Is it too late for Canada? Has the window closed? Although late to the party, Canada may soon be presented with its last best chance to scale up LNG exports in the form of US net zero energy policies. The new Biden administration fulfilled a campaign promise on day one of its administration by rejoining the Paris Agreement, signalling the beginning of an aggressive ‘all of government’ approach to tackling climate change imperatives. Among other policies, the new US administration is promoting a policy for net zero power generation by 2035, which over the coming few decades would gradually eliminate the use of natural gas for power generation.

To analyse implications of US net zero policy on Canadian gas markets, BRG used its LNG Horizon™ model to forecast global natural gas and LNG markets under three scenarios: z Base Case: A business-as-usual scenario, which assumes only those global energy and environment policies that have already been adopted (e.g. the European Green Deal). z US Net Zero: The US alone adopts a net zero policy for electricity generation by 2035. z Global Net Zero: The US policy sparks intensified climate efforts in Europe and adoption of more stringent climate policies in the major Asian economies, such as those described in the IEA’s Sustainable Development scenario.

LNG Horizon is well suited for this analysis because it provides detailed representations of the US and Canadian markets, including supply basins, gas processing, pipeline infrastructure, LNG terminals, and demand regions to forecast prices and volumes. Most importantly for this analysis, the model can project infrastructure capacity additions given the capital costs, variable operating costs, and projected prices. Table 1 shows the implied compounded annual growth rates (CAGR) for demand by region under the stated policies, which was used in BRG’s Base Case, and the sustainable development scenario, which is used in the Global Net Zero case. The sustainable development scenario lowers global gas demand by approximately 3 trillion ft3 in 2030 and 8.5btrillionbft3 by 2040, compared to the stated policy scenario. BRG notes that in the sustainable development scenario, most countries reduce their Figure 4. Forecast of net Canadian exports to the US. Source: BRG LNG Horizon™ forecast and EIA. natural gas consumption, but India increases consumption over the current decade as natural gas displaces coal and other more carbon intensive fuels. As shown in Figure 4 for the Base Case, Canadian net exports to the US continue their downward spiral over the next decade, falling 50% from 2016 to almost 1 trillion ft3. The decline is steady, with only a minor rebound in the later part of this decade as new US LNG export terminals, including Golden Pass and Calcasieu Pass, come into operation. Figure 5 shows that in the Base Case, North American LNG export volumes are dominated by US LNG exporters. Canadian LNG exports are forecast to eventually enter the market in 2025 when LNG Canada’s 1.8 billion ft3/d of capacity becomes operational. The export volumes reach 5.8 billion ft3/d by 2032, with 4.0 billion ft3/d of additional capacity forecast to be economically viable. The forecast capacity additions indicate that two additional large scale LNG terminals would be economic to build in Western Canada, although the Canadian LNG exports are Figure 5. North American LNG exports. Source: BRG LNG Horizon forecast. still dwarfed by the projected 14.2bbillion ft3/d of US LNG exports. A US net zero policy could significantly enhance the Table 1. Gas demand growth rates (CAGR) by scenario. Source: BRG analysis of IEA 2020 prospects for Canadian LNG World Energy Outlook scenarios exports. The gradual elimination of US natural gas consumption Region Stated policies Sustainable development for power generation will cause 2020 - 2025 2025 - 2030 2030 - 2040 2020 - 2025 2025 - 2030 2030 - 2040 North American natural gas prices to drop, making US and EU 1.2% -1.2% -1.3% 0.6% -4.2% -4.2% Canadian LNG exports more cost-competitive in global Japan -2.0% -1.6% 0.3% -1.0% 0.0% -2.8% markets. As shown in Figure 6, China 4.6% 3.1% 2.5% 3.1% 2.4% 1.4% LNG Horizon forecasts US (Henry Hub) and Canadian India 8.5% 5.6% 4.4% 8.7% 7.3% 3.9% (Alberta) prices to both

June 2021

decrease, but the impact is more acute in the US because it is directly affected by the natural gas demand decline. Alberta prices decline by a lesser amount because they are already depressed in the Base Case and Canada is only indirectly affected by the US policy and demand reductions. Overall, the North

Figure 6. Price impact from US Net Zero scenario. Source: BRG LNG Horizon forecast.

Figure 7. Impact of US Net Zero case on North American LNG export capacity. Source: BRG LNG Horizon forecast.

American price declines make US LNG more competitive in Europe and Canadian LNG more competitive in Asia. In the US Net Zero case, North American LNG exports are more competitive in global markets and LNG Horizon indicates market demand for additional LNG liquefaction capacity in both Canada and the US, as shown in Figure 6. The total North America LNG export volume increase represents an approximately 15% increase compared to the Base Case. Interestingly, the first beneficiary is Canada, which adds 0.8bbillion ft3/d of capacity, bringing Canada’s total LNG export capacity up to 6.6 billion ft3/d. US capacity expansion follows later, growing by an additional 3bbillion ft3/d in 2032 because of the net zero policy. Canadian LNG projects on the west coast have an advantage to premier markets in Asia while US Gulf Coast LNG projects have an advantage to Europe and fast growing Latin American markets. Which projects eventually come to fruition will depend on factors such as marketing ability, personal relationships, and terms developers are willing to accept, as well as the economic merit of the projects. Therefore, the most pertinent number is the total North American LNG exports because it represents how much volume is projected to be available for the various North American LNG projects. But what if the US does not act alone on net zero policies and rather sets off a wave of global commitments to comparable net zero polices among all the world’s major economies and gas and LNG consumers? This question is addressed in the Global Net Zero scenario based upon the IEA’s Sustainable Development scenario, which assumes Europe and the major Asian countries all pursue net zero emissions for the power sector by 2035 and net zero emissions for the overall economy by 2050. Under this scenario, global gas markets begin to shrink albeit inconsistently over time and by regions. The impact of this scenario on North American LNG exports is a decline of 1.5bbillion ft3/d by 2032, with most of the decrease hitting Canadian LNG exports, as shown in Figure 8. Whereas in the Base Case, 4.0 billion ft3/d of Canadian greenfield LNG capacity was built; with the global natural gas demand decline in the Global Net Zero scenario, only 2.5 billion ft3/d of Canadian LNG capacity is added. In comparison, US LNG exports are minimally affected because most of the US volumes come from existing and projected brownfield terminal expansions, which are less costly than greenfield projects. The results emphasise the point that greenfield LNG projects are the marginal sources of global LNG supply and thus highly sensitive to market conditions.

Conclusion In summary, a stringent US net zero policy would boost the prospects for Canadian LNG by lowering feed gas prices and enhancing the competitiveness of Canadian exports in the Asian markets. However, if Asian countries also aggressively pursue net zero type policies over the coming decades, the lower demand could significantly limit development of the greenfield Canadian LNG projects. In other words, an aggressive US net zero policy that runs in advance of Asian market commitments could be Canadian LNG’s last best chance to capture a significant share of the Asian LNG market, but that chance could also be compromised by an accelerated global push for net zero policies.

Figure 8. Impact of Global Net Zero case on North American LNG export capacity. Source: BRG LNG Horizon forecast.

June 2021

Note The views and opinions expressed in this article are those of the authors and do not necessarily reflect the opinions, position, or policy of Berkeley Research Group, LLC or its other employees and affiliates.

Allen Yeh, CTCI Corporation, Taiwan, considers the construction of LNG receiving terminals and the factors that must be understood prior to investing in these terminals.

s the world is committed to reducing carbon emissions and curbing global warming, Asian countries have responded to carbon reduction and are moving towards net-zero carbon emission. Replacing traditional coal-fired power generation with gas-fired power plants is an important policy for many countries to actively promote the energy transition. Both public sectors and private enterprises have invested in the construction of LNG receiving terminals to meet the growing demand for gas supply. According to the International Energy Agency (IEA), the number of countries with LNG receiving terminals in the world has increased from nine in 2000 to 42 in 2020, and the increase is mainly concentrated in Asian countries such as Japan, China, South Korea, India, and Taiwan. Other countries like Vietnam, Indonesia, the Philippines, and Bangladesh are also committed to achieving their development plans of LNG receiving terminals.

LNG receiving terminal work The construction of a complete LNG receiving terminal mainly includes marine works, storage tanks, regasification, buildings, and related facilities. It takes approximately five to sevenbyears from carrying out an environmental impact assessment and obtaining government construction permits to the completion of the engineering, procurement, construction, and commissioning works. Activities at an LNG receiving terminal can be divided into four main stages: berthing of ships and unloading of cargoes; storage of LNG in cryogenic tanks; LNG regasification; and send-out of gas into the transmission grid.

Marine work An LNG jetty is a construction work projecting pipelines from an onshore terminal out over water. It often consists of piles, a trestle and topsides, pipelines, access road, unloading/loading arms, and breasting and mooring dolphins. The process of designing and constructing a jetty can be time-consuming, costly, and requires intervention in both onshore and marine environments. A jetty also serves as a connection that enables transfer of LNG between a berthed ship and the onshore terminal. Based on economic and fire-fighting considerations, LNG terminals generally adopt breasting and mooring dolphin types of jetties, which are connected to onshore facilities by trestles. The length of the trestle may vary from tens of metres to several kilometres according to local conditions, such as port planning, seabed depth, environmental protection requirements, etc. The construction of the long span trestle may use a customised equipment called a cantilever bridge – this equipment is capable of shifting the work front forwards over the already constructed trestle part on a span by span approach, without suffering from impacts of water depth and wave conditions. For an LNG receiving terminal that uses seawater for LNG regasification (such as ORV and IFV facilities), seawater inlet/ outfall (SW I/O) is also one of the important tasks of the marine works, especially the design and construction of the inlet

pit. It is worth noting that some projects must use the shield construction method due to environmental protection requirements. Although this method can reduce the impact on the environment, the cost and schedule risks are much higher than that of traditional open-cut construction, and the construction machinery is relatively complicated. As seawater is corrosive to metals, RC and FRP materials are used for seawater conveying pipes.

Tank An LNG storage tank is a specialised type of storage tank used to store LNG at the very low temperature of -162˚C (-260˚F). Many newly-built or under construction LNG receiving terminals adopt an above-ground type of full containment storage tank, which is composed of 9% nickel steel plate inner wall and pre-stressed concrete (PC) outer wall. Due to the height of the LNG storage tank, the PC outer wall is constructed with system forms, such as slip form or jump form. Subject to the code/regulation requirements to knuckle plate fabrication, currently the common storage tank capacities for double dome roof type are from 180b000b-b230b000 m3. The suspended roof type provides more flexibilities in the range of capacities, including the ongoing two 250 000 m3 tanks of Thailand PTTLNG and the completed 260 000 m3 tank of Singapore LNG (SLNG). Roof air raising is one of the most critical tasks in the construction of LNG storage tanks. It is an irreversible procedure because re-lifting may cause the sealing material

metal mesh to break or rupture, as well as risk of leaking air pressure, resulting in an imbalance of the storage tank roof and becoming stuck on the pre-stressed concrete wall. In normal practice, contractors will arrange roof pre-air-raising and official roof air raising. Weather conditions, especially wind speed, are also crucial and must be considered during roof air raising.

Regasification facilities There are different types of regasification vaporisers, such as open rack vaporiser (ORV), shell and tube vaporiser (STV), submerged combustion vaporiser (SCV), and intermediate fluid vaporiser (IFV). The choice of vaporiser will vary according to the characteristics of the project. Primary considerations include plant conditions, normal and peak-shaving gas supply requirements, local climate, seawater temperature and cleanliness, energy efficiency, maintenance requirements, and costs. To save energy and minimise greenhouse gas emissions, it is ideal to use ‘free heat’ from the ambient air or seawater when selecting the type of vaporiser for an LNG receiving terminal. Considering operation and maintenance costs, in areas where seawater is very clean, ORVs are generally selected for base load operations; otherwise, IFVs will be adopted. SCVs are reserved for peak gas supplies and serve as back-up vaporisers when ORVs or IFVs are under maintenance. Integrating the inlets/outfalls of the LNG receiving terminal with the nearby combined cycle power plant (CCPP) can help improve energy efficiency and reduce each other’s operating costs. The idea is that seawater can be used as a heat source of the LNG vaporiser in the LNG receiving terminal as well as a cold source for condensing the steam discharged from the steam turbine in the combined cycle power plant.

Buildings

Figure 1. Roof air raising in CPC’s third LNG receiving terminal, Taiwan. Image courtesy of CPC Corporation.

Buildings (including administration, maintenance, substation, control room, guard house, etc.) are the common facilities for an LNG receiving terminal. However, Thailand’s PTTLNG adopted a different strategy by transforming the administration building of Nong Fab Terminal from a closed plant facility to a public education centre, allowing ordinary citizens and students to take electric vehicle tours and visit green buildings, rooftop solar power generation facilities, and wind power generation facilities. This helps educate people about the significance of this energy source, the production process, and the benefit of LNG. The administration area consists of an administration building, two support buildings, and large landscape areas. The administration area features an educational zone, exhibition hall, an in-plant power generation facility (wind turbine and solar cell) together with an LNG cold energy utilisation system which can generate and send the cold air – the byproduct collected from the regasification process – into the climatic dome in order to maintain the required ecological environment for the winter flowers inside.

Cold energy utilisation Figure 2. First berthing after expansion of the Petronet Kochi LNG receiving terminal, India.

June 2021

During the process of LNG regasification, a large amount of cold energy will be released. To some degree, a considerable amount of cold energy will be available when importing LNG. Possible cold energy applications in LNG receiving terminals

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include supply of air conditioning (HVAC) for buildings inside the terminal, cold energy power generation, intake air cooling for in-plant power generation (i.e. GTG) and/or nearby combined cycle power plants (CCPP) to improve their performance efficiency. The cold energy can also provide adjacent areas an integrated utilisation of resources, such as air separation to produce liquid nitrogen and liquid oxygen, cold storage warehouse, and low temperature fishery, etc. Compared to other applications, the application of air separation has more economic value. However, initially most of the existing LNG receiving terminals were set up to provide stable supply of natural gas rather than cold energy application purposes. Insufficient demand from surrounding industries, constraints on land use, insufficient economic benefits from application projects, and unclear policy directions are the causes that make promotion of cold energy utilisation difficult. It will be easier for new LNG receiving terminals to reap the benefits of cold energy utilisation if potential applications are taken into consideration during the planning stage, together with co-ordinated government policies and industrial chain participation. It is worth noting that LNG’s cold energy utilisation also faces many restrictions, for example: the length of LNG pipelines must be controlled within 1 - 2 km due to safety considerations and regional restrictions; the stability of cold energy supply could be impacted by the LNG demand in different seasons; the available piping insulation and cold storage technology.

LNG receiving terminal expansion work Considering factors such as high construction cost, constructability, shipping, and environmental impacts, the overall maritime construction works of LNG receiving terminals are usually completed during the newly-built period. However, the owners would reserve enough space in accordance with their investment plans for further expansion of LNG storage tanks and regasification facilities stage by stage. In contrast to newly-built LNG receiving terminals, the expansion work pays more attention to the integration between expanded facilities and existing facilities, especially the control rooms, power supplies, fire protection, isolation and leakage of mechanical works, and location of electrical and instrument (E&I) tie-in points. The system and equipment capacity of existing terminals also needs to be verified.

Conclusion In the long-term, Asia’s growing LNG demand forecast will motivate existing import countries as well as newcomers to increase their capacity, either through expansion or building new LNG receiving terminals. Although LNG receiving terminals are not as complicated as liquefaction terminals in terms of engineering complexity, investors nevertheless must think carefully about some important issues before investing in LNG receiving terminal constructions. These include: ensuring the safety of terminal construction; reducing environmental impact from construction activities; gaining the support of environmental protection groups; obtaining government permits; promoting cold energy utilisation via the synergy of government policies as well as industrial participation; and allowing facility access to the public to get their support on clean energy.

Jos Oude Luttikhuis, Howden, the Netherlands, explains why selecting the right cooling fans is integral to reduce noise emissions in LNG plants.

s the world gears up for a future of lower carbon energy, gas, and in particular LNG, is to play a vital role within the overall energy mix. The production of LNG, like many other processes within the energy field, requires substantial investment in facilities to make this happen. Operators faced with the development and construction of such facilities have a huge number of decisions to make, from liquefaction process technology and design to intricate considerations over the impact on the environment within which the plant will be located. One such aspect relates to noise emissions. As with any industrial facility, there are regulations that are in place to ensure that the impact on the well-being of on-site personnel is controlled to an acceptable level, as well as reducing the

impact on the wider environment and potential communities in the vicinity of the plant. The noise regulations within the plant (termed near field) can commonly specify levels of below 85bdBA. There can be a range of mitigating solutions to reduce the noise as well as provide personnel with suitable protective equipment. The regulations for noise levels beyond the plant (termed far field) can be much more stringent, targeting averages below 50 dBA, with factors such as proximity to sensitive areas increasing the demand for controls. LNG trains generate substantial levels of noise and due to the large array of equipment, there are multiple sources which contribute to the overall emissions. While much of the equipment is situated within enclosed buildings and therefore can be addressed through noise mitigation solutions, the heat rejection cycle typically involves large heat exchangers which

Table 1. Comparison of fan model noise performance

Standard (E series)

Low noise (E Series)

Very low noise (E series)

Ultra low noise (SX series)

Solidity = 0.18

Solidity = 0.38

Solidity = 0.49

Solidity = 0.71

RPM = 246

RPM = 192

RPM = 179

Tip speed = 55 m/s

Tip speed = 43 m/s

Tip speed = 40 m/s

Tip speed = 39 m/s

Sound (PWL) = 100.5 dBA

Sound (PWL) = 93.6 dBA

Sound (PWL) = 90.7 dBA

Sound (PWL) = 84 dBA

Gain vs standard 6.9 dBA

Gain vs standard 9.8 dBA

Gain vs standard 16.5 dBA

–

are located externally. This is therefore often the top contributor to far field noise.

Addressing process cooling noise

Figure 1. SX cooling fans undergoing tests.

Each train will generate significant amounts of heat from the liquefaction cycle, which needs to be transferred to atmosphere to enable the safe ongoing operation of the process. The selected method is mostly either to use water-cooled cooling towers or air-cooled heat exchangers (ACHE). Where an ACHE is selected, it is often based on its relative simplicity with limited additional infrastructure, despite a potentially overall lower efficiency and larger footprint. Cooling towers offer improved cooling efficiency and a smaller footprint where the complexity is accepted and water resources are adequate. Due to the levels of heat rejection required, regardless of the selected process cooling solution, cooling fans are likely to be used in substantial numbers. There may be hundreds of fans drawing the hot air from the system, each of which can generate noise emissions that when multiplied, presents operators and their consultant engineers with a significant issue in regards to compliance with environmental regulations.

Not all fans are created equal

Figure 2. SX series fan installed on-site.

June 2021

There are a range of cooling fans available on the market. A standard cooling fan can emit over 100 dBA when operating at full speed. The contributors to fan noise are tip speed, aerodynamic power, the diameter of the fan, the geometrical shape of the blade, and other variables from the fan inlet/outlet to obstacles and drive noise. In order to achieve lower noise emissions, the fan design focuses on geometrical shape and the potential to achieve a lower tip speed. Potential geometrical profiles are linked to the manufacturing process as much as the design itself. Many standard fans on offer are manufactured from aluminium, which brings restrictions to the design possibilities. At Howden, the blades are manufactured from fibreglass reinforced polyester (FRP), with layers being built up within specified moulds.

This material and approach gives full flexibility for the design as it involves virtually no restriction in shape. The design can therefore focus on creating a blade that meets the precise shape required to maximise efficient performance as well as minimising noise output. The characteristics that are sought for a high performance fan blade are a non-symmetrical air foil with a variable chord and twist. The twist enables the blade to compensate for the peripheral change in speed from the blade tip to the wide chord, and fans without this can be as much as 50% lower in terms of static efficiency. The FRP material carries additional value as, being a relatively low weight material, the blade can be produced to concentrate strength into the area where it is needed most, for example the neck and shoulder of blades; non-structural parts such as the tip can have less material applied to carry less weight. The material also offers impressive damping of mechanical vibrations, especially when compared to aluminium (up to six times). In summary, the use of moulded FRP brings real advantages to cooling system operators in lower power consumption with related lower running costs, as well as reliability and longevity of the fan. Specifically, within the context of noise reduction, fans produced from moulded FRP are able to have a thick aero foil. It is this design aspect which translates to the ability to generate the required pressure differential at low speed. Low fan speed is the goal for operators seeking lower noise.

Noise reduction options To illustrate the performance step-up from a standard fan to lower noise alternatives, the Howden range can be

described focusing on the different solidity of blade and the potential tip speed. The diagram in Table 1 shows four fans operating at a given duty point – this is based on a fan with a 14bftb(4.2bm)bdia., an air flow of 100 m3/s, and pressure of 170bPa. By changing the profile and adding to the solidity of the blade through the manufacturing process described, the tip speed can be reduced while delivering the same cooling performance. This has a substantial impact on the noise level, gaining reductions of up to 16.5 dBA vs the standard fan.

Additional selection factors Noise can often be the driving consideration when selecting fans, however other factors will play a part such as the cooling system footprint and operating costs. Addressing the noise requirement can also bring benefits in both of these areas. Low noise impellers can reduce the cooler size while maintaining the same cooling capacity. This is possible due to the higher static pressure and increased flow per fan. As a result, fewer fans are needed to meet the target cooling duty. The combination of fewer fans of a high efficiency design contributes to lower lifetime operating costs both in terms of less power consumption and less maintenance. When it comes to options, Howden is able to provide a high level of flexibility even within the specific series designated as low or ultra-low noise. Each can be configured with different numbers of blades of varying sizes to meet the desired performance (noise and efficiency). Increased protection for the blades can be added through

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special coatings and leading edge protection, particularly in the case of wet cooling systems. These additions give greater assurance of long-term, reliable operation, minimising future maintenance.

Case from a large LNG liquefaction plant The Golden Pass LNG plant is a US$10 billion project owned by Qatar Petroleum and ExxonMobil. It is set to make the existing terminal in Sabine Pass, Texas, US, a premier LNG exporter. The plant will operate three liquefaction trains to provide an annual output of 15.6bmillion t of LNG. Environmental interests around the site are very important, with the operator (ExxonMobil) particularly concerned that the noise levels are kept within stringent boundaries (set by the regulator FERC at 55bdBA Ldn – day night sound level). The site requires a large number of coolers and condensers to support the process and power cooling. The appointed EPC (Chiyoda) was looking for solutions from the cooling system providers, which were able to meet this high specification. As one of the industry leaders in the design and supply of low noise cooling fans, a number of the bidding cooler suppliers turned to Howden for technical options. Howden was able to utilise its in-depth technical knowledge to propose multiple variants able to meet the design specification. The successful OEM, Dasan Thermal Solutions (DTS) of Korea, is to supply a cooling system based on its ACHE technology comprising 17 types of coolers and condensers. Once complete, the ACHE system will incorporate more than

600 cooling fans mainly in induced draught configuration. The highest number of fans will be employed within the propane condenser – a total of 288bfans for the three trains. The fans selected are variants of the SX model with sizes ranging from 5 - 14 ft in dia. (approximately 1.5 - 4.2 m). DTS had broken down the noise requirements to each of the 17btypes ranging from approximately 72 dB power level for the smaller fans to approximately 80 dB for the larger ones. With three and four bladed SX fans, Howden was able to satisfy all of the requirements and even underbid in some cases. As part of its product evaluation, DTS required noise tests to enable performance comparisons. Howden was able to leverage its global network to attend the test in Korea and provide support to the DTS engineers, as well as explain the performance of the fan to technical managers of Chiyoda. This involved representatives from Howden’s centre of excellence in the Netherlands and from its businesses in China, Korea, and Japan.

Conclusion Process cooling is an integral part of the LNG production process and the resulting noise pollution is one of many issues that need to be addressed by engineers. As fans within such systems are large contributors to noise, tackling the issue at source can be an advantageous approach. Fan design, manufacturing methods, and materials are key to meeting environmental regulations without sacrificing performance; in fact low noise fans are able to deliver benefits to the whole system design and ongoing efficient operation.

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Andy Foreman, Amarinth Ltd, UK, discusses the challenges of designing pumps for FLNG vessels stationed in some of the world’s most hostile environments.

espite the short-term reduction in energy demand caused by the COVID-19 pandemic, the US Energy Information Administration (EIA) predicts that global energy demand will rebound to its pre-crisis level in early 2023 whilst also taking advantage of cleaner technologies than traditional coal and oil. As the global demand for energy grows again, natural gas, the cleanest burning fossil fuel, will play a vital role in balancing economic growth and environmental responsibilities, with a projected growth in demand for LNG of 30% by 2040. However, the economics of onshore LNG plants is becoming increasingly challenged as suitable gas fields have become more remote and project infrastructure has become difficult to construct, resulting in high costs and high risk. A huge proportion of the world’s natural gas reserves are also located offshore in under-developed or remote regions of the globe. In recent years, with the global demand for LNG

continuing to increase, floating LNG (FLNG) facilities have been commissioned enabling companies to start to take advantage of previously unreachable gas fields.

A self-contained LNG plant on a ship FLNG vessels are entire facilities that handle the offshore storage, processing, and transport of LNG. Using the same systems as land-based LNG plants, these vessels can process gas closer to the source, treating and liquefying it (which involves supercooling the gas to -160˚C to turn it into a liquid), without needing miles of pipelines to transport the gas to the nearest coastal facility. The liquefied gas is stored in tanks on the vessel until it is transferred to LNG carriers for transport to processing plants. FLNGs open the potential to exploit gas fields that can be miles out to sea and which would previously have been too difficult or costly to take advantage of.

Designing and building FLNG vessels raises numerous challenges. For the system to be viable, the vessel must include all the same facilities as a land-based LNG plant. Although the vessels are some of the largest in the world, this requires packaging the plant and equipment into a space one-quarter of the size of land-based plants. To operate in the harsh environment of the open sea, the process modules aboard the vessels require reliable, robust pumping solutions

to maximise the efficiency and safety of the vessel, its equipment, and the LNG processes. Amarinth is at the forefront of the design and manufacture of centrifugal pumps for the oil and gas industry, including for many of the world’s FPSO vessels. The company has also established itself as one of the industry’s go-to experts for centrifugal pumps that can deliver the duties demanded by the LNG industry, both onshore and offshore. The company is now using all its experience and expertise to equip the latest generation of FLNG vessels with robust, reliable pumping solutions.

Harsh environment and limited space

Figure 1. Amarinth API 610 VS4 vertical pump used on several topside processes.

Figure 2. Bespoke strengthened pump casings from Amarinth.

The pumps onboard a FLNG vessel must withstand an extremely harsh environment, from the composition of the fluids, extremely low temperatures, corrosive seawater, highly abrasive sand, and all aboard a vessel that is constantly in motion from wind and waves. Moreover, the pumps must operate reliably 24 hours a day, requiring minimal downtime for scheduled maintenance. With space at a premium aboard a FLNG vessel, particularly headroom, one of the key challenges is that pumps must be designed to operate in a low net positive suction head (NPSH) available environment otherwise they will be prone to cavitation, seriously shortening their working life. Many of the pumps must also work reliably despite being placed under significant and unusual loadings due to the motion of the ship and space constraints, and it is not unusual to have specifications that are above and beyond that set out in API 610. However, being aboard a vessel, any bespoke design must be achieved whilst keeping the weight of the pumps to a minimum. Furthermore, despite these considerable design challenges, the target time to fit out a vessel is often less than 52 weeks from start to finish, with the time given over to the procurement of equipment as little as 20 weeks. This places immense pressure on the pump manufacturer to align the design and delivery of the pumps to meet the critical build schedule of the FLNG and its process packages as any delay would prove extremely costly. With a lifespan of over 20 years, it is planned that FLNG vessels will be redeployed to other fields once they have depleted a gas source, reducing the need for further construction, and so all equipment must continue to operate reliably and optimally over this lifetime regardless of the vessel’s location. Although many of the challenges apply to all FLNG vessels, to highlight some of the solutions in more detail, two FLNG projects Amarinth has recently supplied pumps to – Coral South and Tortue Ahmeyim – are detailed next.

Coral South FLNG

Figure 3. Amarinth pump impeller designed for low NPSH(A) duties.

June 2021

Amarinth engineers tackled several of the FLNG challenges head-on for the Coral South field, the first ultra-deepwater FLNG facility in the world. This is the first project in the development of the considerable gas resources discovered by Eni in Area 4 of the Rovuma Basin, off the coast of Mozambique, more than 2 km (1.24 miles) beneath the ocean’s surface. The Coral field contains approximately 450bbillionbm3 (16 trillion ft3) of gas and the mammoth FLNG

vessel, which has a 432 m long × 66 m wide hull and weighs in at approximately 140 000 t, will have the capacity to process 3.4bmillion tpy of LNG. A total of nine API 610 OH2 pumps with Plan 53B seal support systems were required for a MEG regeneration unit and a further four pumps for the desanding unit onboard the FLNG vessel. In both cases, the pumps had to be packaged and designed to operate with very low NPSH available due to the positioning of the skids on the FLNG topsides. Selecting a pump is always a balance of many factors, including the volumes and properties of the fluid to be pumped, total static lift, pipe size, pipe losses, the efficiency of the pumps, and how frequently the pump will be run. Where space is at a premium however, engineers must deal with the additional and difficult factor of the lack of suction head. The lack of headroom on Coral South between decks meant that a low suction head was a significant design consideration, and not taking this into account would cause catastrophic cavitation to occur in the pumps. Cavitation occurs when a pump cannot get enough fluid flow into the impeller and the resulting reduction in pressure causes the liquid to vaporise and form bubbles. These bubbles can grow dramatically and choke an inlet, further reducing the flow of liquid and the performance of the pump. In addition, the bubbles can implode with tremendous force, literally tearing away at the metal surface. The resulting increase in stresses, vibration, and noise can lead to downtime and premature component replacement, and in some cases complete pump failure. To avoid this catastrophic situation, the pump

designers needed to ensure that the net positive suction head available at the pump, NPSH(A), exceeded that required by the pump to operate without cavitation occurring, NPSH(R). NPSH(A) is in principle a straightforward calculation taking into account the suction static head, pipe friction losses, atmospheric pressure, and the vapour pressure of the liquid. The first step in designing a system with low NPSH is to review the physical location of the pumps and tanks. Ensuring the pump is as close to the tank as possible will minimise pipe losses. Similarly, reducing the number of bends, valves, and filters in the pipework between the tank and the pump suction will result in greater NPSH(A). The designer must also ensure that the pipework is of the right size for the required flowrates and that the minimum level of liquid is sufficiently above the suction tank outlet, which reduces vortices and potential air entrapment at low levels. When designing for the extreme challenges of a FLNG vessel, every calculation must be completed fully and accurately. Simply introducing safety margins without due thought to the process would result in a complex engineering solution with large costs and potentially a weight penalty when a simpler solution may be available. For example, APIb610 recommends that the pump manufacturer gives serious consideration to the difference between NPSH(A) and NPSH(R) when calculated using the vapour pressure of the lightest fraction in the fluid being pumped. In the case of Coral South, like many other FLNG vessels, the headroom was not available to engineer a solution if the calculations were only based on the lightest fraction, and so the design

Figure 4. Lowering the motor onto an Amarinth vertical inline pump. considered the lightest bulk vapour pressure of the process fluid. This reduced the vapour pressure used in the NPSH calculation, decreasing the static head required, resulting in a pump that could deliver the duty and fit within the available space. The specification also called for nozzle loading requirements of four times that set by API 610 due to the space constraints. Amarinth used its engineering expertise, business agility, and software solutions to create a bespoke design – strengthening casings and increasing web sizes and thicknesses, and undertaking detailed stress analysis using Finite Element Analysis tools to prove and guarantee the design. Lastly, as the motion of the vessel would starve normal bearings of their lubricating oil, the company developed a bespoke grease lubrication system. To keep the project on track, the company succeeded in designing and manufacturing these ATEX compliant bespoke pumps on a very tight 28-week deadline.

Tortue Ahmeyim FLNG FLNG vessels are subject to large fluctuations in loads as they process and then store the liquefied gas until ready to offload and then start again with an empty hull. In addition, to maintain sea worthiness and stability in heavy seas, they have self-contained ballast systems which require pumps that can move large volumes of seawater into and out of the ballast tanks, but which must be compact enough to fit within the available headroom between decks. Amarinth solved these and other challenges on the FLNG vessel destined for the Greater Tortue Ahmeyim field development project. Located off the coast of Mauritania and Senegal, this field is thought to contain a potential

June 2021

420bbillionbm3 (15 trillion ft3) of natural gas and is the deepest offshore project in Africa to date. The FLNG vessel will have the capacity to process 2.5 million tpy of LNG. Amarinth was commissioned to provide over 65 pump sets for a broad range of duties for both the vessel’s topsides and hull applications. The company was selected for its proven expertise and for continuity of supply, spares commonality, and single source commissioning. To maintain the vessel’s stability and equilibrium, large ballast tanks in the hull are filled with seawater and subsequently emptied again as the amount of processed LNG in the vessel’s internal hull tanks changes. After careful consideration of the available space within the hull for the ballast pumps, Amarinth designed bespoke compact vertical inline pumps. The bespoke design minimised both the weight and footprint of the pumps and ensured that their height still allowed them to be lifted out for maintenance within the restricted headroom of the decks. The tight space constraints of the vessel also required Amarinth to design complex pipework that would fit within the shape and restrictions of the hull. The head and flow of the ballast pumps was also not constant and changed according to the tidal conditions. To cover this range of duties, Amarinth supplied the pumps with variable speed drives, enabling them to efficiently move the right amount of seawater at any time and compensate for both slow and rapid changes of volumes in the process tanks. Other critical duty pumps supplied by Amarinth for Tortue were used in the process of loading the LNG onto waiting transportation ships, where vertically submerged pumps designed for operating with large flow capacities at cryogenic temperatures were required. In addition, pumps were supplied for several vital topside processes, such as produced water treatment and MEG reclamation. In these cases, the pumps had to handle highly corrosive fluids and so required total containment Plan 53B seal support systems with double mechanical seals. Seal support systems for vertical pumps are usually located some distance from the pump, but with space being so restricted, Amarinth designed bespoke baseplates for the vertical pumps that could accommodate both the pump and its seal support system, minimising the footprint of the whole unit to fit the available space. Seawater lift duties aboard the vessel required the use of self-priming pumps with substantial MV motors and Planb53B seal support systems. Amarinth provided its compact vacuum primer units for the pumps and designed a bespoke support frame for the very heavy motor with a footprint to fit the confined space within the hull.

Providing solutions for the growing demands of the LNG industry Designing pumps for use aboard FLNG vessels is a huge challenge for engineers with each vessel having its own unique requirements. In delivering solutions for these extreme environments however, pump manufacturers such as Amarinth are able to leverage their expertise, skills, and technology acquired in the oil and gas industry, particularly on FPSO vessels, to design and manufacture innovative, robust, reliable, and cost-effective pumps to meet the growing demands of the FLNG industry, now and in the future.

Scott Moreland, QUADAX Valves, USA, outlines the design considerations of valves to be used in applications with extreme temperature requirements.

s most piping specialists know, LNG applications can be very difficult to control flow, and it takes a special design with specific materials to work in temperatures ranging down to -454˚F/-270˚C. A design and materials which cannot be utilised in most valve types. While both gate valve and ball valve designs have been utilised, they do not always provide the very best of results – zero leakage in on/off applications. Even most triple offset valves will not allow for zero leakage, due to the elliptical design of the port and sealing areas being most difficult to hold the most stringent sealing. That, coupled with fabricated designs which will be made worse whenever there is any deflection of sealing surfaces caused by pinned disc or inferior stem designs, mean there can be a very small window where a valve can seal perfectly. A four offset design valve allowing for a circular sealing surface, along with very low friction on the seals, will comply with the desired effect of allowing for zero leakage at low temperatures. This is true especially after a high number of cycles at very low temperatures while most other TOV’s have begun a process of increasingly leaking beyond acceptable levels. As a result of a four offset construction and state of the art manufacturing technology, QUADAX® Valves are designed to offer 100% compliance even with the highest tightness and extreme temperature requirements. Now take those extreme applications and add the requirement to the reliability of functioning time and again sporadically in the unique application of refuelling a rocket with LNG/liquid hydrogen in less-than-ideal weather conditions, i.e. coastal locations. The frequency of the loading at the very low temperatures, the rough handling of the equipment given the surroundings and circumstances of quickly turning on/off the process, along with the outside temperatures and corrosive atmosphere of the coastal locations for launching pads, all give rise to very extreme conditions in which a valve has to operate without failing time and time again – high cycling. The leading aerospace companies in the US have found a strong business partner for their valve requirements and therefore the solution to maintaining zero leakage on/off operation in QUADAX Valves.

Figure 1. US aerospace group launching latest rocket with payload.

Space travel In order to meet the constantly growing demand for the economic transportation of medium and heavier satellites for civilian purposes, the launching stations for orbital missiles are 29

continuously expanded. The fuelling systems are upgraded continually and have to be ready for processing at any given time. During the fuelling process, temperature swings are extreme, which must be addressed with a valving solution which requires complete and safe shut-off every time. When it comes to refuelling that utilises LNG at less than -259˚F, aerospace companies have very well-defined specifications including special testing, special cleaning, and very durable material requirements. To assure zero leakage in these extreme temperatures in the refuelling process, a valve is required which is manufactured with a totally round seat and sealing geometry, along with other features which will provide positive sealing even if the materials are shrinking or expanding given the unique temperature differences throughout the process and from the environment. While other valve designs often fall short, the QUADAX Valve is designed to work in these very low temperatures, as well as in extremely high temperatures (up to 1472˚F). Besides the negative environmental effect, excessive fugitive emissions could also have an impact on the security and safety of personnel. The operating companies of these launch sites are therefore paying particular attention to this fact and request an individual performance testing for the approval of cryogenic valves which shall be installed in their refuelling systems. QUADAX exceeds at these types of testing and most recently performed a special test combining the

cryogenic test according to BS 6364 with an endurance test according to EN 12567. A QUADAX four offset butterfly valve DNb500 mm, ANSI class 150, was tested at the ITIS BV test laboratory in the Netherlands, specifying 10 thermal cycles with a fugitive emission test at 20˚C/68˚F and at -196˚C/-320˚F alternating. In addition, the requirement called for an endurance test, with 500 mechanical movements at -196˚C measuring the internal and external leakage after determined cycles. The benchmark in terms of the seat leakage was less than 3000 ml/min. for a valve of DN 500 mm based on BS 6364 and a maximum allowable fugitive emission of ≤1.0·10-3bmbar·1·s-1 at any time of the cycles. The valve was tested with helium at 19 bar test pressure whereas the seat leakage and fugitive emission was measured after 20/40/80/150/300 and 500 cycles. As a result of the four offset design and a high precision in manufacturing, QUADAX Valves has provided once more the evidence of a remarkable performance in cryogenic applications. The test institute, ITIS BV, certified that the seat leakage never exceeded a low value of 590 ml/min., and after 500bcycles zero leakage at all could be detected. Moreover, the fugitive emission at the bonnet and trunnion gaskets of the top entry valve never exceeded a value of ≤1.0·10-5bmbar·1·s-1. The round seat and sealing geometry of QUADAX Valves is a totally friction-free metal to metal design. Due to this round geometry, after several hundred cycles the seat and sealing ring is literally looped-in and can provide the highest tightness even if the material is shrinking and expanding due to extreme temperature differences.

Valve offerings

Figure 2. Quadax testing to the latest cryogenic specifications and beyond.

The successful testing undertaken on the QUADAX brand valves, along with a broad range of size and configurations, provide the user in extreme temperatures with a go-to partner for reliable valves. The five configurations – lugged style, double flanged to ISO 5752, long patterned double flanged to replace gate valve face to face per ANSI 16.10, buttweld end design for welded into lines, and top entry design – allow for complete repairability when a valve is welded into place. These choices, along with piping size ranges from 2 in. (50 mm) to 72 in. (1800 mm) and pressure ranges from ANSI classes 150 - 1500, allow the user to pick the very best fit for their piping systems. QUADAX’s four offset valves are designed to offer four key principles to the company’s customer base: z Extreme temperature ranges. Homogenous materials allowing for same expanding/ shrinkage. Temperatures from -454˚F (-270˚C) to 1472˚F (800˚C). Large temperature swings are easy to handle. z Superior tightness. Meet or exceed the most stringent tightness requirements. Bubble-tight even in cryogenic applications. Innovated and patented sealing design. z Increased operational safety. Totally friction-free in sealing areas.

Figure 3. The Quadax technical team works in clean room environments, modifying valves for use in aerospace applications.

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Reduced risk of failures. No wear in sealing areas. Longer service life.

z Reduced operating costs. Higher Cv/Kv values against other TOVs. Lower nominal pipe diameters. Lower torque requirements. Reduced maintenance costs (lower cost of overall ownership). As a recent LNG customer found by switching to the four offset design, they now have valves in an older facility that are operating better and more efficiently than when the system was new. By switching from a side entry design TOV manufactured by a major valve manufacturer to the QUADAX design top entry, the customer’s people are experiencing less service issues and maintenance on the system; a safer environment with bubble-tight closing and lower fugitive emissions; and lower overall costs to the maintenance budget. This created a success story for QUADAX that has since been replicated at several subsequent user sites and has given a strong referral point for other LNG users to look to whenever they have valving decisions to make for safer, more efficient piping designs.

Designed for beyond Earth As noted, QUADAX has found such partners in the aerospace industry who, after years of struggling with less effective designs, now specify a four offset valve into their system knowing that they are installing a more reliable and safer option. In the US where the aerospace programmes are now run by private companies in close co-operation with the federal space programme, the need for reliable and safe is at the forefront of all when installing systems for fuelling. Every major aerospace

company has moved to using QUADAX in their most critical systems. These companies have found a willing partner that can provide them with peace of mind whenever they design and then install piping systems requiring proven dependability and topmost safe operation for their people and the coastal environments where launch pads are found. The use of LNG/hydrogen in rocket fuelling systems require increased storage and processing of LNG, which has led to a need to have reliable valves in the piping systems. After years of experimenting and use of inferior products, the aerospace customers now require positive testing sometimes beyond what is referenced in BS 6364 where most triple offset valves can comply, although with much effort and for a short period – primarily during FATs. As provided by the ITIS BV testing, QUADAX more than exceeds the requirements of refuelling systems. Reportedly, the aerospace groups agree that QUADAX valves have been tested beyond the requirements set forth by BSb6364 and provide the best results when utilised in the fuelling systems, with a strong history of performance over years of practical applications. At a spaceport there is a high technological infrastructure on which spacecrafts are launched. The fuel combination of hydrogen and oxygen, along with LNG temperatures, are mostly used in liquid fuel rockets today. Both in the production and storage of liquid rocket propellants as well as during the refuelling of the rocket, with such cryogenic fuel components having a temperature colder than -364˚F/-220˚C. Reliability and, of course, personnel safety are the top priorities. Even the smallest leakage can have disastrous consequences. That is why the company’s customers appreciate the four offset design, the high quality, and the know-how of QUADAX Valves.

www.quadax.de

Todd O’Neal and Jay Park, TMEIC Corporation, USA, provide a Japanese view of lean manufacturing methods, and explain how excellence in manufacturing can assure reliability.

NG facilities are among the largest and most complex facilities requiring hundreds of thousands of small and large components, systems, processes, and controls that must work flawlessly, simultaneously to achieve the necessary efficiencies for profitable operation. Additionally, each component and system must operate without failure for many thousands of hours or even years. Piping, compressors, pumps, electrical equipment, controls, heat transfer systems, safety/environmental systems, and all other operational systems must function

as designed, or the process slows or comes to an abrupt halt. In the worst case, far less than desirable and extremely unsafe ‘rapid unplanned disassembly’ may occur. How can we be assured large systems will run reliably and not ‘disassemble?’ We cannot. That is, not as a single machine. Instead, we commonly deconstruct the composite machine and then consider the reliability of individual systems and components. A component-level analysis is the tenet of the statistical method known as failure mode and effects analysis (FMEA). In FMEA,

individual parts are closely looked at, then the machine is reconstructed statistically to arrive at the expected behaviour of the overall system. The individual systems and components operating without failure combine to form a successful assembly. When designed and manufactured precisely in conformance with a well co-ordinated process, these individual systems and components provide the greatest potential for total system success. Through longterm incorporation of quality processes during the design and manufacturing phases, engineers can achieve this component and subsequent recombined equipment level success. In a deconstruction and reconstruction method similar to FMEA for the calculation of reliability, techniques in manufacturing focus on the individual steps of manufacturing at the component and assembly level such that equipment designed to be reliable actually ends up… reliable. Total quality management or lean manufacturing is the common path forward to manufacturing excellence.

The fundamentals of quality management Quality management is far older than one may think and has evolved over many centuries. As far back as medieval times, craftsmen developed rules for making better common products or weapons. The craftsmen would affix their mark to a product indicating they had completed their work and were satisfied with the quality. The feedback process was not as immediate then, but in time the message would get back to the part’s maker, and improvements could be made. Later, inspection by dedicated individuals was added as a process during the industrial age. In this period, a few workers with great experience and ability in their craft would inspect the work of many. Any anomalies were addressed directly between the craftsperson and the inspector, but the process was less than formal, and documentation was generally lacking. Dividing labour into individual crafts and then subdividing the craft groups into smaller efforts further enhanced product quality in the workforce. Specialisation of labour provided a greater level of skill at each task, furthering each product’s quality. In the late 1930s and 1940s, the quality effort became a critical component of the war effort. It marked the first

time organisations worked with their suppliers and sub-suppliers to support quality at the sub-system and component level. Following World War II, quality pioneers such as Deming and Juran introduced total quality systems in which inspection was combined with process improvement and focused training to rapidly improve manufacturing precision and expertise. This total quality approach also resulted in reduced cost of manufacturing. Process changes were not rapidly adopted, nor were requests passively accepted, yet finally, cultural changes came about. Eventually, statistical methods and analysis were combined with the focus on the entire organisation. In the 1950s this became known as total quality management (TQM) and companywide quality control (CQC) or quality management system (QMS). Today, these systems form the backbone of modern global quality systems. Systems such as ISO 9000 are now the basis of acceptance for most industrial users. Nowadays, the ISO system is generally accepted as the gold standard for quality certifications. The general mantra for ISO is “say what you do, do what you say.” Each ISO-certified company must document and implement their own quality programmes and require sub-suppliers to maintain quality programmes of their own. This way, manufacturers can be assured components received can be assembled into a product worthy of branding. ISO and other certifications are often combined with assessments, audits, and actual experience to arrive at an overall product assessment. In the 1940s, decimated by the war in the Pacific, Japanese manufacturing was at an all-time low with respect to output and quality. Japan would have had great difficulty recovering quickly by itself. Japanese and US leadership both understood that to recover more efficiently, Japan needed to embrace a new paradigm. The new paradigm was total quality. With the additions of total quality systems, and the consulting support of quality innovators such as W. Edwards Demming, Japanese manufacturing rallied to recover quickly. Soon, US manufacturers found themselves looking to Japanese companies for guidance in processes that were best in class in quality and manufacturing expertise. By embracing the process of total quality, Japanese manufacturers developed and improved upon the innovative post-war quality philosophy and excelled. Japanese manufacturing came to define quality – a reputation that continues to this day.

Excellence in manufacturing

Figure 1. Clean, ordered assembly area.

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TMEIC is a Japanese company and a global manufacturer of high-power electric motors and power electronics, including variable frequency drives and utility scale inverters for solar power producers and world-class industrial automation systems for a variety of industries. The company utilises total quality management and adds additional Japanese concepts to arrive at its own form of total quality management. This system is used throughout the company to achieve manufacturing excellence. The company recently opened one of the newest manufacturing centres in the US, in Katy, Texas. TMEIC understands that quality is best achieved by closely combining technological innovation and continuous improvement philosophies. The local quality team in conjunction with headquarters in Tokyo, Japan makes sure the quality systems are both

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consistent and relevant. The operations and quality teams work daily to ensure the company processes are on par with best in class standards. Luis Padilla is Operations Director at the company’s Texas facility. Luis claims TMEIC’s focus on quality is not just a local goal. “We train on and share our quality programmes and methods with our companion facilities in Japan and India and around the world.” TMEIC uses a variety of well-developed process tools to ensure excellence in manufacturing. Many of these methods have been modified to incorporate a distinctly Japanese flavour.

Continuous improvement TMEIC practices Kaizen. Kaizen is a Japanese term meaning continuous improvement. The word is formed from two words, ‘kai’ meaning change and ‘zen’ meaning good. Kaizen is a statistical process introduced by the Toyota Company in 1980 and is now used around the world. In the Kaizen model, employees are empowered to present ideas when common problems are encountered. The goal is to eliminate the reoccurrence of non-conformances. This concept is the core of the Kaizen strategy. Managers know a highly engaged workforce is one that understands that their opinions matter. Meaningful change is the result. The process of Kaizen is implemented through four primary actions of the team; plan, do, check, and act. Objectives are planned, and methods are defined. Much effort is placed on this planning phase. No work is started before the plan is complete and understood by all. Strategies are implemented based on the plan. Deviations are not acceptable. Results are then evaluated for improvement and adjustments are made as needed. This feedback step is paramount. Employees participate in the quality control process and receive feedback on how they are contributing to improve the quality of the company’s products. Assemblers have different levels of skills, from level one to five, specific to a particular assembly line and are assigned accordingly. Employees receive periodic training and the company requires assemblers to pass national skills tests to move up to the next level. Quality and reliability are improved by a motivated and highly skilled workforce. The result is reduced processing time, inventory, waste, unnecessary motion, excess transportation, and product defects. Kaizen is the purposeful path to high-quality, highly reliable products. Additionally, all Texas based manufacturing managers at the company are required to make multiple extended trips to Japan to train in quality practices including Kaizen. Another tool used by the company is termed the 5S’s. The 5S’s of manufacturing are taught to all employees and followed each day. The 5S’s are: sorting, setting, shining, standardising, and sustaining. These 5S’s are fundamental to efficiency and repeatability in manufacturing operations. z S1: (Seiri) Workers sort necessary items from unnecessary items and dispose of the unnecessary pieces immediately. A designated person is responsible for determining the items to be disposed of. z S2: (Seiton) Items are clearly marked and placed in order of installation. The items are then installed in this order every time. All parts, tools, and cleaning equipment have fixed locations. Once a task is

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complete, the tools are replaced to their designated locations before the next step is initiated. z S3: (Seiso) Work areas are cleaned continuously. All cleaning equipment is provided, and mandatory cleaning points are defined in the workflow. z S4: (Seiketsu) Standardise and maintain the first three S’s. Time for evaluation by supervisors is established. If non-conformances are discovered, they are addressed immediately. z S5: (Shitsuke) Observe and follow the rules. All employees are expected to practice mutual attention to detail. The purpose of the 5S’s is to reduce waste, injuries, failures, defects, complaints, and delays. Waste is a tightly monitored and evaluated quantity. Waste is created when there is an instance of careless or extravagant use or use without purpose. There are a variety of categories of waste, all of which can be placed into seven groups in lean manufacturing. The waste categories are processing, inventory, over-production, waiting, motion, transportation, and defects. Unchecked, the seven wastes will occur increasingly if the process is not controlled. However, the seven waste categories are reduced greatly using the concept of Muri, Muda, and Mura. These concepts are interrelated with each affecting the other. Muri (unreasonable workload) are wastes that can be remediated by the elimination of excessive or strenuous movement or thought. Muda (loss of time and effort) are wastes reduced by eliminating movement of parts, waiting, and searching. Mura (inconsistent work) is waste decreased by eliminating or reducing sudden changes to workflow or instructions.

Quality from the start Reliable components, built with excellence in manufacturing, using TQM or lean manufacturing techniques, are the direct path to reliable machines for highly complex systems such as LNG facilities or other industrial complex. The lack of high quality, high precision, highly planned processes in manufacturing will lead to failure of components. Failure is intolerable and highly detrimental to the availability of the facility overall. Furthermore, the quality process and the process of continuous improvement are fundamental to success in manufacturing. Does the use of a total quality process necessarily dictate a zero-defect product? No, it does not. But, minimisation of random and systemic nonconformances in the engineered processes will minimise defects at the component level and will benefit the greater system. Quality in manufacturing cannot be left to chance. Quality is not something that can simply be hoped for. Total quality management works well and provides the greatest impact in companies with a long-term vision. Feedback and adjustments are always necessary, and the expertise gained in each iteration adds to organisational wisdom. In the end, the component or equipment manufacturing organisation is not the only beneficiary. The end user will also derive significant benefit when all of the associated component and equipment manufacturers implement well-considered quality management systems.

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Allen Dickey, Owens Corning, USA, explains how insulation can mitigate vapour drive and protect LNG facility function.

he cryogenic operating temperatures at which LNG systems function, along with the locations in which many LNG facilities are located, combine to form specific requirements for the insulation systems. When selecting insulation to safeguard a cryogenic system against vapour drive, several elements have to be considered: the permeability of the insulation, its ability to protect the thermal efficiency of the system, and its stability at extreme temperatures. These factors should influence the decision-making process. According to The Center for Energy Economics at the University of Texas, US, the first layer of protection for LNG facilities is implementation of the correct materials on-site and solid engineering design.1 Using a non-permeable insulation and proper accessories helps to defend cryogenic systems against the consequences of high vapour drive and promotes long-term thermal efficiency, stability, system lifespan, and facility safety.

Vapour drive in LNG facilities It is estimated that 98% of insulation system failures are moisture related.2 Therefore, understanding vapour drive and protecting equipment from moisture damage remains an important element of designing insulation for use in LNG facilities. Much of the equipment on-site functions at approximately -161˚C (-258˚F). This temperature puts piping well below ambient conditions when in operation, although piping systems also can cycle from cold to ambient temperatures during shutdown periods. Many LNG facilities are located in warm, humid climates nearing 32˚C (90˚F) with humidity levels close to 90%, which increases the potential for water vapour transmission (WVT) into the insulation system. Warmer air has a higher capacity for vapour pressure, or the stage when water exists in equilibrium as liquid and vapour. When that equilibrium changes or meets a colder surface, water condenses until a new balance is reached. The differential between ambient and LNG system operating temperatures increases the vapour pressure, driving moisture toward the colder object, and heightens the risk for moisture to penetrate permeable or incorrectly installed or damaged insulation systems. Once moisture starts to collect in LNG system insulation, there is a risk of it freezing, which will increase damage to the insulation and further reduce its effectiveness. Once started, damage to insulation can continue as moisture travels closer to the surface of the pipe. It is possible for moisture intrusion to create a freeze thaw movement pattern as pipe temperature cycles during use and shutdown periods. A comparison trial examined the level of vapour permeability in several different types of insulation, including cellular glass, flexible elastomeric foam, polyisocyanurate, and nano/micro porous or fibrous insulations.3

Figure 1. Often located in warm, humid regions while running piping and equipment at low temperatures, LNG facilities face the potential for damage from moisture penetration into insulation.

typically use stainless steel piping. However, these pipes have the potential to develop stress corrosion cracking (SCC) when water infiltrates the insulation and certain chemical conditions are met. According to the U.S. Department of Transportation, SCC occurs when stressed pipes, or pipes under pressure, are in contact with water and specific chemical elements – often chlorides.5 Even when not in use, LNG pipes are stressed because of their production process, and when also exposed to moisture and non-neutral chemical conditions, they are at risk of cracking. Temperature cycling periods may increase this danger. One way to improve system resilience is to carefully select insulation accessories, such as jacketing, mastics, and vapour barriers. With permeable insulation, any damage to these materials leaves the insulated system vulnerable to moisture penetration. Poorly installed and/or improperly selected accessory products place system performance and lifespan at risk. The establishment of an effective vapour retarder for the insulated cryogenic system is jeopardised by the use of inappropriate materials or poor installation. When a vapour barrier jacketing is installed with correctly applied impermeable insulation, such as close-cell cellular glass insulation, and insulation joints are sealed, it helps protect the system from freeze thaw damage and supports joint integrity. Combining impermeable insulation with wellselected accessories also helps compartmentalise the insulated system, which further reduces the risk of catastrophic failure by isolating insulated sections and preventing the migration of moisture if a particular location is compromised.

Maintaining thermal efficiency and dimensional stability

Figure 2. A lack of stability in insulation materials when exposed to cold temperatures – such as those generated by LNG pipes – may leave gaps for moisture, allowing for ice build-up and system damage. Of those examined, only cellular glass insulation was completely impermeable. The material is also nonabsorbent according to ASTM C240.4 Additionally, cellular glass insulation has a water vapour permeability of 0.00bng/Pa·s·m (0.00 perm·in.) when tested according to the ASTM E96 Procedure B (wet cup) method and does not increase in weight when exposed to 90% humidity.4 Weight gain in insulation resulting from moisture accumulation caused by surrounding humidity can overload pipe supports and cause damage to piping and equipment, reducing the lifespan of the system.

Reducing the risk of stress corrosion cracking with insulation and accessories Metal pipes can be at risk of corrosion under insulation (CUI) when moisture penetrates insulation. LNG facilities

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It has been estimated that the use of properly designed insulation systems to reduce heat transfer in US industry facilities lowers energy consumption by approximately 200bmillion bpy of oil.6 In an LNG system, insulation can be used to help maintain pipes at a pre-set temperature by minimising heat flux, which supports lower operating costs. The intrusion of moisture into insulation surrounding LNG pipes reduces thermal efficiency and increases energy consumption. Industry studies have noted that open-cell insulating materials see up to a 23% increase in thermal conductivity following a 1% increase in moisture.7 Although low-permeability insulation is often used in a system composed of multiple layers of both insulation and vapour barrier jacketings, the installation of an impermeable insulation eliminates the need for more than one vapour retarder, reducing field labour and install costs. Another element to consider when selecting and designing insulation for LNG pipes to prevent premature system failure is the substance’s co-efficient of thermal expansion (CTE). Thermal insulation and steel piping will expand or contract at different rates with changing temperatures. When an LNG system is cooling to temperature, the insulation and pipe will contract by different amounts. In one study, both polyisocyanurate and cellular glass insulations were lowered from ambient to -170˚C (-274˚F). The amount both materials contracted was compared to contraction rates for both carbon and stainless steel experiencing the same temperature drop. Throughout that temperature change, cellular glass insulation tightened

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somewhat less than carbon or 316 stainless steel, while the polyisocyanurate insulation contracted more than the steel.3 Contraction of the insulation could potentially create gaps for vapour to penetrate and ice to form. However, cellular glass insulation has been found to have excellent dimensional stability and to more closely match the substrate when compared with other insulation materials. Cellular glass insulation also has high compressive strength relative to its density – verified with testing according to ASTM C165/ C240/C552.4

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Another consideration for insulation selection and system design for LNG pipes is to install insulation at a thickness that will provide a surface temperature on the outside of the insulation as close to the ambient temperature as practical while the system is in operation. Reaching ambient conditions in the external edge of insulation may prevent condensation from collecting on the insulated system. This design can play a role in addressing common safety concerns at LNG facilities, as an insulated system that does not absorb moisture or allow condensation to form reduces the potential for dripping to occur. Water falling from elevated insulated pipes can lead to wet pavement and slip hazards for those on-site. Additionally, cryogenic piping is often supported on the exterior of the insulation system to eliminate potential thermal shorts that would lead to condensation and ice build-up in the location of the pipe support. Moisture condensing on LNG pipes can freeze and produce falling ice chunks, which further reduces facility safety. Using an impermeable or close-celled insulation can prevent moisture from condensing within insulation and dripping or forming ice.

Conclusion The process of protecting cryogenic piping at an LNG facility from aggressive vapour drive starts with considering the types of materials and accessories being used in the insulation system. Selecting an impermeable insulation, such as cellular glass insulation, helps prevent the problems caused by moisture collecting on or penetrating into insulation by refusing to give water a pathway into the system. Reducing moisture-based risks helps the system avoid SCC and maintain thermal efficiency, supports safety, and limits the potential for damage.

References

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

FOSS, M.M., ‘LNG Safety and Security’, Houston, Texas: Center for Energy Economics, (2012).

ADAMS, L., ‘Thermal Conductivity of Wet Insulations’, ASHRAE Journal, (1974), pp.61-62.

Owens Corning testing data.

Owens Corning, ‘Foamglas One Insulation data sheet’, (2020).

U.S. Department of Transportation: Pipeline Safety Stakeholder Communications, ‘Fact Sheet: Stress Corrosion Cracking’, (2014), https://primis.phmsa.dot.gov

BHATIA, A. ‘Process Plant Insulation and Fuel Efficiency’, Pipeline and Hazardous Materials Safety Administration, (2012), https://www.pdhonline.com

GUSYACHKIN, A.M. et al., ‘Effects of moisture content on thermal conductivity of thermal insulation materials’, IOP Conf. Ser.: Mater. Sci. Eng. 570:012029, (2019).

he most effective ways to respond to changes in feed gas flowrate and composition or process operating goals depend on where the process is running on the operational map and what constraints are either in effect or are close to becoming active. For example, absorbers are almost always either lean-end pinched, rich-end pinched, or mass transfer rate limited. The most appropriate response to an increase in raw gas flowrate, for example, depends on the regime in which the absorber is operating. The most common challenges to operations are posed by changing feed gas composition and flowrate. These can occur at any time but they are especially prevalent around initial start-up when it is almost invariably learned that the design basis for the treating unit is not the reality that prevails at the time. Often units are designed with the ability to accommodate reasonable departures; however, sometimes such is not the case. Indeed, depending on the process configuration, a substantially lower gas flowrate occasionally cannot be treated at all. This will be the first example of intuition gone wrong.

Failure to treat when gas flow is too low Figure 1 shows a CO2 unit that counterintuitively failed to treat to 50 ppmv CO2 when presented with only 10% of the design CO2 flow. This was a shock to everyone concerned. The cause was identified to be the low temperature of the rich solvent from the absorber. CO2 absorption is exothermic and it can cause quite a large temperature bulge to appear within the absorber. The heat of absorption is partially transferred to the gas which carries heat up the column. There, the gas meets cooler solvent and transfers some of its heat into the liquid phase. The solvent then carries the heat downwards where it meets a cooler incoming gas and transfers some of its heat back into the gas. This back-and-forth exchange often results in high temperatures within the absorber. But independent of a temperature bulge, the heat of absorption must eventually be carried out of the absorber in the treated gas and in the amine solvent.

Ralph H. Weiland, Optimized Gas Treating, Inc., USA, explores how to respond to changing process conditions in amine treating.

If the solvent flow is large and the gas flow is relatively low (as in the present case of a very significantly reduced gas flowrate) most of the heat is carried out with the solvent. The low gas flowrate translates directly into a low rich solvent temperature, caused by too little CO2 absorption (insufficient heat of absorption). This has consequences in the performance of downstream equipment. The most immediate consequence was that the too-cold liquid feed to the LP flash unit functionally turned this piece of equipment into an absorber which recaptured some of the already stripped CO2. This pushed too much CO2 into the regenerator and prevented it from producing a sufficiently

lean solvent to meet the 50 ppmv treating goal. Ultimately, the cause was the process configuration itself. It was too tightly integrated to permit it to adapt to the extremely low demand for CO2 removal placed on it. The natural reaction to inadequate treating is to increase the solvent flow, but in this example that would (and did) have the opposite effect – it made treating even worse. The correct response was completely counterintuitive and should have been to decrease the solvent flow and get the rich amine temperature up. To understand this almost certainly requires use of a high-fidelity, mass transfer rate-based simulator. This is a case of what are quite reasonable expectations being thwarted by an unforeseen quirk in the process design. Specifically, very tight heat integration made plant operating highly dependent on heat of absorption. The situation became understood and the problem resolved through careful rate-based simulation. This case is discussed in greater detail by Fulk etbal.1

Using higher solvent strength to process higher CO2 gas

Figure 1. CO2 removal unit in an LNG plant.

Figure 2. CO2 removal unit in a split flow plant. The schematic shows what would usually be a single absorber as separate bulk CO2 removal and polishing columns to make explanations more easily understood.

Figure 3. CO2 treating unit in a split flow plant.

June 2021

A frequent circumstance on start-up is that the CO2 level in the feed gas is marginally higher or lower than the basis used in the original design. Low CO2 does not usually present a problem (the aforementioned case is an exception) but if the issue is higher CO2 in the raw feed gas, then tight pump designs may leave little room for increasing gas removal capacity. It may be possible to vary the loading of the lean solvent or to change the equilibrium backpressure of CO2 over the solvent by changing its temperature. However, adjustments in these parameters do little to change solvent capacity. The only parameter really available is amine concentration, and the natural inclination is to increase the amine strength to increase solvent capacity. However, a higher strength amine is more viscous than its dilute counterpart. One might suspect that this could adversely affect treating simply because higher viscosity means lower mass transfer rates, especially in a process where absorption is controlled by liquid-phase resistance to mass transfer such as CO2 absorption by a piperazine-promoted MDEA-based solvent. However, when amine strength is increased in response to higher feed gas CO2 concentration (all else remaining the same because of equipment constraints), temperatures in the absorber rise, the temperature bulge increases, and it turns out that solvent viscosity remains almost unchanged. In fact, the increased temperature raises the reaction rate of CO2 with the amine and treating may actually improve, although perhaps not as much as one might expect from reaction kinetics. In an equipment-constrained system, using higher solvent strength in response to a higher-than-expected CO2 concentration in the feed gas is a very workable solution. However, one must be careful to keep rich amine loadings below the level dictated by the corrosion limits of the metallurgy of the tower, piping, and control valves. It also helps to be able to assess absorber internal temperature profiles to keep the bulge temperature below approximately 85˚C (185˚F) to prevent amine degradation and tower corrosion problems. This type of assessment is most readily undertaken using a mass transfer rate-based simulation tool such as ProTreat®.

Summer vs winter operations and quirks of split flow process configurations Split flow process configurations offer some remarkable opportunities to make very bad decisions that can defy troubleshooting efforts for a long time. Figure 2 is a schematic of a split flow process layout. In such a process, achieving a very low CO2 concentration in the treated gas does not require all the solvent to be well stripped. In fact, most of the solvent needs to be only partially stripped. Partially-stripped solvent is used to complete bulk CO2 removal in the lower part of the absorber. Well-stripped solvent is fed to the upper part where it polishes the gas by removing the last vestiges of CO2 that were not eliminated in the bulk removal section. A considerable amount of regeneration energy can be saved by such a scheme, however, there can be pitfalls that reveal themselves in the hot summer months, especially in tightly-designed, heatintegrated plants. Split flow layouts are less common in LNG applications than in syngas plants, for example, because the raw gas feeding an LNG train is usually fairly low in CO2 (typically 2%) so the energy saved by having lean and semi-lean amine solvent streams is outweighed by the additional equipment and greater complexity. However, if the raw gas is high enough in CO2 then the energy saved can more than compensate for the additional equipment. The heat recovery provided by the rich-lean and richsemi-lean exchangers is fixed by their area and to an extent by their geometry (shell and tube vs plate and frame, number of passes, etc.). Final heat removal from the lean and semi-lean streams is provided by trim coolers, labelled fin-fan in Figure 2. The heat sink is usually ambient air, and it is here that one can get into trouble in a split-flow plant in a hot climate. During summer months when daytime ambient temperatures exceeded 40 - 45˚C, this plant would fail precipitously to meet the 50 ppmv CO2 specification, not by a small margin but by thousands of ppm. One moment the unit was producing treated gas of much better quality than required, and the next the gas contained thousands of ppm of CO2, without warning of any kind. When this happened, of course, LNG production stopped. A modest LNG train produces 5 million tpy of LNG valued at roughly US$500bmillion – lost production represents approximately US$1.5bmillion of lost gross revenue per day (US$62 500/hr). The normal way to respond to loss of treat is to increase the solvent flowrate. Unfortunately, the lean amine pumps were already operating at absolute maximum flow so there was no room to manoeuvre. Inability to undertake any action to overcome the problem, combined with quite significant financial loss, made finding the root cause paramount. A great deal of effort was expended to identify the cause, but without success. In the end, the cause was revealed but only by careful mass transfer rate-based plant simulation. Simulation led to identifying the semi-lean amine temperature as the culprit. Figure 3 shows how the simulated treating performance was predicted to respond to the semi-lean temperature. At approximately 76˚C the CO2 leak from the polishing column shows extreme sensitivity to semi-lean temperature. Below that temperature it is completely insensitive. Any CO2 that cannot be removed by

the bulk column spills over directly into the polishing column which must remove it. As the semi-lean temperature rises, it can remove less and less CO2 and pushes ever more into the polisher. Eventually the polisher becomes overwhelmed. In the present case, this happens when the bulk column is removing 75% of the CO2 being fed to it. The polisher can remove 25% but nothing beyond that. The precipitous rise in treated gas CO2 level is simply the CO2 that the two columns are unable to remove. It may be interesting to note that the process licensor appears to have been aware of this limitation because the licensor’s advice was to keep the semi-lean temperature below approximately 70˚C. However, the heat exchange equipment was too undersized to allow this recommendation to be heeded. Or perhaps at some time the plant capacity was increased without fully realising all the consequences.

Summary In practice, intuitively correct responses to changing process conditions sometimes have the opposite effect to what was expected. Sometimes equipment constraints prevent the correct action from being taken. But whatever the situation, a predictive process simulator is often the fastest and most reliable tool to identifying the root cause of poor process performance and finding a solution. The cases discussed here were all resolved using the mass transfer rate-based ProTreat gas treating process simulator.

References 1.

FULK, S., JONES, C., and WEILAND, R., ‘When real conditions diverge from design’, LNG Industry, April 2018.

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loud-based and using artificial intelligence (AI) and machine learning, the METIS analytics platform enjoyed exceptional uptake through 2020, with over 250 vessels of different types now using the integrated performance monitoring and evaluation solution. In early 2021, another breakthrough was achieved after a well-known Asian ship manager became the first gas carrier operator to select a new METIS cargo handling and energy efficiency option for its ships, having upgraded to the Inmarsat Fleet Data IoT platform. Functionality specifically developed for LNG and LPG vessels has resulted in METIS monitoring and evaluation now enhancing operations for four gas carriers.

As a cloud-based platform, the solution is specific to the gas ship data acquisition and analytics needs of the ship’s owner/manager, but agnostic as far as the original maker of the equipment monitored and evaluated on board is concerned. Data acquired from shipboard sensors is uploaded for application program interface (API) exchange with the METIS analytics hub. The data is stored securely alongside information from other sources, such as weather providers and traffic monitoring services including AIS, as well as corporate and maintenance planning systems. All of this data is immediately available to the micro-service functionality interacting with end users.

Round the clock data provides a rich, high-resolution picture of ship performance, while the ability to pool, access, and manipulate data for multiple purposes is one of the game-changing ways maritime digitalisation enhances ship efficiency, safety, and environmental performance.

Ship-specific data needs This is a qualitative approach that contrasts markedly from the one-size-fits-all model seen in the maritime space until now, where everyone was presented with the same unfiltered

data, leaving it up to the individual user to manipulate or interpret it. Requirements vary by ship type, and even among supposed sister ships. The METIS system has therefore been developed as highly configurable to detect and act on significant events based on thresholds specific to individual vessels. Its diagnostic capabilities help engineers pin down the likely cause of any anomaly, while predictive capabilities enable the planning of corrective actions. LNG trades demand thorough monitoring of the sensitivities to temperature, pressure, and conditions of special cargoes in storage, in transit, and during handling, but also precise and timely information relevant to each vessel. METIS has developed specialised functionality to monitor and evaluate parameters through the entire voyage, including during loading and discharge.

Cargo conditional

Figure 1. METIS has developed new artificial intelligence (AI)driven cargo handling and energy efficiency functionality for gas carrier operations.

Figure 2. Now on over 250 vessels sailing globally, the METIS end-to-end digital transformation platform is powered by machine learning and AI.

Figure 3. The METIS Virtual Personal Assistant is the first ‘chatbot’ for the maritime industry.

June 2021

Where cargoes in transit are concerned, the METIS package for gas carriers monitors the condition of cargo tanks in real-time, with live dashboards showing the latest readings covering critical cargo parameters (temperature, pressure, and tank level), and a record of measurements over the previous 24 hours. Functionality also enables the ship’s owner/manager to evaluate the condition of cargo tanks over longer periods to develop performance insights across a range of conditions. Loading and discharging is also monitored in real-time to ensure adherence to the strict operational guidelines that apply wherever cargoes are handled and that the condition of cargoesbremains withinbthe required range of values. In a move also specific to gas carrier power consumption, the METIS solution continuously monitors and evaluates the performance of diesel generators in their critical role of maintaining conditions in the cargo tank. As well as ensuring the availability and reliability of machinery, generator performance is evaluated for optimised fuel oil consumption and responsiveness, reflecting the higher power required for handling cargoes for these types of ships compared to conventional tanker and bulk carrier counterparts.

Weather sensitive routing Where other vessel types are concerned, the machine learning supporting the METIS platform has achieved significant successes in route planning. Speed profile, fuel consumption, hull fouling, and other parameters that include the weather conditions that the vessel is likely to encounter can be used to generate what-if scenarios and propose a route that strikes the best possible balance between safety, voyage time, and fuel efficiency. One customer reported a 21.5% reduction in fuel consumption as a result, while another took the benefit as a one-and-a-half day cut in transit time plus a more moderate fuel saving. LNG cargoes are especially sensitive to changes in conditions at sea, adding value to any solution which promises to enhance voyage planning. The recent collaborative project involving four gas ships also included the use of data analytics as a tool to optimise route selection. METIS does not offer real-time weather services in its own right, but offers virtual scenarios based on predictions from three forecast providers, which in combination with actual vessel performance and hull condition data have allowed the carrier operator to evaluate routing alternatives.

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Multiple stakeholders Safety, efficiency, and environmental performance can only benefit from the availability of timely information, while accumulated data and evaluation becomes increasingly useful as a decision-making tool for multiple stakeholders. Data keeping and analysis will also be vital to ensuring that International Maritime Organization (IMO) targets for greenhouse gas (GHG) emissions reductions are met, as demonstrated by the coming into effect of the Energy Efficiency Index for Existing Ships (EEXI). A central feature of the METIS approach involves fuel oil monitoring and analysis. This is based on the real-time collection and processing of data from the main engine; diesel generator and boiler flowmeters; cargo profile parameters; hull and propeller operation parameters; vessel speed with respect to the ground; and sea/weather conditions. As long as particulars regarding the vessel, the rudder, and the propeller are known,bthese parameters can be used to calculate the vessel’s actual fuel total consumption, correlated to speed and power delivered to the propeller. However, given that IMO envisages a 40% reduction in ship GHGs by 2030, existing ships will either need to be modified in quite radical ways to make the cut, or adopt lower CO2 emitting fuels such as LNG on a transition basis as one part of a comprehensive carbon-cutting strategy. METIS recently launched a tool for the shipping industry to predict the trade-off between emissions reduction and debt servicing for ships financed under the Poseidon Principles. This module, launched in early 2021, calculates whether and when ships need investment to keep pace with the IMO average efficiency ratio (AER) underpinning the Principles.

In a first application, one owner determined that, while it was not necessary to make any investment in some of its ships, others needed modification either immediately or in the future, while two should be disposed of straightaway. Another newly developed digital tool within the METIS portfolio has special relevance to the gas carrier sector – especially the spot market. The company recently launched a software module to tackle the challenges shipping companies face in monitoring vessel performance effectively to meet Charter Party Agreement (CPA) reporting needs. The system uses weather data, vessel manoeuvring status, and all other remarks included in the CPA, and offers automated notifications in case the speed consumption curve exceeds predefined limits. The company has made it possible for LNG carrier operators to monitor and track their vessel’s CPA performance at a glance online, using a set of visually rich dashboards. Once all CPA terms are imported into the system, the user can monitor all vessels concerned and identify potential deviations to specified consumption and speed terms.

Conclusion Data-driven decision making helps those ashore and at sea generate scenarios quickly and easily, whether they are based on the current conditions faced by a vessel, the expectations of multiple stakeholders, or the continuing viability of an asset at a time of advancing restrictions on emissions. METIS is helping shipping decide on the optimal course of action, without its captains, superintendents, or business leaders having to resort to guesswork.

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Maksym Kulitsa, Independent FSRU Operations Consultant, Ukraine, and David Wood, DWA Energy Limited, UK, detail the advantages of keeping boil-off gas well balanced.

oday’s tendency in LNG marine transport is to minimise fuel spent and to maximise cargo delivered to discharge ports with minimum environmental impact. New technologies have made significant advances in reducing engine fuel consumption. The introduction of dual-fuel diesel electric (DFDE), M-type electronically controlled gas injection (ME-GI), and other fuel-efficient marine engines on LNG carriers, as well as improved LNG cargo tank designs have contributed to this improvement. Total voyage consumption of LNG is not only dependent on engine efficiency; other voyage operations have an influence. Reducing the LNG heel required for tank cool down prior to arrival at a loading port reduces voyage LNG consumption. During cooling down at sea, excess boil-off gas (BOG) is consumed in the gas combustion unit (GCU) on DFDE or steam dump (SD) on steam vessels. Such consumption is wasteful and leads to atmospheric emissions. Minimising excess BOG therefore has commercial and environmental benefits. The mandatory Ship Energy Efficiency Management Plan (SEEMP) (MEPC, 2016), EU MRV (EU Monitoring, Reporting and Verification of CO2; mandatory since 1 January 2018) and IMO DCS (IMO Data Collection System on fuel consumption; mandatory since 1 January 2019)1,2 all focus on fuel and emissions reductions. The SEEMP provides incentives to adopt more efficient LNG carrier operational practices in parallel with developing more efficient engine and ship designs. Traditional procedures applied to cool down LNG carrier tanks prior to arrival at discharge ports are typically not best practice, because less LNG could be consumed for tank cool down. In some situations, liquid marine fuels are consumed to preserve sufficient LNG heel for tank cool down (e.g. during

delays or bad weather). Marine diesel, at approximately US$535/t in March 2021, is costlier than BOG and produces more atmospheric emissions. More efficient LNG carrier tank cool down prior to arrival at a loading terminal can minimise LNG heel consumption. The proposed balanced-BOG method achieves this with most tank designs and is most effective with LNG carrier membrane tanks.

Cooling down cargo tanks prior to reloading The typical scheme used to cool down membrane LNG tanks is intermittent spraying – twice a day for three days – prior to arrival at the loading terminal. The LNG quantity consumed in cooling down LNG carrier tanks at sea ranges from 800 m3 to 1600 m3 LNG. That typically involves three warm tanks and one semi-cold, LNG-heel tank. The quantity of LNG consumed in that process influences an LNG carrier’s commercial performance. Excess LNG heel consumption leads to the ship delivering less commercial cargo. The traditional method of

tank cool down is convenient but wasteful. Some LNG carriers also consume marine diesel in their engines to save enough LNG heel for tank cool down, thereby increasing operating costs. Applying a high-spraying regime for short periods increases the tank pressure to approximately 65% - 70% of tank maximum allowable relieve valve setting (MARVS), which is 250 mbarg. At that point, spraying is discontinued to allow time for consumption of the resulting excess BOG generated by the engines, GCU or SD. Such a cooling-down schedule leads to high LNG heel consumption. The BOG extracted between spraying acts to cool the warming tanks and the LNG heel in the tanks (Figure 1), thereby contributing to extra consumption. Repeatedly cooling and warming tanks between spray sessions consumes approximately 300 - 400 m3 of LNG, that is approximately 30 - 50% of the LNG consumed in the traditional cool-down regime. The minimum LNG required to cool tanks alongside a terminal involves spraying for approximately 10 - 15 hours, depending on the tank type. LNG consumption for cool down at sea is double that quantity. Some operators, for expediency, allow higher cooling rates than cool down tables for the LNG carriers recommend. This causes excessive thermal stress and risks structural damage to the tanks and their pump towers, so is poor practice. Manufacturers’ cool down tables assist in estimating the LNG heel quantity required for tank cool down during ballast voyages. Adjustments are required for higher heating value (HHV) of the specific LNG cargo composition. Incorrect estimates can result in an LNG carrier arriving at a loading terminal with more LNG heel than necessary (e.g. up to 0.6b-b1.0% of total cargo capacity), reducing the quantity of LNG that can be loaded. On the other hand, insufficient LNG heel available could lead to rejection of the ship at the terminal because its tanks are too warm, and/or the consumption of expensive liquid fuel that is needed to complete the tank cool down. Both outcomes degrade an LNG carrier’s commercial performance. The proposed BOG-balanced method of tank cool down at sea can avoid such situations and substantially reduce LNG consumption.

BOG-balanced tank cool down at sea Figure 1. Example of traditional LNG carrier tank cool-down sequence at sea: 92 hours requiring approximately 680 m3 of LNG to evaporate.

Figure 2. Typical performance curve of LNG spray nozzles used in GTT tanks.

June 2021

This method exploits some BOG generated being consumed in the engine room, GCU, or SD with continuous tank spraying at slow rates. Ballast LNG carrier voyages typically follow two patterns: vessel moves at high speed during the cool down regime; or vessel cools tanks down at anchor or at slow speeds. The LNG carrier’s propulsion system (plus GCU or SD capacity) define the BOG quantity/rate an LNG carrier can handle (m3/hr). Continuous, slow-rate tank spraying with LNG enables the engine (plus GCU/SD, if required) to immediately burn the excess BOG, while maintaining constant tank pressure. Moreover, BOG consumption estimates are simplified using manufacturers’ cool down tables. The cooling energy stated in million/Btu units in the cool down tables is divided by HHV (in million/Btu) of the actual LNG heel. This ratio determines the quantity of the specific LNG onboard that needs to be evaporated to cool tanks to ‘ready-to-load’ temperature, i.e. approximately -130˚C for GTT tanks. Knowing the total LNG required to cool the three warm cargo tanks and the semi-cold heel tank, and knowing the expected total possible gas consumption (by engine/GCU/SD)

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Figure 3. Typical record trends of tank (A) temperature and (B) pressure for the traditional three days of intermittent at sea cool down for membrane tanks.

Figure 4. Comparison of traditional (intermittent) three-day tank cool down with BOG-balanced continuous tank cool down at sea.

June 2021

for voyage conditions, the time needed for tank cool down is readily estimated. Specifically, to derive the tank cool down time required – the quantity of LNG consumed to achieve a ready-to-load temperature, less extra accumulated vapour in the tanks, is divided by the available BOG handling capacity rate. This varies depending on voyage conditions. A uniform, slow LNG tank cool down rate for all tanks can then be applied continuously for that time period. That slow rate will be safer (less thermal stress) than faster cool down rates. To cool an LNG carrier’s tanks down from 30˚C to -130˚C, approximately 680 m3 (approximately 306 t) of LNG is required. Some vapour accumulates in the tanks at the colder state. The total mass of accumulated vapour in the tanks will be approximately 278 m3 (approximately 123 t) for a 160b000bm3 capacity LNG carrier. Thus, only 183 t of BOG needs to be evacuated from the tanks. The time required for balanced-tank cool down at 5 tph BOG rate would be approximately 37 hours, requiring continuous LNG tank spraying at an average total rate of 18.5 m3/hr. Spraying would need to start 37 hours before approaching the terminal. A balance is maintained between the LNG tank spraying and excess BOG extracted from the tanks. Depending on the nozzle spraying pressures, nozzle configurations and spraying regimes, the LNG sprayed in a single tank can vary from <10bm3/hr to >40 m3/hr. The number of LNG spray nozzles and their spraying capacity determines the appropriate spraying pressure in each tank (Figure 2). The cooling progress is easy to monitor and control, cooling the tanks at 4 - 5˚C/hr from 30˚C to -130˚C within 37 hours. The exact LNG quantity allocated for tank cool down should also take into account some spare capacity as contingency for vessel delays causing the cooling period to lengthen. Heat ingress into the tanks and loading pipework also need to be considered. Some additional time should be allocated for LNG heel to be transferred into each of the cooled tanks after cooling down, if necessary. Typically, a minimum of 6b- 10 cm of LNG on even keel should be maintained in each tank to keep them cool. Adjustments for these factors lead to a more accurate minimum LNG allocation for tank cool down. The BOG-balanced method plans to achieve ready-forloading tank temperature conditions on the arrival moment at the loading terminal or, ideally, close to the moment that the loading gauge opens. In which case, it is not actually necessary to transfer heel LNG into the cooled tanks. This means that even less LNG and time are consumed for tank cool down purposes. Figure 3 illustrates the temperature and pressure trends established during a traditional three day intermittent LNG carrier tank cool down at sea, where it consumed approximately 1046 m3 of LNG. Figure 4 illustrates the BOG-balanced tank cool down method, where only approximately 680 m3 of LNG is consumed, i.e. approximately 65% of that consumed using the intermittent method. Figure 4 also compares intermittent LNG carrier tank cool down (three days cooling in advance of arrival) with BOG-balanced tank cool down. The latter results in a 4 - 5˚C/hr continuous temperature descent with no need for LNG heel transfer. The BOG-balanced method is faster (37bhours vs 68 hours) and consumes approximately half the LNG heel, while providing fine-tuning of tank pressure. By using approximately 500 m3 less LNG for tank cooling down for each ballast voyage, the approximate commercial

benefit of the BOG-balanced method would amount to US$588b600/yr for an LNG carrier making 10 voyages, assuming a delivered sales gas price of US$5/million Btu and an energy conversion for LNG of 23.54 million Btu/m3. Benefits of a BOG-balanced cool down of LNG carrier tanks at sea include:

z Lower spraying pressures at tank temperatures above -140˚C do not cause LNG accumulation in the tanks.

z Tank cool down can be optimally and safely controlled with minimum LNG heel consumed, improving commercial performance.

Most LNG carrier operators have yet to unleash the full potential of modern vessel designs to improve efficiency and reduce emissions. The BOG-balanced tank cool down method at sea prior to reloading makes such commercially beneficial improvements by ensuring minimum LNG heel consumption. It is sufficiently flexible to cope with changing operating conditions and loading schedules, working particularly well with membrane cargo tanks due to their spray nozzles configuration. The method’s effectiveness could be further improved by modifying one spray coil per tank to have fewer spray nozzles for even more effective and flexible slow-rate spraying.

z Only simple calculations involving LNG quality and voyage schedule, minimising operator error in heel estimation and training requirements. z It provides flexibility for adjustments relating to inevitable schedule changes. z Spreading LNG heel among tanks can minimise tank warming if loading delays occur, facilitating jetty re-cool down within the charter party laytime allowance. z Cool down can be temporarily halted without the risk of venting over-heated vapour while maintaining tank pressure below 70% MARVS.

z The method reduces the quantity of LNG heel required in vessels fitted with reliquefaction equipment.

Conclusion

To learn more about the BOG-balanced tank cool down method, read the remainder of the article by visiting www.lngindustry.com

z At low or zero vessel speeds, each tank can be sprayed more intensely in frequent bursts, one tank in turn, for short periods. This minimises the total time that each tank is allowed to warm and can be synchronised to prevent tank pressures rising above 65 - 70% MARVS due to vapour expansion. z Slower spraying means less nitrogen consumption during tank cool down.

References 1.

DNV-GL. 2019. EU MRV and IMO DCS.

ICS-Shipping, 2015, ‘European Union Monitoring, reporting and verification (EU MRV) regulation. International Chamber of Shipping Guidance.

MEPC, 2016, ‘Guidelines for the development of a ship energy efficiency management plan (SEEMP).’ Resolution MEPC.282(70), adopted by Marine Environment Protection Committee, 28 October 2016.

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15FACTS

...ON

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Canada has yet to export any LNG

Canadian gas export revenues have dropped by 10.7% per annum from 2010 to 2020

The Canadian prices benchmark AECO-C Hub price often trades well below US$2/million Btu

Canada produces nearly 80% of the world’s maple syrup

The Canadian ﬂag was made official on 28 January 1965

The beaver is an emblem of Canada

While Canadian gas exports declined by 2.4% per annum during the decade from 2010 to 2020, Canadian imports increased by 1.8% per annum

LNG Canada is the only company to achieve FID in the country so far The Rockies stretch for a distance of approximately 4800 km

The Montney, Duvernay, and Horn River basins are some of the country’s natural gasrich formations

Canada’s lakes and rivers contain approximately 20% of the world’s freshwater The country’s capital city is Ottawa

There are 41 national parks and three marine conservation areas

Canada Energy Regulator (CER) estimates that Canada holds almost 1400 trillion ft3 of

Ice hockey is Canada’s national winter sport 56

June 2021

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Accelerating the energy transition for a better tomorrow. Technip Energies is a leading engineering and technology company for the energy transition. We offer leadership positions in LNG, hydrogen and ethylene as well as growing market positions in sustainable chemistry, CO2 management and carbon-free energy solutions. In LNG, we deliver first-class projects while offering solutions to reduce CO2 emissions from liquefaction and export terminals. Through our extensive portfolio of technology, products and services, we bring our clients’ innovative projects to life while breaking boundaries to accelerate the energy transition for a better tomorrow.

technipenergies.com

LNG Industry June 2021 issue

Articles inside

Balance the BOG

The power of AI

Mitigating moisture in cryogenic systems

Ready for anything

Designed for stormy seas

No situation too extreme

It's all about 5 star quality

Silencing the sound waves

Receiving the gift that is LNG

Canadian LNG's last best chance?

LNG news

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