LNG Industry July 2021 by PalladianPublications

July 2021

A masterclass in BOG management

ISSN 1747-1826

CONTENTS 03 Comment

JULY 2021

28 Meticulous performance monitoring

04 LNG news

Mike Hastings, Brüel & Kjær Vibro, Denmark, describes how LNG gas turbine efficiency can be fully optimised with performance monitoring.

08 Roadblocks and obstacles for

the land Down Under

Bruce Robertson, IEEFA, Australia, explains how climate risks, competition, falling demand, and legal challenges are strong headwinds for Australia’s LNG industry.

33 Keeping it cool

Steve Balek, Stellar Energy, USA, explains how digitising turbine inlet air chilling systems can help optimise maintenance activities to ensure maximum LNG production is maintained.

37 Tank bottom corrosion: solved

Merrick Alpert, EonCoat, USA, describes how a weldable coating has been designed to protect welded tank bottoms from corrosion.

39 Valves Q&A

Featuring Baker Hughes and Emerson Automation Solutions.

49 Digitising the field

Ludwig Gross, Fabrice Rey, and Julien Métayer, Technip Energies, France, outline the available advanced solutions for collaborative operator training.

52 Taking inspection to new heights 14 A masterclass in BOG management

Peter Lamberts, Stirling Cryogenics B.V., the Netherlands, g nt and the explores the aspects of boil-off gas (BOG) management growing presence of micro scale LNG in the future.

19 Expanding the degrees egrees of freedom

Dr Joey Walker, EffecTech, UK, looks at how to improve and optimise existing sampling systems forr LNG inspection.

25 Work the wavelengths engths

Per Christian Johnsrud, Tunable, Norway, y, describes ow improved multi-gas analyser technologies and how gas data could benefit the operation off LNG vessels.

Xiang Wong, Cyberhawk, UK, explains how drone technology is helping LNG producers plan and optimise asset inspections.

56 15 facts on... Australia

ON THIS MONTH’S CO COVER Stirling Cryogenics has engineered Stirling S engineere its renowned ren rre enown o ed cryocooler to a tailorma tailormade, tturnkey urnkey solution for boil-off gas (B (BOG) management m anagement and micro scale LNG production. pr T he article in this issue describes the two The different concepts for BOG manage management: direct reliquefaction and subcoolin subcooling. The Stirling technology is the optimum opti solution for small (micro) scale pro projects. www.stirlingcryogenics.eu

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

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LYDIA WOELLWARTH EDITOR

COMMENT S

o somehow the year has jumped from January to July in the blink of an eye and my hopes to escape the isles of Great Britain for a brief minute seem distant hopes and dreams at best. Whilst the specifics of England’s travel rules are only relevant to those Englishmen reading this comment, the overarching theme and confusion will resonate internationally. The rumoured ‘golden ticket’ nature of being double vaccinated; the fact there is a different rule set by one’s home country on all the other 194 countries in the world; and the irritation that on one day you may be fine to go abroad, e.g. to Lisbon, Portugal, and the next the government has changed its mind and you are now knees deep in flight vouchers for the several city breaks you had planned and no longer are going ahead. I speak from experience. Moreover, these flight vouchers remind me of Monopoly money, you almost forget you have actually already paid for them and one day will be scrolling long into your email inbox in search of these crucial 8 digit reference codes that are now waylaid and likely expired. It is the unknown, kept-in-the dark confusion of all things travel that makes it easy to understand why the Gastech 2021 event has moved location from Singapore to Dubai in September this year. I do commend the event organisers for keeping the event physical – albeit it now 3625 miles to a new destination – and not online, because some face to face contact between LNG professionals after months of video call interaction will definitely stir up some exciting interaction and new prospects in the industry. In the coming months as, fingers crossed, the world introduces more flexibility and freedom, our work and

personal lives will take on a new version of themselves. While speaking with a client last week they mentioned how “COVID has no time.” He has found himself in virtual meetings at 10pm, 2am, and 7am on a frequent basis. COVID-19 essentially has removed time zone barriers and the hassle of organising rendezvous points for those necessary social calls. There’s swings and roundabouts with everything – a 2am meeting sounds anything but fun, though to switch on your computer in your house and instantaneously be at the meeting makes it undeniably convenient. A work from home novelty that shall surely be incorporated into companies as routines change and new normalities are determined. To prevent this comment becoming a proclamation of my enjoyment of work from home life and my failure to book any successful holidays this year, let me direct you to the insightful articles this issue has on offer. Adapting to the pandemic, Technip Energies (p.49) outlines the solutions for collaborative operator training, utilising virtual reality and digital simulators in a time when training cannot always take place on-site. On a similar note, when considering the need for LNG operators to keep their workforce safe, Cyberhawk (p.52) explains how drone technology can enable LNG infrastructure to be inspected with precision without endangering the workforce. Over the last 18 or so months, the stories of LNG companies and their employees adapting and achieving while in times of the unknown have been encouraging to hear. If you have a project success story to share or a creative solution to a problem being encountered in the LNG sector, I would love to hear from you so do get in touch.

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LNGNEWS Bangladesh

Canada

Mammoet-Haisla JV successfully reaches next milestone at LNG Canada

ammoet-Haisla joint venture (JV) has announced it has completed the pile handing scope for the LNG Canada project through JGC-Fluor JV in Kitimat, British Columbia, Canada. This project will export LNG and put Canada on the global map of LNG exporting countries. Mammoet-Haisla JV provided offloading services for incoming pipe piles throughout the pandemic, completing the scope in March 2021. Over the course of a year, teams offloaded, transported, and placed 6513 piles. This required 16bmobilisations and demobilisations, 39 078 chains to secure the piles, and over 50 000 working hours on-site. In addition to adjusting and adhering to constantly-changing COVID-19 safety protocol and local restrictions, teams were also faced with adverse weather conditions. Being on the coast of Western Canada throughout the winter season, personnel saw upwards of 518 days of precipitation during this scope alone. Under the agreement, the Mammoet-Haisla JV scope includes receiving all oversize equipment and modules at the project’s Materials Offloading Facility (MOF), transporting them to the build site, and lifting them onto final foundations. Over the span of three years, Mammoet-Haisla JV will be responsible for the horizontal and vertical movement of more than 350b000bt of equipment, the largest items weighing greater than 10b000 t each. Mammoet continues to work with the Haisla First Nation as partners and draw on the company’s broad expertise as an industry leader to effectively deliver major LNG projects worldwide, including in the US, Australia, and Russia.

H-Energy signs MoU for regasified LNG supply

chieving a major milestone for supply of regasified LNG from India to Bangladesh, H-Energy signed the Memorandum of Understanding (MoU) with Petrobangla on 16 June 2021. The companies will soon finalise a long-term supply agreement to commence the supply of regasified LNG to Bangladesh through a cross border natural gas pipeline. H-Energy was authorised by Petroleum and Natural gas Regulatory Board (PNGRB), the regulatory body in India, to build, own, and operate the Kanai Chhata-Shrirampur natural gas pipeline connecting H-Energy’s LNG terminal in West Bengal passing through various regions of the state and further connecting to the Bangladesh border, to enable cross-border supply of regasified LNG into Bangladesh. H-Energy is the only company to have received the authorisation from PNGRB to lay a pipeline to the Bangladesh border. Mr. Darshan Hiranandani, CEO of H-Energy said “This is a key milestone in the future of Indo-Bangladesh energy co-operation. I am grateful to the Government of Bangladesh, the team at Petrobangla, and the various governmental agencies of India whose unstinted support has made this happen. Our objective is to deliver environmentally friendly, safe, and economical energy to the state of West Bengal and to Western Bangladesh. Thanks to the efforts of all stakeholders, most permissions are in place and we shall see important milestone after milestone in this project happen at a rapid pace.” H-Energy’s wholly owned subsidiary HE Marketing Private will be responsible for sourcing LNG and for supplying regasified LNG to Petrobangla. Within Bangladesh, Petrobangla will supply this regasified LNG to gas-based power producers and other gas consumers.

Singapore

bp Singapore and Pavilion Energy sign SPA

avilion Energy Trading & Supply Pte. Ltd (Pavilion Energy) and bp Singapore Pte Ltd have signed a long-term LNG Sales and Purchase agreement (SPA) for the supply of approximately 0.8bmillion tpy of LNG to Singapore for 10 years from 2024. Beyond the supply of LNG to Singapore, both companies will strive to co-develop and implement a greenhouse gas (GHG) quantification and reporting methodology. The

July 2021

methodology will cover emissions from wellhead-to-discharge terminal and be principled on mutual transparency and the adherence to relevant international standards. Mr Frédéric H. Barnaud, Group CEO of Pavilion Energy, said, “This agreement further strengthens our relationship with bp as Pavilion Energy advances our strategies for a lower carbon future, beginning with GHG emissions quantification, reduction, and offsets for Singapore.”

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LNGNEWS Canada

Brazil

Wilson Sons sees business opportunities for maritime support with New Gas Law

ith the New Gas Law in Brazil, sanctioned on 8bApril, LNG will have a relevant role in the national market. Among the main advantages of the fuel are the competitive prices, in addition to the flexibility of origin. And the opportunities in this industry also bring favourable winds to the port support sector. Wilson Sons, a large operator of maritime and port logistics in the Brazilian market, is prepared to meet the growth of this market. In the last year, the company's Towage division carried out more than 25 special operations, which included services to the natural gas or LNG sector, as support for gas carriers and FSRUs, and also to the oil and gas sector in support of FPSOs and drilling rigs. Among the customers served by Wilson Sons tugs in this segment is Celse (Centrais Elétricas de Sergipe), which operates the Port of Sergipe Thermo-electric Power Plant (TPP). With 1.5 GW of installed capacity, the Sergipe TPP is supplied by a regasification terminal, capable of storing up to 170 000 m3 of LNG and regasifying up to 21bmillion m3/d of gas. To give you an idea, the BoliviaBrazil gas pipeline, one of the most important in the country, can transport 30 million m3/d. LNG terminals are also seen in Brazil as an alternative for monetising pre-salt gas. Data from the Brazilian Petroleum Institute (IBP) show that the new Gas Law can generate investments of up to R$17.1 billion for the construction of natural gas processing units and LNG terminals. Other opportunities are the projects involving cabotage and the commercialisation of LNG on a small scale. The objective is to meet the demand for gas in the interior of the country, where there are no gas pipelines to carry the fuel. “Currently, gas reaches a very restricted territory, but with new measures for the sector and greater investment in infrastructure for its flow, it will be possible to transport LNG in larger volumes at competitive prices. It is an alternative to firewood, coal and also gasoline, diesel, and heavy oil”, highlights Lucas Buranelli, LNG terminal Operations Manager at Celse.

July 2021

Wärtsilä to power LNGfuelled escort tugs

ärtsilä will supply the main engines and LNG fuel gas supply systems for two new LNG-fuelled escort tugs being built for Canada’s HaiSea Marine, a joint venture between the Haisla Nation and Seaspan Marine Transportation. The ships have been designed by Robert Allan Ltd Naval Architects and Marine Engineers, and are under construction at Sanmar Shipyards in Turkey. They are expected to be two of the most environmentally advanced escort tugs operating in the coastal waters of British Columbia in Canada. The order with Wärtsilä was placed in April 2021. The two vessels will each be powered by Wärtsilä 34DF dual-fuel engines operating with LNG fuel. The engines will be fitted with Wärtsilä’s NOx selective catalytic reduction (SCR) system to restrict emissions of nitrogen oxides. Wärtsilä will also supply its LNGPac fuel storage, supply, and control system. The Wärtsilä equipment is scheduled for delivery to the shipyard in 2022. Wärtsilä has previously delivered similar equipment for two in-service ferries operated by Seaspan Ferries, another Seaspan affiliated company. The successful performance of these ferries and Wärtsilä’s lifecycle support capabilities in Canada were cited as being important considerations in the award of this contract.

THE LNG ROUNDUP X Wood Mackenzie: China to overtake Japan as world’s largest LNG market X New authorised service provider for NCS in the Kingdom of Saudi Arabia X Titan LNG commissions short-term LNG truck loading facility Follow us on LinkedIn to read more about the articles

www.linkedin.com/showcase/lngindustry

LNGNEWS Senegal

Russia

KARMOL’s FSRU arrives in Dakar

Keel-laying ceremony held for Arctic LNG 2 carrier

ARMOL’s first FSRU has arrived in Dakar, Senegal, marking a major step forward in Karpowership’s LNG-to-power project to supply reliable, affordable, and cleaner energy to the country. The FSRU travelled from Singapore, where it was constructed in a 50/50 joint venture between Karpowership and Japanese firm Mitsui OSK Lines, called KARMOL. This is the first completed FSRU from the KARMOL partnership. The FSRU, KARMOL LNGT Powership Africa, arrived in Senegalese waters on 31 May and will be positioned at its mooring location to commence the commissioning process. The vessel will connect to a Powership, a floating power plant, owned by Karpowership, through gas pipelines. The Karadeniz Powership Aysegu¨l Sultan, has a capacity of 235 MW and has been in operation since October 2019, supplying 15% of Senegal’s electricity with 220 MW of power to Senegal’s grid. Karpowership sees the combination of FSRUs and Powerships as a ground-breaking solution in its mission to bring LNG utilised power generation to countries with no natural gas infrastructure or supply. The FSRU, which was developed by Sembcorp Marine in Singapore, is 272 m long and has a capacity of 125b000bm3. The FSRU arrived with a supply of LNG onboard and the first refuelling will be carried out by Shell in July.

n 15 June 2021, a keel-laying ceremony was held at Zvezda Shipbuilding Complex, in the Russia’s Far East, for a new Arctic LNG carrier ordered by PAO Sovcomflot (SCF Group). This is the lead vessel in a series of 15 carriers, ordered from Zvezda, for servicing the Arctic LNG 2 project. This is the first ever vessel of such dimensions, cargo capacity, and icebreaking capabilities to be constructed at a Russian shipyard. This lead vessel of the series is owned by SCF, while the remaining 14 ships are owned by SMART LNG, a joint venture between PAO Sovcomflot and PAO NOVATEK. All vessels in the series will operate under long-term time charter contracts with Arctic LNG 2. Their construction is being financed by VEB.RF. All 15 carriers will operate under the Russian flag, meanwhile the shipbuilding process is being supervised by the Russian Maritime Register of Shipping (RS) and Bureau Veritas (BV). This series of ice-class Arc7 vessels is designed for the year-round transportation of LNG in the challenging conditions along the Northern Sea Route, including its eastern sector. Importantly, these vessels will have increased icebreaking capabilities and manoeuvrability in the ice, when compared to the first generation of icebreaking LNG carriers (Christophe de Margerie series). Each LNG carrier will be 300 m long, 48.8 m wide, and will have a cargo capacity of 172 600 m3. The propulsion system includes three azimuth propulsion units, with a total power capacity of 45 MW.

23 - 25 August 2021

21 - 23 September 2021

04 - 06 October 2021

Canada Gas & LNG Exhibition & Conference 2021

Gastech Exhibition & Conference 2021

ILTA

Vancouver, Canada

Dubai, UAE

https://ilta2021.ilta.org

www.canadagaslng.com

www.gastechevent.com

21 - 22 October 2021

15 - 18 November 2021

30 November - 03 December 2021

Downstream USA

ADIPEC

Houston, USA

Abu Dhabi, UAE

21st World LNG Summit & Awards Evening

www.reutersevents.com/events/downstream

www.adipec.com

Rome, Italy

Houston, USA

www.worldlngsummit.com

July 2021

Bruce Robertson, IEEFA, Australia, explains how climate risks, competition, falling demand, and legal challenges are strong headwinds for Australia’s LNG industry.

he Australian LNG industry faces headwinds in 2021 due to new climate commitments from major customers, falling demand, legal risks, and competition from Qatar. In addition, the International Energy Agency (IEA) has adopted a new position on ‘natural’ gas which is far from its former place of gas as a transition fuel with demand increasing. It now sees gas as an industry in decline. New climate commitments by major gas and LNG importing nations are, over time, likely to result in lower global demand for gas. The US is already seeing falling demand and Australia has experienced lower demand since 2014. Coupled with increased climate risks, the Australian LNG industry faces significant legal risks highlighted by the recent Sharma vs Minister for the Environment judgement. Australian LNG also faces competitive risks from Qatar, the global low-cost LNG supplier. Qatar is planning a 64% increase in production which will place pressure on prices. Balanced against all of this is the substantial nature of Australian government subsidies. Australia’s gas industry cannot survive without large government investment and these subsidies are merely prolonging the inevitable decline of gas as a fuel in the energy system. With demand now in decline and climate deadlines nearing, investors must be aware of the high likelihood of gas assets in Australia becoming stranded.

International Energy Agency foretells end of gas The IEA has traditionally been captured by the fossil fuel industry and blind to the revolution that has occurred in the way people produce and consume energy. This

Figure 1. Official gas emissions. Source: Department of Industry, Science, Energy and Resources; Australia’s Emissions Projections 2020.

the harm caused by climate change in the approvals process of fossil fuel-related projects. In closing, Justice Mordecai Bromberg said there is evidence of the “severe harm” climate change can cause future generations. “It will largely be inflicted by the inaction of this generation of adults, in what might fairly be described as the greatest intergenerational injustice ever inflicted by one generation of humans upon the next,” Bromberg said. Whilst the court refused an injunction of a forthcoming approval for a coal mine extension, the possibility of it granting one remains open. The effect of this landmark judgement was neatly summed up by prominent environmental lawyer Elaine Johnson from Australia’s Environmental Defenders Office: “When you start to contemplate the effect of the Sharma judgement on new fossil fuel projects in Australia, it’s fair to say that the future of all such projects is now in doubt. Fossil fuel projects are now highly vulnerable to legal challenge.”

Qatar plans large expansion of cheap LNG

Figure 2. Total domestic consumption of gas in Australia has declined. Source: AEMO.

positioning recently changed with the release of its report ‘Net Zero by 2050 – A Roadmap for the Global Energy Sector’; a report peer reviewed by Shell and ENI with BP as a contributor. IEA’s report came to the startling conclusion that the world has to get off gas. In summary the IEA stated that: z Beyond projects already committed as of 2021, there are no new oil and gas fields approved for development in the major pathway. z Many of the LNG liquefaction facilities currently under construction or at the planning stage are not needed. z Betweenb2020bandb2050, gasbtradedbasbLNGbwill fallbbyb60%. z During the 2030s, global gas demand will decline by more than 5% per year on average, meaning that some fields may be closed prematurely or shut temporarily. The IEA concludes that the gas industry will decline by 5% per annum compound and stranded assets will abound. Essentially, the IEA is ringing the bell that gas is now a declining industry globally.

Climate change legal risks are rising following Sharma vs Minister for the Environment Eight teenagers and an 86-year-old nun acting as their legal guardian recently sued Australia’s Federal Minister for the Environment claiming that the Minister owed them a “duty of care” to protect young children from the harms induced by climate change. The Federal Court of Australia made a ruling that the country’s Environment Minister has an obligation to consider

July 2021

Qatar, the world’s biggest LNG exporter until last year,bhas advisedbit will push ahead with a huge expansion of capacity, taking it from 77 million tpy to 110 million tpy by 2025, then potentially to 126 million tpy just two years later. Qatar is looking to develop its North Field, a field shared with Iran who has already pushed ahead with development. This 64% expansion from the world’s lowest cost LNG producer will make development in higher cost fields more problematic. Qatar has also cut prices by approximately 22% to secure new customers. A recent deal was struck with Sinopec at a ‘slope’ or index against crude oil of just 10.19%. Qatar is a very low-cost producer and can comfortably afford to cut the price of LNG. According to Wood Mackenzie: “At a long-term breakeven price of just over US$4/million Btu, Qatar’s LNG production is at the bottom of the global LNG cost curve, alongside Arctic Russian projects.” Qatar is not only looking to price to garner customers, it is also looking at producing lower emitting LNG via building facilities capable of capturing and storing 7 million tpy of emissions by 2030. In November 2020, Qatar Petroleum signed the world’s first deal that details the carbon dioxide pollution of each cargo shipped to the buyer in Singapore. Qatar Petroleum plans to reduce the amount of greenhouse gases (GHG) it emits from its LNG plants by 25% and upstream operations by 75% by 2030 via cutting flaring and reducing methane leakages to 0.2%.

LNG emissions LNG is a significantly higher emitting fuel than piped gas. In Australia, over 9% of gas is consumed at LNG facilities in order to ‘super cool’ the gas down to -160˚C.1 A further 2%b-b6% of methane is lost or burnt in the shipping process. In sum, approximately 13% of the gas is lost or burnt prior to it being regasified in the importing nation (typically in Asia). This higher emissions nature of LNG will make it a less preferred fuel as the world accelerates efforts to decarbonise.

Emissions intensity In a recently released paper, the Institute for Energy Economics and Financial Analysis (IEEFA) estimates that between 2014

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(the faint pink line at the bottom of the graph) were sourced from several cherry-picked wells by the Gas Industry Social and Environmental Research Alliance (GISERA), which is the gas industry funded, gas industry controlled arm of Australia’s science agency, the CSIRO.bThey are not in line with the experience in other parts of the world.

Demand and capacity factor reduction Figure 3. US natural gas consumption by sector, net change from previous year (2018 - 2022). Source: US Energy Information Administration.

Figure 4. Cost stack of select LNG projects (DES to Asia). Source: Wood Mackenzie; Australia Oil & Gas Industry Outlook Report.

and 2019, the emissions intensity of Australia’s gas production increased by approximately 30% as newer projects released higher rates of GHG emissions. The average amount of GHG associated with gas production increased from 0.54 t of CO2-e per t of LNG produced, to 0.7 t of CO2-e per t of LNG produced. The original fields that supplied projects in the north of Western Australia (North Rankin and Goodwyn fields) have low reservoir CO2 (3 v%). However, a further, similar steep increase in emissions is likely to be repeated when the five original fields in the North West Shelf of Western Australia finally deplete their currently producing reservoirs and gas is piped (as foreshadowed by Woodside) from the Browse area 900 km away. Those fields are reported to contain 10 - 16 v% CO2 and in combination with compression for the long pipeline, make them far more emissions intensive than the original fields that supplied the project.

Emissions from venting and flaring are growing faster than production The gas industry has expanded venting and flaring at a far faster rate than its expansion in production. Between 2014 and 2020, the gas industry expanded production from 691 PJ to 1916 PJ, an increase of 177%.2bOfficial venting and flaring emissions rose by 300% during this period, far in excess of the increase in production.3 Official figures from the Australian Government Department of Industry, Science, Energy, and Resources assume there are no other emission leaks apart from those occurring with the flaring and venting of gas.bThis is an assumption that does not stand up to scrutiny. In Figure 1, the figures used for emissions from other leaks such as fugitive emissions and those in the supply chain

July 2021

Both domestically and globally, there are signs showing that gas demand has peaked. In Australia, total domestic consumption of gas is down 16% since 2014 (Figure 2). Declines have been more pronounced in the gas-fired electricity generation sector where gas usage has declined by 42% since 2014. The decline in gas-fired generation has occurred despite the rapid uptake of renewable energy. Renewables now account for 28% of generation in Australia’s National Electricity Market (NEM). Australia’s federal government is doing everything in its power to reverse the declining usage of gas. It recently progressed the building of the 660 MW Kurri Kurri gas-fired peaking power plant based in New South Wales (NSW) by the government-owned company Snowy Hydro. As well as the AUS$610 million to build the Kurri Kurri plant, the federal government gifted Chinese-owned EnergyAustralia AUS$83 million to build the 316 MW Tallawarra B gas plant near Wollongong in NSW, which is approximately 25% of the cost. The government also gifted Andrew ‘Twiggy’ Forrest, the well-known Australian billionaire, AUS$30 million to assist in the building of his 650 MW gas plant also in Wollongong. In total, the federal government is currently subsidising gas-fired powered generation in NSW to the tune of AUS$723 million to build a significant 1700 MW of gas plants that Australia simply does not need. In addition to demand reduction, there is also massive latent capacity in Australia’s gas peaking power stations. Capacity utilisation of gas peaking plants has fallen from 15.5% in 2014 to just 6.5% in 2020. Snowy Hydro itself owns the Colongra gas peaking plant near Kurri Kurri. It had a capacity utilisation of just 0.9% in 2020.

US gas demand Gas demand fell in the COVID-affected year of 2020. Interestingly, the US government’s Energy Information Administration (EIA) is forecasting a rebound in industrial and residential consumption offset by a large fall in gas powered generation. Overall, the US domestic market is expected to decline in the future as renewable energy eats into gas’ market share.

Global LNG demand Globally, nations are coming to grips with their newfound climate commitments. As outlined in the IEA roadmap, there is no room for more gas in a carbon constrained world. Over time it is expected that this will translate into lower demand in important South-east Asian markets.

Key new gas field developments in Australia The key new gas field developments in Australia include Barossa and the Beetaloo in the Northern Territory, the Scarborough gas field in Western Australia, and the Narrabri

gas project in NSW. They are by no means the only new gas field developments as there are also new onshore fields being developed in all states and territories of Australia, with the exception of the Australian Capital Territory and Tasmania. The development of new gas fields is incompatible with any meaningful climate commitments.

growing LNG market – Australian companies have more limited customer opportunities. Given that the Pluto expansion is for 6.5 million tpy, only 31% of the project’s output is contracted. Typically for a project to proceed, greater than 80% of volumes need to have found long-term customers.

Barossa, Northern Territory

The Beetaloo, Northern Territory

In good news for the LNG industry in Australia, the Barossa gas field located offshore Northern Territory gained Final Investment Decision (FID) from Santos and SK E&S on 30bMarch 2021. The US$3.6 billion project extends the life of the 3.7bmillion tpy Darwin LNG facility which has been sourcing its gas from the Bayu-Undan field, a field that is running out of gas. Barossa is the highest emitting gas and LNG project on the globe. Field emissions of CO2 are so high that John Robert, IEEFA guest contributor, quipped that: “The Barossa to Darwin LNG project looks more like a CO2 emissions factory with an LNG byproduct.” Santos is exploring the potential of carbon-neutral LNG from Barossa. In the meantime, it will vent the CO2 from the field. Santos recently received a AUS$15 million grant from the federal government to build a carbon capture and storage facility at Moomba. The CO2 will be used for enhanced oil recovery, however Moomba is too far from Barossa to capture its emissions.

The federal government is looking to the Northern Territory as one of its key areas of expansion under its gas-fired recovery. In January 2021, the government announced it was pouring AUS$173 million into road infrastructure in the Beetaloo basin and a further AUS$50 million directly into subsidising gas exploration wells. The drilling in the Beetaloo is recommencing this dry season after COVID and low prices halted development. Companies such as Tambouran Resources, Santos, Origin Energy, Empire Energy, and Falcon Oil and Gas are all vying for a share of the government’s largesse. Subsidies for new projects are not uncommon in Australia, however direct subsidisation of high-risk exploration wells is rare.

Scarborough, Western Australia The remote Scarborough field off Western Australia was discovered in 1979. Woodside proposes to develop the Scarborough gas resource through new offshore facilities connected by a 430 km pipeline to an expansion of the existing Pluto LNG facility on the Burrup Peninsula (Pluto Train 2). The Pluto Train 2 LNG brownfields expansion would have a capacity of approximately 5 million tpy. At an Australian Petroleum Production and Exploration Association (APPEA) conference in May 2013, in the days when ExxonMobil was a stakeholder in the Scarborough gas field, Exxon Executive Mark Nolan was reported as saying that the Scarborough project will be “very challenged from a cost point of view.” Scarborough contains very dry gas so there are no liquids to improve the economics of the project. The field is shallow and broad and will require expensive deepwater horizontal drilling – according to Exxon. In a report by Wood Mackenzie dated 9 March 2020 (commissioned by APPEA), the Pluto expansion project, utilising gas from Scarborough, is the most expensive at over US$9/million Btu delivered to Asia. The increasing competition globally puts even greater pressure on the economics of the Scarborough gas field and Pluto LNG expansion. Woodside has struggled to secure long-term contracts for its Scarborough gas expansion. In January 2021, Woodside announced an expansion of the binding 13-year Sales and Purchase Agreement (SPA) with Uniper of Germany. Initial supply commencing in 2021 is for a volume of up to 1bmillionbtpy increasing to 2 million tpy from 2026. The initial agreement with Uniper was struck over a year ago in late 2019. Woodside has been unable to attract any other customers. With the frosty relationship that currently exists between Australia and China – which is the fastest

Narrabri, New South Wales Santos’ controversy-plagued Narrabri gas project appears to have stalled following its final approvals in November 2020. Pipeline access appears to have been the problem with APA not submitting its Environmental Impact Statement by 4 May 2021 for its Western Slopes Pipeline to connect Narrabri with the Eastern gas grid. There appears to be little progress by APA on this project. The federal government is looking to subsidise the other gas pipeline that could connect Narrabri into the gas grid, which is the Queensland Hunter Gas pipeline (QHGP). The QHGP was first approved in 2009 but the company will need significant government support to get its pipeline built. It is likely that government support will be forthcoming to facilitate the Narrabri gas project.

Conclusion The LNG industry in Australia faces an increasingly competitive global market placing pressure on profitability. The government is looking at providing considerable support for the industry in the form of offtake agreements, subsidies for exploration and infrastructure, and legislative support. In the end, it is likely that the failing economics of gas will overwhelm government support. Investors need to understand the existential risks to their capital if they choose to employ it in the LNG industry.

References 1.

Department of Industry, Science, Energy and Resources, Australian Energy Update 2020, September 2020.

AEMO. Gas forecasting portal. 2021.

Department of Industry, Science, Energy and Resources, Australia’s emissions projections 2020 Chart Data Spreadsheet, 2020.

Note The views expressed herein are those of the author and not necessarily the views of IEEFA, its management, its subsidiaries, its affiliates, or its other professionals.

July 2021

Figure 1. The Stirling Cryogenics micro scale integrated purification and liquefaction plant.

he fast-growing use of LNG as a fuel for maritime and road transportation has increased the need for proven cryogenic technologies and solutions on a global scale. This novel market is pushing for a decentralised, flexible, and smaller scale LNG supply chain. This translates into developments such as LNG satellite storages and bunkering facilities, away from production facilities or terminals needing local small scale production of LNG. Critical success factors for the infrastructure are autonomous remote operation as well as energy efficient, modular, and reliable cryogenic cooling systems. The combination of all these factors have created opportunities for Stirling Cryogenics to prove its worth. Stirling Cryogenics is currently active in two different LNG applications: boil-off gas (BOG) management and micro scale LNG production.

Boil-off gas management BOG management is an iterative process. Storage tank volume, storage tank heat leak, composition of the BOG, management of non-condensable gases, systems layout and spatial constrains, desired output, operating pressure, engineering standards or notified bodies approval; all these parameters have their

share of impact on BOG management. In designing the BOG management system, the main questions to be answered are: what is the expected boil-off rate? What is the maximum allowable and the required pressure of the LNG? What is the desired holding time? How can we handle the non-condensable gasses to avoid build-up and poor LNG heating value? In response to the market’s demand for retrofit solutions that can be implemented with minimum impact on the existing structures, Stirling Cryogenics developed a turnkey, containerised solution with a lead time shorter than one year. The only connections needed are BOG and LNG lines and electrical supply. The needed space is as limited as can be and easily dimensioned. The BOG management solution of Stirling Cryogenics is suitable for onshore and offshore storage tanks. Onshore storage tanks usually concern small scale LNG terminals or peak shaving facilities. Offshore storage tanks concern bunkering barges or small LNG carriers. Stirling Cryogenics adapted the technology to maritime conditions in 1990 when the Stirling machines were installed on the Tonen Ethylene Maru to manage BOG. The ethylene is transported as a (flammable) liquid at -104˚C. BOG coming from

Peter Lamberts, Stirling Cryogenics B.V., the Netherlands, explores the aspects of boil-off gas (BOG) management and the growing presence of micro scale LNG in the future.

the tanks is reliquefied by three 4-cylinder cryogenerators. The units have been in operation until the ship, and the Stirling machines, were decommissioned after many years of excellent service. In order to meet the maritime demand, Stirling Cryogenics optimised its cryogenerators for roll and pitch requirements, according to ABS, BV, and USCG standards (or others upon request). As space and redundancy are of the essence for maritime applications, BOG management solutions based on Stirling Maritime Cryogenerators offer multiple advantages: small

Figure 2. Typical set-up for BOG management through direct reliquefaction.

footprint per unit (1.75bmb×b0.75 m × 1.22 m), easily scalable system set-up, and a plug and play design. The capacity ‘sweet spot’ of the Stirling solution lies between 6 - 100 kW in cooling power, or between 1b-b15btpd of BOG management. The suitable capacity depends on the required equilibrium within the tank (either standard cylindrical tank, Type C, or membrane tanks) and can be reached by installing Stirling machines in parallel. There are two concepts for managing BOG in storage tanks: direct reliquefaction and subcooling.

Direct reliquefaction of BOG In this concept the gaseous BOG is fed to the Stirling machine and is reliquefied at its equilibrium saturated temperature and pressure so there is no pressure change. As the driving forces are the pressure difference and gravity, it is required that the Stirling machine is placed on a level higher than the LNG storage tank. The cooling of the LNG can be a continuous process. The control system will monitor the pressure of the tank, to start and stop the Stirling machines when the pressure in the storage tank reaches a pre-set level. The non-condensable gases (i.e nitrogen, helium, etc.) can be efficiently managed from the BOG during the reliquefaction of the BOG, which will prevent these non-condensables from accumulating in the tank over time. The Tote bunkering barge, Clean Jacksonville, built by Conrad and operating in the Port of Jacksonville, Florida (US), has a 2200 m3 GTT Mark III Flex technology cargo tank on board. Stirling machines are placed on top of the tank to ensure that the pressure is kept low, as well as the temperature of the liquid. Operational deployment was in 2018 and the units have been running successfully since.

Subcooling of BOG

Figure 3. Stirling cryogenerators for direct LNG reliquefaction installed inside the Clean Jacksonville bunker barge.

Figure 4. The LNG London bunker barge.

July 2021

The second concept to manage BOG is subcooling. This concept is based on an effective method of reducing pressure in a storage tank by spraying – a method widely used in the cryogenic industry when tanks contain warm liquid. LNG is taken from the bottom of the tank and pumped through the heat exchanger of the Stirling machine. Here energy is extracted and the LNG will be subcooled to a specified temperature. This subcooled LNG is then sprayed via nozzles into the gas area at the top of the tank and by this process the gas pressure is reduced and the liquid is cooled. The bunker barge LNG London, operating in the Port of Rotterdam, the Netherlands, is equipped with a 3000 m3 TypebC tank and uses subcooling as the method to manage the BOG. Since its operational deployment in July 2019, the LNG London has completed more than 200 successful bunkering sessions. Each concept has its own specific benefits; the choice depends on installation possibilities, circumstances, and requirements of the total LNG tank system. However, they have the financial efficiency of the Stirling machines in common. If they are not operated, for instance after a new tank filling of the bunkering vessel, there is no energy needed so operational costs can be avoided. Recently, Stirling has contracted the supply of the BOG management equipment of the new-build bunkering barge that will be taken into operation in Barcelona, Spain, in 2022.

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The Stirling cycle The Stirling cycle is a thermodynamic closed cycle invented in 1816 by the Scottish minister Robert Stirling. It was used as an engine and was considered at the time to be capable of replacing the steam engine. The counterpart of the Stirling engine, the refrigerator, was first recognised in 1832. The principle behind the machines was almost condemned to obscurity after the invention of the internal combustion engine. In 1938 the Dutch Philips Research Laboratory was looking for a means to power electricity generators for short wave communication systems in remote areas without electricity supply. The Stirling engine attracted their attention. In 1946 Philips started optimising the Stirling cycle to be used for cryogenic cooling, and the result was the development of the Stirling Cryogenerator. The Stirling cycle alternately compresses and expands a fixed quantity of helium in a closed cycle. The compression takes place at room temperature to facilitate the discharge of heat caused by compression, whereas the expansion is performed at the cryogenic temperature required by the application. The Stirling cycle is remarkable because it is a closed cycle in which the Cryogenerator’s internal working gas (helium) never comes into contact with the fluid to be cooled; they connect only by flow of heat through the heat exchanger wall. This concept eliminates contamination of the customers’ process as well as of the Stirling cycle working gas, resulting in long continuous operating periods and longevity.

Figure 5. Typical set-up for BOG management through subcooling.

The combination of high-efficiency, small footprint, and low operational cost were the decisive arguments to choose the Stirling Cryogenics subcooling BOG management solution for this 5000 m3 bunkering barge.

Micro scale LNG production In the last decade the use of LNG as an automotive fuel for long haulage heavy duty transportation has become popular. The reasons to move away from diesel vary from making transportation more environmentally friendly to simply using a cheaper fuel. With this development a need has arisen for local small and micro scale LNG production from local sources. These sources can be biogas production plants, landfills producing biogas, natural gas wells, or even natural gas pipelines. The sources vary widely in different geographical regions. Stirling Cryogenics has developed an integrated gas purification and liquefaction plant for micro scale at a maximum of 30 tpd. This has been achieved together with sister company Hysytech Srl, which specialises in gas purification technology. The design can be made suitable for any kind of natural gas or biogas. The plant is completely assembled in Stirling Cryogenics’ workshop and fully containerised. This makes the plant easy to transport and installation on-site can be undertaken in the shortest possible time. The plant is of a turnkey design and includes not only the necessary equipment for purification and liquefaction but also the chiller to reject the heat from the gas, equipment for process analysis and controls, and a pressure transfer device. On-site, connections only need to be made for power, the feed gas, and the LNG storage tank. A Stirling machine typically produces 1 tpd of LNG. The required capacity is reached by adding the right quantity of Stirling machines. Due to this modular design the Stirling liquefaction plant is very suitable for future scale up. Stirling has ready-made designs where all infrastructure is prepared for a larger capacity but with a lower than maximum number of Stirling machines. These can be added later once the business grows. The modular design also has the advantage that machines can be switched off in case of lower required production due to, for example, an interruption in the gas feed or a (temporary) lower demand for LNG. Here the energy efficiency (kWh/kg of LNG) of the plant will always be optimal. In 2021, Stirling will deliver four commercial plants for LNG production in the range of 10 tpd. It can be considered the breakthrough in the market of local on-site LNG production. Considering that the number of micro scale liquefaction plants worldwide is currently no more than 10, Stirling is a serious player in this market.

Future plans

Figure 6. Stirling cryogenerators for LNG subcooling installed on the LNG London.

July 2021

Stirling sees a bright future for micro scale LNG production. For many years the market was trapped in the chicken or egg discussion, potential producers were waiting for the demand, and the users (trucking companies) were waiting for a cheap and reliable supply. It seems that this cycle has been broken and Stirling is dedicated to play a major role. During 2021 Stirling is planning to develop a machine with a larger capacity without a significant increase of the price. This will further enhance the feasibility of projects and enable realisation of plans that have been shelved in the past years.

Dr Joey Walker, EffecTech, UK, looks at how to improve and optimise existing sampling systems for LNG inspection.

NG production and trade has been on a significant growth curve over the past decade. In 2020, global LNG demand reached 360 million tpy and this is expected to double by the year 2040.1 The success of LNG as a key contributor to the energy mix can be attributed to its flexibility and resilience, especially during the 2020 economic hardship caused by the COVID-19 outbreak. What remains an unknown is how accurately LNG volume and physical properties can be measured, which, when combined, produces a final total energy value for custody transfer agreements. A small error in final energy measurement can translate to significant financial risk on both sides of the contractual agreement. The general practices of measurement adopted by the natural gas industry are difficult to apply to LNG because it is a cryogenic liquid. Industry has responded to this issue by producing equipment and instrumentation suitable for measurement in the cryogenic liquid phase, however the development, calibration, and testing of such apparatus requires many years of research and collaboration. Industrial operators are likely to remain conservative in their approach to new measurement technology, therefore existing sampling system installations are expected to remain unchanged or replaced, unless they are proven to be inadequate. EffecTech, which already offers performance evaluations for natural gas instruments to ensure confidence in measurement, has focused on how to improve and optimise existing sampling

systems using a combination of thermodynamic modelling and Monte-Carlo simulations, as part of the development of a sampling system inspection service for LNG customers.

How to sample and measure LNG When LNG is loaded onto a cargo ship and is transported over significant distances, it undergoes a natural boiling process as a result of the natural heat influxes that penetrate the storage vessel, generally referred to as ‘ageing’.2 This boiling process produces a vapour phase that is rich in lighter hydrocarbons, therefore having a different composition to the liquid phase. Consequently, the quality characteristics of the LNG have changed. This necessitates the requirement to measure the LNG composition during onloading and offloading processes to account for the difference in composition, such that the correct monetary value can be allocated. The more accurately the composition is determined, the lower the risk that is incurred on both sides of the contractual agreement. The current method for measuring LNG composition requires taking a sample, vaporising it, and measuring it with a gas chromatograph. This is a very challenging process since the LNG must undergo a phase transition from a cryogenic phase to

room temperature conditions suitable for chromatographic analysis. The complexity of LNG sampling systems has resulted in the development of international standards and guidelines that provide best practices from industry. ISO 8943-20073, BS EN 12838 – 20004, and the GIIGNL custody transfer handbook5 are the leading reference materials that cover methods for LNG sampling, conditioning, and measurement. The main components that make up an LNG sampling system include: the sampling line, vaporiser, gas homogeniser, sample cylinders, gas chromatograph (GC), and auxiliary equipment such as control valves, compressors, and temperature sensors. The most common way to take an LNG sample is with a sampling probe which is inserted directly into the LNG loading/unloading transfer lines. Once the LNG is sampled and vaporised, the gas is either continuously fed into gas sample holders for offline analysis, known as continuous sampling, or the gas is continuously fed into a constant pressure floating piston (CP/FP) cylinder and partly directed to a GC for real-time measurements, known as intermittent sampling. The choice of sampling procedure is stipulated in contractual agreements; however, the intermittent sampling method has become more obsolete for custody transfer since it has more moving parts.

What type of sampling issues can be encountered? LNG sampling probes require suitable insulation to prevent external heat from penetrating the cryogenic liquid. Some heat may be absorbed by the sampling line from the surroundings as the LNG is sampled, however the amount of heat should never exceed that which would increase the temperature of the LNG to beyond its bubble point. Sampling probes are normally combined with an in-line vaporiser which is responsible for fully converting the cryogenic LNG to ambient temperature gas. If the LNG is permitted to boil before it reaches the vaporiser, lighter hydrocarbons and nitrogen will preferentially boil-off resulting in a partially fractionated liquid, as illustrated in Figure 1. Fundamentally, the LNG composition has changed and this will be reflected in the measured gas composition. At this point, the LNG is not representative of the source from where it was sampled.

Figure 1. Illustrating the partial fractionation of LNG as it absorbs heat (Qin) from the surroundings. A

Reducing the likelihood of LNG prevaporisation There are a number of ways to mitigate the pre-vaporisation of LNG. Primarily, the aim is to maximise the degree of subcooling

Figure 2. Illustrating the impact of pressure and temperature on subcooling capacity of LNG. A generic LNG composition and general sampling parameters have been selected for this illustration. (A) shows a high sampling temperature, low pressure case that fractionates; (B) shows a high pressure case; (C) shows a low temperature, low pressure case.

July 2021

(or degrees of freedom) the LNG has to combat various heat influxes. Combining the sampling probe with a high-quality insulation material, or ideally vacuum insulation, can help reduce the natural heat influx. However, heat leakage may present itself at critical isolation points and flange connections along the sampling system, which is an unfortunate inevitability, though not likely to have the greatest impact. To increase subcooling, the LNG can be pressurised to increase its bubble point or reduced in temperature to maximise the difference between the bubble point and sampling point. Figureb2 demonstrates the impact of altering pressure and temperature on the subcooling capacity of LNG. The blue line shows the bubble line (liquid phase on the left hand side of the blue line and two-phase vapour/liquid on the right hand side of the blue line). The green line shows the degree of subcooling the LNG has before it reaches its bubble point (the intersection of the green and blue line). The red line shows the amount of heat influx, as a proportion of the subcooling, that is absorbed into the LNG. The beginning of the red line is the sampling point. Adjusting sample line length can provide higher degrees of subcooling. Shorter sample lines provide better insulation since they have a smaller surface area that reduces heat transfer from the surroundings to the flowing LNG. Figure 3 demonstrates the impact of four different sampling line lengths, (A) 0.5bm, (B) 1 m, (C) 1.5bm, and (D) 2 m, on LNG subcooling capacity. The figures shown are only for demonstration purposes. Optimal sample line length can only be determined on a case-by-case basis since sampling system parameters can vary significantly.

It is clear from Figures 2 and 3 that higher sampling pressures, lower sampling temperatures, and shorter sample line lengths provide the largest subcooling capacity. There are numerous sampling system parameters that can be investigated. For example, the type of insulation used around the sampling line/probe has a substantial impact on the heat transfer taking place at the interface between the LNG and the surroundings. From sampling parameters, expected parameter ranges, and expected LNG compositions, it is possible to create a performance profile to pinpoint system vulnerabilities. A Monte-Carlo simulation, already used by EffecTech for performance evaluations of natural gas instruments, has proven to be a robust approach since numerous scenarios may be evaluated. Figures 4 and 5 show examples of subcooling capacity dependence on pressure and LNG sampling temperature for 2000 simulated scenarios covering a wide range of LNG compositions and sampling conditions. Subcooling residual is defined here as the remaining heat capacity of the LNG following heat absorption through the sampling line. A subcooling residual of less than zero indicates that the subcooling capacity of the LNG has become depleted and it therefore has reached its bubble point. It is clear from Figures 4 and 5 that for this specific scenario, LNG temperatures below 107.5 K and LNG pressures above 5.5bbara are required to prevent LNG pre-vaporisation. Furthermore, modelling multiple LNG sampling scenarios can help uncover boundary conditions for optimal sampling. In addition, maximising the LNG subcooling capacity can provide

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extra protection against heat influx sources or sudden changes in system parameters, for example sudden pressure drops. However, there must be a trade-off with the vaporiser power output since more energy is required to fully vaporise a lower temperature liquid.

Is LNG composition an important consideration in LNG sampling?

LNG import terminals may be subject to a wide range of compositions as cargoes are supplied from different locations which have different compositions and liquid characteristics. Each component present in LNG has a different boiling point and therefore contributes a different weighting to the overall bubble point of the LNG. Table 1 provides three typical LNG compositions and their corresponding Figure 3. Illustrating the impact of different sampling line lengths on LNG bubble points at pressures between 1 bara subcooling capacity. (A) 0.5 m; (B) 1 m; (C) 1.5 m; and (D) 2 m. and 9 bara. It is clear from Table 1 that there is a noticeable difference in bubble point, which is greater at lower pressures. Given a scenario Table 1. Difference in bubble points (BP) for a lean, medium, and where a sampling system is designed to sample at 120 K rich LNG composition at between 1 - 9 bara at 2 bar, these parameters would be suitable for a rich LNG composition since the difference between the Amount fraction (%mol/mol) sampling point (120 K) and bubble point (117 K) is 3˚. Lean Medium Rich However, the same system would have a negative degree of subcooling for the lean and medium compositions, 1 2 3 leading to almost certain pre-vaporisation if accounting for various heat influxes. Nitrogen 0.10 0.50 1.60 Knowledge of the imported composition prior to LNG Methane 99.74 89.40 77.88 unloading is crucial for sampling system design. Optimisation using a Monte-Carlo approach described Ethane 0.10 7.00 13.80 hitherto can provide insight into how different LNG Propane 0.00 2.00 3.80 compositions behave and how the system parameters described above can be fine-tuned to reduce heat influx Iso-butane 0.02 0.50 1.30 and maximise the degree of subcooling. N-Butane

0.02

0.50

1.30

Iso-pentane

0.01

0.05

0.16

N-pentane

0.01

0.05

0.16

Assessing vaporiser performance

Maximum difference (K)

BP at 1 Bara (K)

111.24

110.86

106.68

4.56

BP at 2 Bara (K)

120.25

120.37

117.23

3.13

BP at 3 Bara (K)

126.27

126.70

124.17

2.53

BP at 4 Bara (K)

130.94

131.61

129.51

2.09

BP at 5 Bara (K)

134.81

135.68

133.93

1.75

BP at 6 Bara (K)

138.15

139.20

137.73

1.47

BP at 7 Bara (K)

141.11

142.32

141.10

1.22

BP at 8 Bara (K)

143.78

145.13

144.14

1.36

BP at 9 Bara (K)

146.21

147.71

146.91

1.50

July 2021

LNG vaporisers come in all shapes and sizes; however, the thermodynamic principles are the same. A sample of cryogenic liquid needs to be fully converted to its gaseous phase to prevent residual liquid forming at the vaporiser outlet. This process may be achieved at low pressure or at supercritical conditions. Supercritical vaporisers reduce the likelihood of residual liquid formation significantly as the conversion from liquid to gas does not proceed through the two-phase region of the phase envelope as shown in Figure 6. For non-supercritical sampling, higher sampling flowrates require a higher heat output from the vaporiser to fully convert from cryogenic temperature to ambient temperature. Similarly, at lower sampling temperatures, more heat is required for the phase conversion as the absolute difference in temperature is greater. The required heat output from the vaporiser can be calculated from heat transfer equations. By combining mass flowrates, latent heats, and heat capacities, the required

energy output from the vaporiser can be determined. By comparing the required heater output to the actual heater output, an assessment of the vaporiser performance can be made. Temperature monitoring on the inlet and outlet of the vaporiser should be in place to confirm successful phase conversion. In addition, physical checks of ice formation on the external surface of the vaporiser can provide an indication of heat loss or a faulty unit.

Financial impact From the aforementioned demonstrations, it is clear that sampling representatively for accurate measurement is needed. Since calorific value and density are determined from composition and are crucial in the calculation of total energy content for custody transfer, even a small mismeasurement in composition due to unrepresentative sampling can have a substantial financial impact. Conservative estimates of LNG measurement uncertainty which take into account LNG sampling, vaporisation, and measuring equipment hover at approximately 1%.5 Given the size of the LNG market and heavily fluctuating spot prices, a 1% uncertainty translates to hundreds of millions of dollars in financial risk. Improvements made in LNG sampling and vaporisation can help to reduce this risk, ultimately providing greater confidence in measurement.

Figure 4. Subcooling dependence on LNG temperature for 2000 simulated scenarios.

Summary The complexity and variability of sampling systems and LNG cargoes highlight the need to ensure sampling systems are capable of making error-free representative measurements. Thermodynamic modelling and Monte-Carlo simulations can be used to ensure that there is adequate subcooling to prevent pre-vaporisation and to ensure that the vaporiser is sufficiently powerful to completely vaporise the liquid sample. Modelling multiple sampling scenarios can expose vulnerabilities in the system and highlight significant parameter sensitivities. Optimising LNG sampling systems can provide higher confidence in complete liquid conversion and measurement and consequently reduce the financial risk during custody transfer. To make sure all potential risks can be identified and assessed, EffecTech provides UKAS-accredited LNG sampling system inspections in-line with ISO 8943. Site-specific data is used to generate Monte-Carlo simulations using in-house software developed by EffecTech that allows the identification of safe operating envelopes and provides detailed recommendations for improvements. EffecTech is also accredited by UKAS for performance evaluations and as a producer of reference materials.

Figure 5. Subcooling dependence on LNG pressure for 2000 simulated scenarios.

References 1.

Royal Dutch Shell, Shell LNG Outlook 2021, (2021).

WOOD, D.A., and KULITSA, M., ‘Weathering /Ageing of LNG Cargoes During Marine Transport and Processing on FSU and FSR’. 10, Journal of Energy Resources Technology, Vol 140, (2018).

BSI, ‘ISO 8943:2007 Refrigerated light hydrocarbon fluids – Sampling of liquefied natural gas – Continuous and intermittent methods’, (2007).

BSI, ‘BS EN 12838:2000 – Installations and equipment for liquefied natural gas. Suitability testing of LNG sampling systems’, (2000).

GIIGNL, LNG custody transfer handbook, (2017).

Figure 6. Phase envelope of a generic LNG composition demonstrating the different thermodynamic paths of LNG vaporisers.

July 2021

Per Christian Johnsrud, Tunable, Norway, describes multi-gas analyser technologies and how improved gas data could benefit the operation of LNG vessels.

he maritime industry is currently striving to reduce greenhouse gas emissions. Many shipowners are making investments to update their fleets by enabling vessels to run on reduced carbon fuels like LNG. There is a clear drive to improve fuel efficiency and thereby reduce both costs and the environmental footprints of operating vessels. The integration of live data of the fuel quality consumed by the engine will support these initiatives. By combining multi-gas analyser technologies with a digitalisation algorithm and data analytics, shipowners can obtain valuable information that can improve the operation of their vessels. Going forward with this insight will be of increasing importance.

Potential for improved efficiency by access to gas data For LNG powered engines, the quality of boil-off gas (BOG) changes over time as a vessel consumes the LNG in the tank. In addition, the combination of forced and natural BOG further adds rapid changes to the gas mixture injected into the engine. This is negative with respect to fuel economy, as the variations in fuel quality forces the crew to run the vessel engines at a worst-case fuel mix scenario to minimise the risk for knocking. In such a scenario, they could potentially have to operate three engines at a low load instead of only two engines at a higher load per engine. With access to real-time multi-gas data it is possible to tune two engines to run at higher loads which saves fuel. On top of that, operating fewer engines at

Figure 1. Measurement principle of Tunable’s natural gas analyser technology.

higher loads reduces run hours on the engines, which reduces wear and maintenance costs. Gas mix information can be combined with other sensor and vessel data to produce valuable performance insight and enable shipowners to better monitor vessel performance. Various data acquisition companies are integrating these data streams to provide comprehensive data analytics. To be able to take full advantage of this data analytics, it is essential to have online gas analysers that provide data updates in real-time.

Improved data knowledge for better understanding of fuel consumption Some LNG carriers have installed gas analysers for measuring the quality of BOG which is consumed as fuel during sailing. Typically, the shipowner and charterer agree on fixed boil-off rates and fuel consumption as part of a chartering contract. However, actual gas consumption and value is impacted by the gas mix delivered during the voyage and might differ in the end. By having access to online gas analysis of the actual fuel consumed during sailing, the shipowner/charterer will receive improved knowledge which could benefit their commercial agreement.

Figure 2. The Tunable micro-electro-mechanical (MEMS) filter is continuously scanning a wide wavelength of the infrared light, to measure gas composition in the fuel gas mixture.

Figure 3. Tunable T1000 natural gas analyser with sampling system.

Gas analysers are used to measure multiple components There are various technologies available in the market that measure gas composition, calorific value, and methane number. Historically, gas chromatographs have been used for the measurement of natural gas and LNG. Lately, new analysers based on infrared spectroscopy have entered the market. These technologies are using absorption spectroscopy to measure gas composition. Each gas component has a unique infrared ‘fingerprint’. By illuminating the gas sample with infrared light at various wavelengths, the analyser can determine the presence as well as the concentration of individual gas components. A number of infrared technologies can be used to extract information on the absorption spectra, such as Fourier transform infrared spectroscopy (FTIR) or systems with interference filters that measure a discrete set of wavelengths. Technologies that allow rapid scanning over a broad wavelength range in the far infrared are preferable as they provide faster response time and higher accuracy. Moreover, for maritime use, it is highly important that the analyser is robust and easy to operate. This excludes systems with delicate optics and fragile mechanics, such as an FTIR. The maintenance requirements of the system should be minimised and they should be able to handle demanding offshore conditions. Furthermore, it is beneficial that the system does not require special gases for recalibration and manual operations while vessels are at sea.

A multi-gas analyser

Figure 4. FSRU Höegh Galleon where the analyser system has been in operation since 2019.

July 2021

The Tunable multi-gas analyser measures gas composition by infrared absorption spectroscopy. A small gas stream from the BOG fuel pipe is extracted by a sample probe and fed into the gas analyser. By measuring the transmittance of light through the sample cell at various wavelengths, the analyser determines the gas composition. The measurement principle is illustrated in Figure 1. A key component is a widely tuneable micro-electro-mechanical (MEMS) filter capable of scanning the wavelength of the infrared light continuously

from 7 - 14 μm. Wide scanning allows all gas components of interest to be identified and quantified, and it minimises cross interference. Furthermore, the quick response of the MEMS filter allows dynamic changes of the mixture to be measured, even when sampling relatively small gas volumes. The response time is crucial in dynamic engine optimisation applications. Lastly, the MEMS chip is highly robust, has a long lifetime, and is insensitive to vibrations.

Minimising operational cost Shipowners are looking for systems that are easy to operate and require minimum need for maintenance and support during operation. With no moving parts, the Tunable multi-gas analyser has been designed to be sufficiently robust for demanding maritime conditions. Traditional systems have been complex and have required regular attendance and consumables such as calibration and carrier gas. By removing the need for these consumables, the shipowner saves cost and space, reduces logistics, and lowers the HSE risk associated with the handling of pressurised gas bottles. The system is ATEX certified for use in Ex Zone 1.

Fast response time an enabler for engine performance The Tunable system conducts in-line measurements and does not require time for the separation of the gas components, such as in a gas chromatograph (GC). This provides a short response time and allows the identification of rapid changes to the gas composition during operation. By continuous measurement of the gas quality it is possible to operate the engines more efficiently and reduce fuel consumption.

Field test on FSRU Höegh Galleon Höegh LNG and Tunable have concluded a joint field trial for continuous online monitoring of the composition and calorific value of natural gas. The objective has been to provide a gas analyser that requires less support and reduces Höegh LNG’s annual operation and maintenance cost. As part of the project, Tunable’s natural gas analyser has been in operation on FSRU Höegh Galleon since 2019, where it has continuously monitored the complex composition and calorific value of the BOG. The field demonstration has proven that the gas analyser is successfully measuring mixtures of gases in line with specifications required for LNG carriers. During operations, remote condition monitoring and service has been successfully tested through a data link, removing the need for onboard service personnel. The feedback from the operation of the system by the ship operator is that the analyser has enabled them to get in-situ readings without delay and without consumption of calibration gas. This requires less support, implying lower operation and maintenance costs compared to existing technology.

Conclusion The shipping industry will continue to look for ways to improve fuel efficiency and reduce emissions. This will require better insight of critical fuel parameters. Development of a better data analytics system and performance improvement tools will be important. However, to take full advantage of this system, it is critical to have access to fast and reliable multi-gas data, which the ship operators only acquire through installation of an online gas analyser on the fuel gas system.

Mike Hastings, Brüel & Kjær Vibro, Denmark, describes how LNG gas turbine efficiency can be fully optimised with performance monitoring.

as turbines are some of the most reliable prime movers in industry for the applications they are used in, but also some of the hungriest. Just several percentage points drop in performance can result in annual production losses of millions. Case studies show that performance monitoring as an automatic monitoring strategy is an important tool for optimising the production output.

Optimal operation and maintenance The substantial worldwide market growth in LNG demand is driven by economic and environmental benefits as well as improved production technology. Gas turbines are widely used in the LNG industry as a result of this improved technology and they boast exceptional reliability in relation to other prime movers. But the performance of these machines is

strongly dependent on how well they are serviced. It is not unusual for their performance to drop a few percentage points between overhauls, translating into production losses worth millions of dollars. Online and offline (crank) washes are some of the important services for maximising gas turbine output, but there are many different policies in terms of procedures, recipes, and scheduling of these washes. The effectiveness of these washes, or any other process-related service or modification of the gas turbines, is best determined by monitoring the performance of these machines. In fact, a performance monitoring system that is part of an integrated condition monitoring strategy can do much more to increase overall production of the gas turbines, as well as for other process machines. It can also reduce the number of

unexpected shutdowns and reduce overall maintenance costs by detecting faults early enough, so service can be costeffectively planned ahead of time.

Performance monitoring system

Figure 1. Performance trend for a gas turbine before and after an offline wash. 1. Corrected bell-mouth airflow (kg/s). 2. Isentropic compressor efficiency (%). 3. Corrected compressor discharge pressure (bar). 4. Corrected power (MW).

An integrated vibration and performance monitoring system was selected at an LNG plant that would not only maximise the output of a number of critical machines in the entire plant, but would also reduce the number of unplanned shutdowns. The same system would also reduce the machine specialist manpower needed to safeguard the machines by one person. During the one year period of using the system, a number of faults have been detected in a number of machines. This article, however, focuses on how the performance monitoring function of the monitoring system is used for detecting, diagnosing, and trending gas turbine compressor fouling and turbine nozzle faults associated with the propane and mixed refrigerant compressor trains in the liquefaction cycle at an LNG plant.

Compressor fouling The gas turbine compressor blades perform the important task of preparing the incoming air before it is fired and expanded to rotate the power turbine to drive the gas compressor. The efficiency with which this task is performed depends upon the aerodynamic flow of the air over the blades, which is also influenced by the surface condition and profile of the blades. Even though the incoming air is filtered, dirt is still able to bypass and accumulate on the blade surfaces, or even erode them by impacts over time. Both of these effects, deposits and erosion, will reduce the airflow and efficiency of the compressor, thus limiting the power output. Machine manufacturers report that the efficiency of the gas turbines can be significantly improved by using recommended bladewashing techniques, but a loss of approximately 2.5% in efficiency can still be expected between overhaul intervals. Out of this 2.5% efficiency loss, it is reported that 1.5% is recoverable by using more optimised washing techniques. This 1.5% efficiency gain translates into an increase in production, and for many industries the reduced fuel consumption and lower emissions are an additional benefit.

Figure 2. Performance trend for a gas turbine before and after an online wash. 1. Corrected bell-mouth airflow (kg/s). 2. Isentropic compressor efficiency (%). 3. Corrected compressor discharge pressure (bar). 4. Corrected power (MW).

Figure 3. Isentropic compressor efficiency of GT A (red) and GT B (blue).

July 2021

Offline and online compressor washes The offline wash is the most effective way to clean the gas turbine compressor blades. Unfortunately, the machine must be stationary to do this, and this means production downtime. An online wash, on the other hand, can be carried out without shutting down the machine, but this only cleans the first few compressor stages. Nevertheless, this is important since the first stage deposits not only reduce the efficiency but also the airflow and the compressor discharge pressure. The succeeding compressor stage blade deposits only reduce efficiency (not airflow or discharge pressure), but these stages are more effectively cleaned by offline washing. The regularity of online and offline washes is strongly dependent on the application and location, and is a trade-off between optimal operating efficiency in relation to downtime. The only way to determine the effectiveness of the compressor bladewashing programme is not merely by visual examination

using a borescope, but by monitoring the performance of the machines.

Case 1: Offline washing makes a difference A significant increase in gas turbine performance can be seen in Figure 1, after an offline wash was performed: z Increased compressor efficiency by 2.5%. z Increased compressor discharge pressure. z Increased airflow. z Increased power. Online washes have not been undertaken prior to the offline wash, and therefore these are the expected results. This is followed by an expected downward trend of these parameters as the compressor blades begin to foul again.

Case 2: Rain showers reduce performance At one installation there had been very humid conditions for two weeks and this was followed by a period with heavy rain showers. On the day of the rain showers there was a very dramatic decrease in performance in many of the gas turbines. Immediately following the rain showers, a newly commissioned gas turbine fully recovered the original compressor efficiency it had prior to the rain showers (not shown in the figures), but other gas turbine trains gave indications that there was significant compressor blade fouling (reduced efficiency, airflow, and discharge pressure). An online wash was then carried out on those gas turbines which

had not recovered after the rain showers. The results were disappointing and so several online washes were carried out in succession since it was not possible to stop the machines at that time to do an offline wash. This only resulted in a partial recovery of most of the machines, evident by the diagram in Figure 2 for one of the machines.

What went wrong with the efficiency? As seen in Figure 2, the pressure drop across the inlet air filter started to increase dramatically during the two weeks of high humidity and then returned to a normal level immediately after the rain showers. The following is the sequence of events: The filters started to become saturated with water due to the high humidity. Maximum saturation was reached during the rain showers and the water precipitated into the gas turbine compressor, bringing with it all the dirt that had accumulated during the months since the last filter change. The water evaporated during the compression process, leaving most of the dirt attached to the blades during this short time interval, thus lowering the efficiency to an extremely low level. The accumulation of dirt was so drastic that it was not possible to recover the efficiency after subsequent online washes for all the machines.

How to avoid this problem happening again Obviously, the weather cannot be controlled, but there are many things that can be undertaken to minimise the risk that it poses for gas turbine operation. For example, in the case mentioned previously, a weather protective enclosure could justify its investment in this and similar applications.

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But regardless of the type of physical modification carried out on a gas turbine to preserve or enhance its production capacity or reliability, a means is still needed to determine its effectiveness.

Figure 4. Bell-mouth airflow of GT A (red) and GT B (blue).

This is achieved by automatic and continuous performance monitoring of the compressor trains, not monitoring only for commissioning of machines, establishing baselines, or undertaking analysis/diagnostic work. Many believe that after a washing programme has been established (with or without performance monitoring to optimise it), these washes can be scheduled on time-based intervals. This is generally not true. Not only is performance monitoring needed for tracking the effectiveness of the washing programme under varying operation conditions, but it is also needed to monitor for unexpected events, such as rain showers, dust storms, or other sudden changes that can influence the process. Once an automatic performance monitoring solution is in place, it is important to monitor the correct parameters. In the example of the rain showers, it is very important to monitor the pressure differential across the inlet filter and trend it at all times. If there is a relatively high pressure-drop in combination with rain, fog, or high humidity, there is a danger that the event described earlier can repeat itself. Change the filters before they become too dirty. Perform online washes as often as possible, during and directly after the event, and, if possible, perform an offline wash after any such event.

Case 3: Monitor all appropriate performance parameters

Figure 5. Corrected compressor discharge pressure of GT A (red) and GT B (blue).

Two identical gas turbines are used in a low-pressure and high-pressure propane compression cycle, but the performances for the machines differ considerably. As seen in Figuresb3 - 5, the machines have similar airflow, compressor discharge pressure, and compressor efficiency, but GT A is performing slightly better except for its power output (Figureb7). How is this possible? By looking at the turbine isentropic efficiency (Figure 6), GT A is approximately 5% less than GT B. It was later determined that the second stage nozzle positions on GT A were incorrect, which was most prevalent during the warm summer months. The lesson to be learned here is to monitor all the appropriate performance parameters, not only the efficiency.

Conclusion

Figure 6. Turbine isentropic efficiency of GT A (red) and GT B (blue).

Figure 7. Corrected power of GT A (red) and GT B (blue).

July 2021

Process industries such as the LNG industry can save millions of dollars in lost production by improving the performance of their machines by only a couple of percent. Compressor washing is one method to improve this, but its effectiveness is dependent on many factors. The most reliable technique to determine this is by accurate performance monitoring of the machines based on a standardised thermodynamic model, where the algorithms and corrections are widely accepted and time proven. The performance monitoring system should not be considered a temporary analysis tool that is used only from time to time, but as an automatic 24 hours a day, seven days a week monitoring strategy, just as in the case of vibration monitoring. Unexpected process changes can and do occur that make time-based solutions impractical. An appropriate machine condition monitoring system solution is needed to do this, and this is not the same system or strategy used for machine control and safety. An accurate thermodynamic model is required together with real gas properties, an extensive database, diagnostic and analysis tools, and a versatile alarm strategy. But just as important as the system, a specialist is necessary to assess needs, implement the system, and train personnel, since performance monitoring is a very specialised field.

Steve Balek, Stellar Energy, USA, explains how digitising turbine inlet air chilling systems can help optimise maintenance activities to ensure maximum LNG production is maintained.

or liquefaction plants in warm or temperate climates, turbine inlet air chilling (TIAC) has proved to be a reliable and cost-efficient means of ensuring stable power output and, in turn, predictable LNG production. Despite this, TIAC systems are often viewed as ancillary, and thus not traditionally targeted for digitalisation to the same extent as equipment on main refrigeration trains, such as gas turbines, compressors, electrical motors, etc. However, a strong business case exists to extend performance monitoring onto mechanical TIAC systems. Doing so provides a number of benefits that directly impact a plant’s bottom line, including the ability to pre-empt failures and optimise maintenance activities so that production uptime is maximised.

Turbine inlet air chilling overview Power output in gas turbines is proportional to inlet air density. As the temperature of ambient air rises, density decreases and so too does mass flowrate through the turbine. When dry bulb temperature exceeds the ISO-rated inlet air design point (typically 15˚C), power output begins to degrade. For LNG plants, this can potentially result in a production bottleneck, as turbine units driving main refrigerant compressor trains are unable to operate at nameplate capacity. Numerous TIAC technologies can be employed to offset the effect of ambient air temperature fluctuations. All of these work by chilling inlet air before it enters the compressor of the gas turbine – typically to approximately 7˚C. Mechanical chilling often represents the best available technology for liquefaction plants, as it offers highly predictable performance (regardless of relative humidity) and does not require large volumes of water or complex water treatment systems. This is in stark contrast to other methods, such as evaporative cooling or fogging. Mechanical TIAC systems operate in a similar fashion to traditional air conditioning units. A system consists of one or multiple centrifugal compressor chillers and pumps, which send chilled water (or a water-glycol solution) as a secondary refrigerant to coils downstream of a highefficiency filtration system in the gas turbine inlet filter house. In gas turbine power generation applications, mechanical TIAC has shown to provide up to 35% output gains on hot days above 35˚C and as much as a 5% improvement in the heat rate of gas turbines. Additionally, case studies which have examined commonly applied liquefaction processes have shown that the majority of the gas turbine power gain is directly realised in LNG production gain.

The case for performance monitoring In recent years, digitalisation has emerged as a powerful lever for helping LNG plants improve efficiency and optimise production. There are now numerous examples across the industry where facilities have used performance monitoring of critical systems to reduce downtime and associated costs through preventative maintenance. To date, most of the focus on digitalisation in liquefaction plants has been directed at the compression train itself, and more specifically, on ensuring the uptime of major equipment

assets (for example, gas turbines, compressors, electric motors, heat exchangers, etc.) Generally speaking, there has been less focus to leverage operational data from other areas, including the TIAC system. In many cases, managers will have access to high-level information regarding their TIAC system – for example, which chillers are in operation and which are not – through the plant-wide control and monitoring human machine interface (HMI). However, they rarely have the capability to drill down into detailed performance data at the componentlevel. With little operational visibility and virtually no way to see potential issues developing, maintenance usually has to be conducted reactively after a failure occurs. An N+1 redundancy philosophy is typically used with TIAC systems to ensure that cooling load can be met when a single chiller is taken out of service. However, in the summer months, when all chillers in the plant are operating at full capacity most (if not all) of the time, any failure or unplanned shutdown could mean a reduction in gas turbine output and corresponding drop in LNG production. In a facility with one or more aeroderivative gas turbines, for example, on a day with ambient temperatures above 35˚C, a shutdown of multiple chillers within a TIAC plant can potentially result in up to a 20% loss in LNG production. Depending on how long it takes to determine the root cause of the failure and implement a fix, losses upwards of millions of dollars can occur. Implementing a performance monitoring system helps mitigate this by providing plant managers with visibility into the chiller plant on a much more granular level (e.g. temperature delta across condenser coils, flowrate, efficiency, pump amperage, and so on). With the additional data, the performance of the TIAC system can be benchmarked so that any deviations which could indicate a problem can be investigated and resolved before an actual failure occurs. In this way, the existing integration gap between industrial process and business intelligence is bridged and plant managers are able to make more informed decisions with the ultimate goal of maximising LNG production.

Real-world application Stellar Energy recently implemented a first-of-its-kind intelligent monitoring performance dashboard for a mechanical TIAC system at a large scale US liquefaction facility. The modular air-cooled system uses a non-flammable hydrofluoro-olefin as the primary refrigerant in the packaged

Figure 1. Performance curve of the gas turbines and the expected output with and without TIAC at different ambient conditions.

July 2021

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chillers to cool the secondary refrigerant, a low-concentration glycol solution. Using inline pumps, this solution is sent to filter house cooling coils to provide a constant 7.2˚C inlet temperature for gas turbines driving multiple compression trains. The system also uses a low concentration glycol solution sent through the condensers by inline pumps to a radiator field to remove heat from the primary refrigerant. The TIAC performance dashboard presents easily interpreted graphs and metrics that plant managers can use to create an overall picture of the TIAC system’s impact on LNG production. Performance metrics illustrate the value of the TIAC system in terms of the current daily and current monthly performance gain (megawatt hours) and the total run time of the chiller plant (hours). All performance calculations pertaining to gas turbine power output are calculated from a performance model curve created in power plant modelling software (Thermoflow GTPro®). The graph in Figure 1 shows the performance curve of the gas turbines and the expected output with and without TIAC at different ambient conditions. The green line indicates the real-time ambient condition. The overlaid text indicates the current change in inlet temperature and gain in megawatt output enabled by TIAC. If a user notices that the system is not performing as expected, he or she can investigate the root cause. Key data points that can be viewed include, but are not limited to, inlet and outlet water temperatures of the turbine inlet coil and temperatures surrounding the air-cooled heat exchanger, as well as chiller plant efficiency (kilowatt per tonne of refrigeration), total auxiliary load (megawatt), total chiller load (tonne of refrigeration), and the total number of air cooled heat exchangers (ACHE) fans in operation. For each chiller, the unit diagram displays real-time chilled water and condenser cooling water temperatures and flow. In addition, it displays whether equipment is in operation or offline and the total run hours of each pump. System reports can be generated on-demand for any selected period of time. The performance dashboard can be run locally or on a secure cloud and features an open data structure so that data is exportable to other platforms, such as enterprise resource planning (ERP) systems or other digital analytics tools.

Figure 2. Performance dashboard showing real-time performance of total chiller plant and individual chiller pairs.

July 2021

Enabling preventative maintenance With the type of detailed insight provided by the performance monitoring dashboard, plant managers can fundamentally transform the way they operate and maintain their TIAC system. Take, for example, a damaged and/or fouled condenser coil in a chilled water loop. Without a performance monitoring system in place, the only indication that a problem exists would likely be an increase in the inlet air temperature of the turbine and a corresponding reduction in shaft horsepower output. However, by the time the issue is noticed by personnel in the control room, the production disruption may already be underway, and the only option would be to shut down the chiller for inspection and repairs. With a performance dashboard installed, this problem could be identified much earlier and would likely manifest in the form of a reduction in overall chiller plant efficiencyb(kilowatt per tonne of refrigeration). In many cases, there may be no degradation in power output, as temperature delta across the damaged condenser coil is still being maintained, but at the expense of overpumping and increased electricity consumption. After investigating and identifying the underperforming coil, technicians can be dispatched to investigate the root cause. The necessary spare parts can then be ordered and maintenance can be scheduled for a time when it will not impact LNG production – for example, on a day when the ambient temperature is low and the chilling load can be handled by the balance of the system. In other cases, it may be possible to perform minor maintenance to ensure that the chiller remains operational until the next scheduled plant shutdown.

Combining data insights with OEM expertise A collaborative partnership between the original equipment manufacturer (OEM) and plant operator is often adopted when it comes to the operation and maintenance of compression train assets, such as gas turbines and compressors. TIAC systems are typically viewed as less complex. Nonetheless, the same type of approach should be employed, especially given the potential impact a failure can have on LNG production. Implementing a TIAC performance monitoring system can provide tremendous value to LNG plants by enabling preventative maintenance and ensuring stable production. However, maximising the predictive window requires a combination of data analysis and collection, along with OEM system knowledge. With millions of hours of accumulated operating experience, TIAC system OEMs have chilling system expertise beyond the realm of typical LNG plant personnel. This specialised knowledge is critical when determining what corrective actions to take in order to mitigate problems or optimise the system. Facility managers can therefore benefit by engaging with an OEM before implementing a performance monitoring system. For greenfield plants, this should occur as early in the design phase as possible so that value is beginning at plant start-up.

Merrick Alpert, EonCoat, USA, describes how a weldable coating has been designed to protect welded tank bottoms from corrosion.

Figure 1. Welding tank bottom plates in place.

oneywell International Inc. needed to solve a problem at its Geismar, Louisiana, US plant that plagues the LNG and petrochemical industry: how to prevent corrosion on the soil facing side of a tank. This problem costs large LNG and industrial companies billions of dollars a year, and until recently there was no solution. Traditional paint does not work because if the painted steel is welded, the paint on the soil facing side will burn off and create a corrosion cell that immediately begins rusting. Cathodic protection does not work because the required voltage cannot be maintained over the large, uninsulated metal surface in contact with the ground. Honeywell, like many of the largest LNG and petrochemical companies in the world, typically leave the tank bottoms unprotected and accept as inevitable the enormous cost of repair, replacement, and downtime that is guaranteed to occur as the steel corrodes. Fortunately for Honeywell, Controlled Maintenance,bInc. (CMI) delivered a solution. CMI, with vast industrial maintenance services experience, showed Honeywell that a coating had been developed that could be

applied to the soil facing side of the tank and then safely welded with no damage caused to the coating. CMI’s long history of both tank bottom construction and tank bottom repair had led the company to search for a better solution for Honeywell and its other customers throughout the US. CMI’s decades of experience led the company to conclude that tank bottoms represented the most frequent failure point caused by premature corrosion. The problem was even more prevalent for tanks welded in place at a tank farm. CMI had learned about the tank bottom solution from Asset Protection Solutions, a New Orleans-based company that represents the EonCoat anti-corrosive coating in the US Gulf Coast region Asset Protection Solutions’ technical team worked with CMI to support the project, which involved an EonCoat coating on the tank bottom steel panels at CMI’s Gonzalez, Louisiana, US facility before the panels were transported to Honeywell’s Geismar HCL unit. The panels coated with EonCoat were then welded in place as the tank was fabricated in the tank field. “The coating held during the weld, it held during the construction, and even held well during transport,” said Don 37

Bourg, CMI’s Vice President of Operations who oversaw the project. “This coating will perform without being compromised by internal welding.” Orhan Ergün, Managing Director of Asset Protection Solutions, provided insight into the team-based solution that CMI and Asset Protection Solutions delivered together to Honeywell. “We were deeply committed to working with our friends at CMI to deliver a world class solution to Honeywell. And we are equally committed to sharing this breakthrough solution to tank owners throughout the Gulf Coast region.” Sarah LeBlanc, Sales Manager for Asset Protection Solutions in Louisiana, US, was instrumental in originating and managing the project to fruition. “We worked with the team at CMI to assess, identify, and specify the right solution. And for tank bottom coating, EonCoat is the right answer.”

Weldable coating Unlike traditional polymer coatings that burn up when welded, EonCoat is inorganic and non-flammable. Made entirely of minerals, the coating will not burn. Welding the panels together on the floor of the tank does not damage the coated soil facing side of the steel. Don Bourg, who oversaw the welding operation on the Honeywell tank, summarised the result by saying: “The coating was 100% intact before I left the site.” Unlike paint, which only serves as a barrier coating over the substrate, EonCoat prevents carbon steel from corroding by chemically reacting with the steel. The result is that the coated surface of the steel is an alloy that is inert and will not react with the elements. Neither oxygen nor moisture will react with the alloy. Corrosion cannot occur. Since the alloy layer, made of iron, magnesium, and phosphate, is chemically bonded to the steel, nothing can get past or beneath EonCoat’s alloy layer. In comparison, paint is just a barrier that sits on top of the steel profile. There are gaps where the profile is low. Oxygen, moisture, and salts make their way through the inevitable cuts and gouges in the paint. These corrosion promoters weave their way around these gaps underneath paint over time and create the rust blisters that are so often seen. When EonCoat is spray applied to steel, a ductile ceramic layer forms over the alloy layer. The result is two layers of corrosion protection. The alloy layer is chemically bonded to and part of the steel, and the ceramic layer is chemically bonded to the alloy layer. The ceramic layer functions as a phosphate reservoir, allowing the coating to self-heal if it is mechanically damaged.

Figure 2. Two plates coated with EonCoat weldable coating being welded together.

July 2021

Phosphates in the ceramic will migrate to the steel to protect it from corrosion, as needed. The result is corrosion protection for the life of the asset, with a single application.

Benefits EonCoat delivered the solution to Honeywell’s primary concern – preventing tank bottom failure. By using this coating, Honeywell should never have to replace the tank bottom again. If EonCoat is not used, the cost of repairing or replacing the bottom of a tank, and the associated lost production opportunity (LPO) asset downtime, is often hundreds of thousands of dollars. The cost of using EonCoat is similar to the cost of an industrial paint system. But unlike paint, EonCoat’s weldable coating withstands a temperature of 600˚C (1112˚F). The coating also delivers a series of health, safety, and environmental (HSE) benefits to Honeywell, its employees, the community, and Honeywell’s shareholders, that cannot be obtained with traditional paint. The coating is non-toxic and non-flammable – even when welded – so the result is a safer work environment for Honeywell’s employees and contractors. Furthermore, since EonCoat is water-based and inorganic, it contains no volatile organic compounds (VOCs), no hazardous air pollutants (HAPs), and no odour. Honeywell also benefits from the high degree of impact and abrasion resistance the coating delivers to protect the steel.

Ease of application Unlike paint, EonCoat does not need to be applied to white metal. The coating is successfully applied over flash rusted steel. For the Honeywell tank, CMI followed the NACE 3/SSPC SP 6 commercial blast standard and then allowed the steel to flash rust until CMI was ready to apply EonCoat. The elimination of the need to spend time blasting to a white metal standard and then rapidly applying primer before rust bloom develops is one of the ways in which EonCoat delivers labour cost savings and faster return to service to asset owners such as Honeywell. It can also be applied on damp steel. As CMI experienced, this allows the coating to be applied even in weather conditions when traditional paint could not be used. CMI applied the 1:1 plural component coating using a basic plural component pump and a Graco G40 spray gun. Clean-up is undertaken with only water, as the water based EonCoat does not require solvent. Moreover, it is applied at atmospheric temperature. There are no heated lines or heated hoppers. EonCoat’s tank bottom coating is a one coat product. No topcoat is used with this weldable coating. EonCoat’s President Merrick Alpert summarised the project on behalf of all of the participants: “We are honoured to work with CMI and Asset Protection Solutions to deliver this breakthrough technology to a great company, Honeywell International. Along with the EonCoat project team at CMI and Asset Protection Solutions, we welcome the opportunity to protect the large number of tanks located throughout the Gulf region.” Looking forward, the scourge of tanks rusting out from the soil facing side and constant replacement of tank bottoms is over. After decades of struggle there has been a solution created that works. EonCoat is designed to be easy and safe to apply and will last for the life of the tank. It can be used with or without cathodic protection, effective either way. The intention is that tank owners will no longer have to include time and money to replace bottoms in their budget.

LNG Industry asked two companies to discuss some issues regarding LNG valves.

VALVES

Matt Byers – Director of Product Management Brian Burkhart – Senior Product Manager Baker Hughes Matt Byers is the Director of Product Management for Consolidated Pressure Relief Devices, a pioneer in overpressure protection that delivers solutions to the increasingly high standards for safety, efficiency, and emissions reduction faced by the industries Baker Hughes serves. Matt holds a Bachelor of Science degree in Mechanical Engineering from Louisiana Tech University, US. Brian Burkhart is the Senior Product Manager for Consolidated Pressure Relief Devices. Under his leadership, Consolidated has launched two first-to-market and patented products, representing a true technological step change in the overpressure protection industry: the 2900 Series Gen II Pilot-Operated Pressure Relief Valve and the 1900 DM Series Dual Media (DM) Dual Certified Spring-Operated Pressure Relief Valve. Brian holds a Bachelor of Science degree in Industrial Distribution Texas A&M University, US, and an MBA from the University of Houston at Sugar Land, US.

Reid Youngdahl – Valve Technical Specialist Emerson Automation Solutions Reid began working for Emerson in 2013 as an Applications Engineer, providing global control valve technical support for various industrial markets such as oil and gas, power generation, and original equipment manufacturers. Reid currently provides technical consultation for severe service control valve applications to optimise customer solutions. Reid is based at Emerson’s office in Marshalltown, Iowa, US.

VALVES Why are valves considered fundamental devices in LNG operations? Reid Youngdahl - Emerson Automation Solutions Control valves are critical final control elements within an LNG facility due to their direct impact on key performance indicators as they touch every part of the LNG value chain. Though often overlooked, properly specified control valves enable significant LNG process improvement, such as increased output with decreased energy consumption. Critical control valve applications within an LNG facility begin with the control of pipeline natural gas into the facility through the inlet feed pressure let-down valves. Next, control valves are fundamental in controlling the process fluids around the absorber column to clean the gas, including the large pressure differential outgassing rich amine let-down control valve located at the bottom of the column. Compressors located throughout an LNG facility are kept safe and running efficiently with anti-surge valves, which must provide fast and accurate control. Arguably the most critical valves in the facility are the Joule-Thomson (JT) control valves located around the main cryogenic heat exchanger (MCHE) as these have significant impact on LNG production. Finally, finished product LNG is loaded, unloaded, and regassed through control valves.

How is safety kept as a top priority in the design and fitting of valves? Matt Byers & Brian Burkhart - Baker Hughes Pressure relief valves (PRVs) are inherently a safety device, so reliability must be unquestioned. Given the extreme temperatures characteristic of cryogenic applications, enhanced sealing features are required to ensure PRVs effectively perform their safety function. As the last line of defence to protect equipment and personnel from an overpressure event, valves must be constructed to minimise leakage and recover effectively from a relief event.bMaterials of construction, trim designs, and anti-galling measures are all critical considerations for design. Common problems include:bb z Seat leakage: Thermal stress from low temperature causes material deflection.bThis deflection on a seating surface can result in leakage while the valve is closed, or immediately following a relief event. z Galling of bearing/guiding surfaces:bAnti-seize grease, commonly used in non-cryogenic applications to prevent galling, quickly deteriorates under cryogenic temperatures.bThis results in galling-induced wear between the metallic components, which leads to seat leakage, valve simmer, and ‘hang-up’ of guiding surfaces as the valve attempts to reseat following a relief event.b z Process loss and fugitive emissions:bSeat damage as a result of prolonged seat leakage, premature opening as a result of major seat leakage, or the PRV not fully closing after a relief event due to excessive galling can all lead to unwanted and costly release or fugitive emission of process fluid.

Reid Youngdahl - Emerson Automation Solutions

Baker Hughes: Consolidated™ Cyrodisc patented Thermolip technology.

Emerson continues to focus on the safety and performance of its Fisher control valve and actuator products, including those destined for critical LNG applications. The company’s experts are dedicated to understanding not only normal operating conditions, but also extreme conditions encountered during emergency or transient events, along with the expanding global standards and regulatory landscape, to confirm the safety of our advanced product designs. Emerson has a wide range of materials available for customer selection so valves can safely operate in corrosive ambient environments, and when subjected to process fluid contaminants. Extensive product design analysis and testing is completed to verify ultra-low fugitive emissions, tight shut-off, noise reduction and other performance characteristics critical to

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VALVES performance in cryogenic and other LNG applications. Consideration of safety is incorporated into every stage of the design and manufacturing process. Emerson’s commitment to safety in the evolving LNG industry protects the environment and reduces the risk of harm to end user personnel and process equipment.

Detail a challenging valve solution that required more ingenuity than normal. Reid Youngdahl - Emerson Automation Solutions The main cryogenic heat exchanger (MCHE) is considered the heart of the LNG facility, so the JT control valves feeding the MCHE are considered the most critical of control valves. When specified and engineered correctly, licensed process controllers can operate optimally, resulting in increased LNG throughput with less energy use. On the flipside, the implications are great when these high-pressure differential cryogenic assemblies, inherently susceptible to poor throttling performance, are overlooked. For example, an LNG facility identified that their current JT control valves were a key reason for suboptimal plant performance. Due to an excessive installed deadband, the large cryogenic globe valve assemblies were incapable of controlling to the required small step changes, inhibiting optimised licensed process controller tunings. Additionally, mechanical assembly reliability issues were observed, such as insufficient extended bonnet lengths creating external ice formation that led to packing leaks and valve positioner stem linkage damage. The facility determined that new high-performance pneumatically operated control valves with strict dynamic performance parameters related to deadband, deadtime, and frequency response were the best path forward. A complete engineering review was required to meet the necessary throttling performance. The holistic approach included proper severe service trim selection to minimise vibration caused by the high-pressure differential, as well as custom cage characterisation to ensure the installed gain of the assembly was ideal for the given process. Low friction cryogenic valve plug seals were designed to ensure good throttling performance while meeting Class IV seat leakage, as this amount of leakage was acceptable due to the continuous modulation duty in this JT application. High performance double acting actuators, along with an expertly tuned Fisher FIELDVUE™ DVC6200 linkageless (magnetic feedback array) smart positioner atop a cryogenic extension bonnet, were supplied. To provide best performance, all JT control valve assemblies were dynamically tested while fully submerged in liquid nitrogen at -320˚F. Results exceeded expectations with measured small step change controllability for increments as low as 0.0625%.

Matt Byers & Brian Burkhart - Baker Hughes The typical failure mode of a PRV operating with cryogenic media is seat leakage after valve actuation, or when the operating pressure is close to set pressure. The product team at Baker Hughes for consolidated valves looked to high temperature PRV design innovations which have evolved over the last 100 years, mostly on steam applications, from their yoke/side rod constructions to their disc designs.bMany of today’s PRVs designed for steam have unique disc designs which leverage thermal expansion principles to provide leak-tight performance at elevated temperatures.bThese high temperature disc designs have a thermolip feature which uses the temperature differential between the process fluid and ambient temperature in the body bowl to cause a downward deflection, providing more contact stress on the nozzle seat and creating greater seat tightness at elevated temperatures. Applying the same thermal expansion principles that have demonstrated and successfully proven leak-tight performance on high temperature applications, the Consolidated team designed a reversed thermolip Cryodisc.bThis reversed thermolip produces the same leak tight performance at cryogenic temperature as has been proven with high temperature discs at elevated temperatures. Another common PRV problem in cryogenic applications Emerson Automation Solutions: Fisher™ Digital Isolation™ valve assemblies, like the Fisher TOV solution, come with a that needs to be addressed is galling of bearing/guiding single SIL certification for the final control element assembly surfaces that can cause seat leakage and potentially cause a rather than SIL certificates for each component. PRV to fail to close off after a relief event.bAnti-seize grease, 42

Consolidated™ 1900 Dual Media (DM) Series Designed for Cryogenic Optimization Pressure Relief Valves (PRVs) are a necessary requirement for overpressure protection within the LNG industry. However, not all PRVs are created equally when it comes to performance within cryogenic applications with temperatures as low as -320°F (-196°C). • Enhanced Seat Tightness Patented Cryodisc technology leverages thermal expansion principles to create uniform contact pressure on the nozzle seat.

Patented Thermolip

• Reduced Galling and Wear Titanium Nitride (TiN) coating, an extremely hard ceramic material, is applied to bearing surfaces and guiding surfaces of critical PRV components. • Dependable Performance The Consolidated 1900 DM Series can be relied upon to perform before and after a relief event to save users thousands annually on unplanned downtime, repair costs, process loss and excessive fugitive emissions.

For more information, contact your local Baker Hughes representative or visit valves.bakerhughes.com

VALVES commonly used in non-cryogenic applications to prevent galling and provide lubrication, quickly deteriorates under cryogenic temperatures. This results in galling-induced wear between the metallic components, which leads to seat leakage and hang-up of guiding surfaces as the valve attempts to reseat following a relief event. A solution to address this issue is Titanium nitride (TiN) coating, which is an extremely hard ceramic material, applied to improve a substrate’s surface properties. It is applied as a thin coating, less than 4 μm, and is used to harden and protect metal to metal bearing surfaces and sliding/guiding surfaces. This coating eliminates galling, microwelding, seizing, and adhesive wear on critical PRV components. It has a very low friction, enhances corrosion resistance, and has erosion resistance. Applying TiN coating on critical bearing and guiding PRV components will improve seat tightness after a relief event on LNG and can save users on unplanned downtime, PRV repair costs, process loss, and excessive fugitive emissions.

Describe some recent developments in ensuring zero leakage and guaranteeing endurance. Reid Youngdahl - Emerson Automation Solutions Single sourced final control element (FCE) valve assemblies with one complete safety integrity level (SIL) certification to be used within a safety instrumented system (SIS) provide pre-configured online diagnostics to ensure reliable operation, with in-depth factory testing to ensure all devices are working together properly. A holistic approach is critical when evaluating a valve’s ability to provide zero leakage, while ensuring endurance to high cycles. For example, the valve itself could be properly selected, but if the actuator were sized incorrectly with mounting brackets not designed to handle the maximum torque of SIS valves, issues may be created with maintaining shut-off throughout the life of the SIS assembly. Single SIL certified and tested assemblies have improved actuator sizing processes and mounting bracketry, and along with factory acceptance testing these ensure the valve shuts off completely for as long as the assembly is in service.

Matt Byers & Brian Burkhart - Baker Hughes The seat leakage standard for PRVs is defined by API 527 Seat Tightness of Pressure Relief Valves. In this standard, PRV leakage rates for metal-seated, spring-operated PRVs are deemed acceptable at rates as high as 100 bubbles/min. for a valve. This standard is applied and measured in a manufacturing or service setting to a valve that is in its prime condition, but does not address acceptable leakage rates for a valve that is installed and in service. In this condition, it is safe to assume that the valve will experience significantly higher leakage rates due to seat defects from PRV cycling, system debris, or slow erosion over time. By contrast, pilot-operated PRVs are allowed 0 bubbles/min. seat leakage across the main valve seat. This technology ensures zero leakage in the main valve with repeatable performance due to the nature of the valve design and use of a more forgiving seat in the form of soft goods. However, the API 527 standard fails to address the leakage that occurs out of the pilot portion of a modulating pilot valve. This most common design for a modulating pilot valve uses an antiquated modulating technology known as internal modulation, and is the most prone to fugitive emissions through the pilot under normal operating conditions. As this valve approaches set pressure, the pilot will anticipate the need to modulate by releasing a small amount of main valve dome pressure from the main valve and out of the pilot discharge. While this allows for modulation in the overpressure cycle, it has the negative side effect of fugitive emissions even when the valve is supposed to be in a zero leakage state. Consolidated valves offer a unique approach with their true zero leakage bolt-on modulating pilot valve technology. Instead of anticipating an overpressure scenario and prematurely releasing main valve dome pressure into the atmosphere, this design waits until set pressure is reached before releasing any Baker Hughes: Consolidated 1900 Series Dual pressure through the pilot discharge, thus completely eliminating fugitive Media (DM). emissions from the PRV under normal operating conditions. 44

VALVES What are the current limitations of valve technology? Reid Youngdahl - Emerson Automation Solutions A common practice in the LNG industry is specifying cryogenic control valves to comply with on/off isolation valve seat leakage standards. This is possible, but at the cost of good throttling performance if not accounted for by the control valve vendor. This situation primarily arises with large, high-pressure balanced cryogenic globe type control valves specified to meet on/off isolation valve seat leakage standards, such as BS6364. Balanced plug seals exist to provide the required seat leakage, but these can add a significant amount of friction to the assembly. If this friction is not properly accounted for, it can greatly inhibit the tight throttling performance of a control valve. The critical MCHE JT control valves are inherently susceptible to this concern due to applications that often require large, high-pressure balanced cryogenic globe type control valves. The control valves can meet the project specified isolation cryogenic seat leakage requirements via factory acceptance testing, however installed dynamic performance of the valve may not be ideal for optimised licensed process controller tuning. These valves are continuously modulating when the LNG facility is running, thus it is important to ensure valves throughout the facility are being specified correctly.

Emerson Automation Solutions: The Joule-Thomson (JT) control valves are critical to achieve optimal plant performance. It must be capable of precise throttling control in severe cryogenic temperatures at high pressure differentials.

How has valve design developed over the years and where can you see future changes occurring? Reid Youngdahl - Emerson Automation Solutions There have been many advancements in control valve designs to meet the severe service application demands of LNG facilities. The ever-increasing liquefaction million tpy export capacity of LNG facilities calls for larger capacity valves, specifically the inlet feed pressure let-down valves. The inlet feed pressure let-down valves are critical as they begin the LNG process by controlling the pipeline natural gas entering the facility, with poor control valve performance often leading to serious downstream disturbances. The combination of large, highpressure natural gas transmission pipelines; increased required flowrates due to the ever-increasing liquefaction million tpy export capacities; and the requirement for providing good throttling performance has led to the development of tailor-made control valves. Example facility designs have required multiple NPS 24 CL1500 globe valves with characterised noise attenuation trim to handle both high-pressure differential low flow and low-pressure differential high flow conditions. Further design enhancements to eliminate the high flow induced vibration coupled with non-ideal piping practices in large, high-pressure globe valves include the use of gridded seat rings to provide good flow control and ensure stable operation of the valve and downstream assets.

Do you expect there to be an increase in future demand for valves in a particular LNG application or facility? Reid Youngdahl - Emerson Automation Solutions The demand for valve count and applications for a traditional LNG facility remain fairly flat, depending on the licensor and EPC. However, there is a possibility to see an increase in valve count based on sustainable efforts around carbon capture and sequestration. Many operating companies must now support company environment sustainability governance (ESG) efforts. But the greatest shift in the LNG valve market space is desired support and the services provided by the valve vendor. Start-up and flushing trim can be utilised in the commissioning stage to decrease the time needed to install these valves, especially the critical ones, and to provide a safer plant environment with less crane lifts and man-hours required to get valves installed and operating correctly. 45

VALVES These start-up activities enable cost savings by protecting critical severe service trim sets, and by reducing the need for buying spool pieces and other piping materials to flush the system before operational trim is installed. Compressor anti-surge valve actuator assemblies can be shipped separately to reduce the risk of damaging these high-performance pneumatic accessories when the valves are installed to align the piping. All these non-traditional needs can be satisfied to enable a successful, safe, and seamless LNG facility start-up.

As the world strives for decarbonisation, is there an opportunity cost between valve cost-effectiveness and applying fugitive emission technology? Reid Youngdahl - Emerson Automation Solutions In general, upgrading a valve assembly to a higher tier fugitive emission packing set is a marginal cost adder in relation to the entire valve assembly. However, the higher tier fugitive emission packing designs typically add significant friction to the assembly, which can lead to flow down implications. Though the cost adder of fugitive emission packing itself is low, the additional friction may require larger actuation and additional accessories that add cost to the overall valve assembly. Another implication is the direct relationship of increased valve assembly friction and deadband. If not accounted for properly, this decrease in throttling performance can result in suboptimal process performance, thus adding additional operating costs to an LNG facility. These complications make it crucial to select a control valve vendor whose technology expertly navigates the potential trade-off of performance and emissions mitigation techniques.

Matt Byers & Brian Burkhart - Baker Hughes “Safety First” is the mantra when it comes to overpressure protection.bAfter all, the primary purpose of a PRV is to act as the last line of defence for safety in the event of an unexpected overpressure event.bWith safety as the top priority, the overpressure protection industry has historically delivered safety solutions at the expense of fugitive emissions, process loss, and eroding profits.bThat being said, the technology available to the industry over the last century has largely been limited and slow to adapt to the changing needs and demands of the modern economy. The workhorse valve of choice in the industry has primarily been the API 526 Spring-Operated PRV, and now has millions installed around the world. Based on spring-operated safety valve technology from the 1850s, this valve offers a proven and reliable solution when it comes to safety.bHowever, its metal-to-metal seat design and excessively long blowdown in multi-phase/case relief scenarios make it costly in terms of process loss and unwanted fugitive emissions. Pilot-operated PRV technology was later introduced in response to calls for increased operating efficiency and fugitive emissions reduction.bThis new technology was able to both maintain the safety standards of the API 526 Spring-Operated PRV while also allowing operators to run their system at higher pressures without experiencing seat leakage.bHowever, it often came at a cost as upgrading old installed base to this new technology would require high levels of management of change (MOC) activities and piping modifications due to centre-to-face dimensional differences. In 2020, Consolidated Valves released the new 2900 Series Generation II Pilot-Operated Pressure Relief Valve, an enabler for spring-to-pilot PRV upgrades that reduces emissions due to PRV leakage in an economical manner. This valve is able to retrofit or replace existing API 526 Spring-Operated PRVs to the latest in pilot valve technology while completely maintaining centre-to-face dimensions and almost completely removing MOC activities and their associated costs.

Explain the role of valves in helping to reduce emissions and keep energy consumption low in the LNG process. Reid Youngdahl - Emerson Automation Solutions Control valves can play a major role in an LNG facility’s decarbonisation goal to ship carbon-neutral exports. In addition to ensuring fugitive emission compliance within the valve assembly design, properly specified high-performance throttling control valves can reduce the overall carbon footprint of an LNG facility. Examples include the JT control valves located around the MCHE, which have significant impact on LNG production. When properly specified, these control valves enable LNG process improvements, such as increased LNG output with decreased energy consumption. Fast-stroking, high-performance compressor anti-surge valves enable a compressor to run more efficiently by safely operating closer to the surge line. These increased process efficiencies, coupled with reduced process disturbances, result in less overall gas-to-flare instances, reducing product loss and protecting the environment. 46

LNG Industry asked two companies to discuss some issues regarding LNG valves.

VALVES

Protect against compressor surge and improve FGàDJFODJFT Achieve maximum compressor efficiency with a Fisher™ optimized anti-surge control valve package. The entire LNG refrigeration cycle relies on robust compressors to ensure uninterrupted production. At the center of the anti-surge recycle loop is the compressor anti-surge control valve, which is tasked with meeting several challenges. Complete surge cycles can occur in less than seconds, so a quick reaction is essential. Precise control is also required to prevent unwanted recycle or imbalance that may cause accidental trips or stalls to plant production. The Fisher optimized antisurge control valve package provides higher gains, precise response, and remarkable stability. It also has online diagnostic capabilities to monitor its health. Fisher™ control valve with SS-263 volume boosters and FIELDVUE ODV-tier digital valve controller

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Ludwig Gross, Fabrice Rey, and Julien Métayer, Technip Energies, France, outline the available advanced solutions for collaborative operator training. Figure 1. View of the high fidelity VR model of the FLNG in CETO®.

hen it comes to plant safety and productivity, plant operators are key personnel. This is a fact well known to process industries such as LNG production. Plant operators are in charge of conducting operations efficiently and managing day-to-day production and upsets to avoid major incidents. Their skilled responses are essential for safe and profitable production management. With more complex plants in remote locations, operating companies face the challenge of finding new ways to train operators that are less costly and more efficient. Offering a digital induction to field operations or the acquisition of new skills without leaving the office is a personal development opportunity much appreciated by plant operators, particularly millennials. These smart and innovative training

solutions assist plant management in mitigating the loss of knowledge and competencies following the retirement of the more experienced workforce. For more than a decade companies have been using operator training simulators (OTS) on a routine basis. However, an OTS is dedicated to the console operator. Field operators must rely on on-the-job training (OJT). A major limitation of physical OJT is the increased risk from junior operators handling critical situations. In such events, the senior operator will have to take over control, limiting learning opportunities for the less experienced junior. To enhance field operator training, companies have been turning to immersive training simulators (ITS) in addition to OJT. Standard ITS is a valuable tool for maintenance planning and for

familiarising operators with plant topology. It will also cover the training on routine procedures and emergency response plans. However, it is currently limited to basic feedback from the plant. As such, the trainee will not be able to evaluate the consequences of his actions on the plant process.

A digital simulator training tool A Plant Operator Digital Simulator (PODS) is a digital asset where actions performed in the virtual field or control room and their interactions are reflected accurately. It relies on the connection of the expertise gained in OTS projects and ITS project development and mitigates some drawbacks of each individual solution. This training tool integrates two training interfaces, one dedicated to console operators and the other to field operators. Both interfaces access the same virtual environment in realtime. Trainees can practice collaborative scenarios between the field and control room. Most emblematic scenarios would be related to unsafe process conditions and critical operations, such as start-up activities. These activities require major field operation under control room supervision. For the interactive simulation solution, Technip Energies stands on its proprietary interactive simulation platform. CETO® is built to provide the company’s project teams and clients an in-house solution to visualise 3D environments and interact with them in the most natural possible way. This involves a state-of-the-art physics engine that replicates the behaviour of the real world inside the simulation.

It also requires a strong expertise in computer science to deliver user-friendly solutions based on technologies such as virtual and augmented reality. Last but not least of the cornerstones inside CETO is its capability to deploy massive 3D models in the scale of a whole plant, and optimise the workflow to achieve this. CETO has a strong track record in offshore operations including heavy lifts and ROV operations. Based on this experience and to widen its service market, Technip Energies has developed a complete in-house ITS product offering. As with most ITSs, it is capable of providing scripted reactions of the plant to the user actions. However, such scripted actions cannot provide a process realism at the scale of a plant or even at functional unit level. This is within the capabilities of the process simulation.

Relying on specialist teams

For the process dynamic simulation, Technip Energies stands on its specialists. The team has been developed with skilled personnel to offer a valuable in-house solution during project execution and operation phases. This involves dedicated specialists with a strong knowledge of the different tools available on the market and their preferred use cases. It also requires a detailed knowledge in process control and operations to deliver added value to project and operations. Additionally, the team provides increased flexibility during the engineering phase. The team has a strong track record in engineering transient analysis in close collaboration with process engineers. Based also on its experience, Technip Energies has developed a complete in-house dynamic simulation lifecycle solution. Based on the engineering transient analysis, the specialist team delivers models for integration to the integrated control and safety system (ICSS). Technip Energies plays an active part in the virtual commissioning of the ICSS and the OTS delivery. As Technip Energies hosts both CETO and dynamic simulation specialist teams, it has been natural to connect CETO to the process model to provide a fully realistic reaction of the plant response to the field operator actions. The field operator and the mechanical dynamics world are now connected with the console operator and its fluid dynamics world. Beyond the interactive simulation solution and dynamic simulation team, Technip Energies leverages all the competencies of an engineering company. PODS has been the Figure 2. A VR model automated import from engineering opportunity to develop internal add-ins to transform an 3D model. engineering 3D model into a virtual reality model or to develop an in-house monitoring interface. In turn these developments open the way to new applications. Following PODS development and through internal synergies, it is now possible to remotely share a virtual reality during 3D model review, accompanying the increased importance of the human factor engineering for operating companies. Similarly, process simulation has developed light interfaces that are also used as plant production dashboards accompanying the digital Figure 3. Two simulators and two interfaces immersing operators as a single goal. transformation of the company’s clients.

July 2021

Technip Energies has designed innovative workflows to provide training modules for collaboration between field and console operators in a cost-effective way, multiplying the value for its LNG clients. In the course of the demonstrator development, it became clear that PODS is an ideal tool for other project activities. The activities identified so far cover the writing of start-up procedures, the development of augmented reality applications for field personnel, and the deployment of robots in unmanned facilities. The writing of the operating procedures prior to start-up is a complex and time-consuming activity for all LNG projects. It requires senior operators to fully understand the design intent of the plant. They have to thoroughly go through all the project documentation issued by process and instrumentation and acquire an in-depth knowledge of the plant. This can lead to misalignments and misinterpretations. Within PODS, the operator is immersed in the final plant and confronts the simulated facility with his/her initial interpretation of the control and safety system, assumptions on the process response, and sparse understanding of the plant layout. This simulated facility confirms the behaviour of the automation, provides the proper feedback of the fluid dynamics, and exposes the operator to the reality of the physical environment. In this secure environment, the operator will perform the start-up operations with his/her initial grasp. PODS will record all actions and parameters. By reviewing the outcomes of the operations, the operator gains specific experience. The operator now can run an optimised sequence seeking the best efficiency and safety. Once the operator has stabilised the best sequence, PODS will generate a draft of the procedure, including all steps with explicit KPIs and validation criteria. During the peer review, PODS is available to the reviewer to run and stress test the procedure. By having a more robust procedure with PODS, the facility start-up is executed more efficiently, avoiding on-site trial and error and failure of critical equipment, and reducing start-up time to achieve earlier production. In addition to the expected gains on traditional activities, PODS is also a tool that will assist in the deployment of other digital services. Among those services, PODS can address augmented reality and unmanned facilities and robotics. ATEX grade augmented reality devices are reaching the market. Soon field operators in LNG plants will be equipped, but use cases are difficult to validate in the field, hindering any wide deployment. Much caution remains among operators who do not appreciate the operational gain of augmented reality as field tests are not performed. On the other hand, management is concerned about heavy deployment. It is apparent that return on investment (ROI) of such novel technology will require significant change management. The proof-of-concept strategy in this domain has reached its limits. To target multiple sites, various facilities would require large IT infrastructures on each site. PODS proposes a solution to this problem: the augmented reality product will be simulated in PODS. All real-time data useful to the operator is computed in the PODS environment. The augmented reality application will deliver this data to the operator, multiple data configurations will be proposed, and any new sets of data could be tested easily. Moreover, the look and feel of the future augmented reality application will be tested. Operations and management will then validate the information selection and

ergonomics of the application. This will feed the specifications of the augmented reality deployment to the site. PODS infrastructure is extremely light. Deployment of PODS on multiple sites to evaluate the augmented reality solution on multiple teams can be performed in a very short time with limited costs. The two targets achieved are a strong evaluation of the ROI and an easier adoption. For unmanned facilities, PODS also supports developments in robotics, serving as a training ground for robots. It will be possible to test procedures and record automated features. PODS can undertake all this in a cost-effective way long before the plant is completed. Once the plant starts operations the virtual environment is still available as a digital twin of the robot deployed in the field. PODS emulates robot behaviour to provide data to the supervisor software, such as Cyxpro. It will also assist in determining when human site intervention is required. These operations are conducted in co-operation with Cybernetix, Technip Energies’ robotics affiliate.

Summary From the start, PODS was designed as a full digital twin for operators. It delivers high-fidelity computation of field, control room, and process conditions interacting in real-time. For major contractors, such developments in operator training can be a game changer. A contractor’s focus on industrial ROI instead of software profitability ensures maximised benefits for end users. As such, PODS is playing a key role in Technip Energies’ participation to the LNG industry’s digital transformation.

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Xiang Wong, Cyberhawk, UK, explains how drone technology is helping LNG producers plan and optimise asset inspections.

t has been over a year since the first cases of the COVID-19 pandemic were identified, and the full scale of disruption it has caused is clear to see. For the LNG industry, the pandemic coupled with low prices and oversupply has placed increased pressure on operators. To survive amidst a volatile market and capitalise on future growth opportunities, operators must act now to make their operations as safe, robust, and efficient as possible. From Cyberhawk’s experience, many LNG operators have already turned to drone-based inspections as a cost-effective and time-efficient approach to identify asset defects, mitigate health and safety risks, and prioritise critical maintenance work. As oversupply continues throughout 2021, with new projects continuing to increase capacity well beyond the steady growth of demand, more and more LNG companies are expected to embrace the benefits of drone inspection compared with traditional methods, such as using rope access or scaffolding.

Maintenance backlogs The roll-out of a COVID-19 vaccine has been welcomed around the world; however, the need for reduced manpower and

social distancing at work sites remains critical. For LNG asset operators, consideration must be made to ensure they not only protect their workforce from infection, but are found to be compliant with strict guidelines set out by the regulators. Since early 2020, many health and safety regulators have been carrying out ‘virtual visits’ to onshore and offshore sites and even vessels, as they continue to seek assurance that hazards are being effectively managed by operators. Last year, the Health and Safety Executive (HSE) came together with the Trades Union Congress (TUC) and Confederation of British Industry (CBI) to send a loud and clear message that the “health and safety of workers remains paramount”, despite the operational challenges COVID-19 brings. These remote visits have highlighted serious cases of inspections being deferred due to cost cutting and reduced headcounts, which has resulted in dangerous health and safety breaches and extensive maintenance backlogs. Even prior to the pandemic, this was an issue. A total of 1382 non-compliance issues were raised with operators in 2019, an increase of 10% from the 1254 cases recorded in 2018, according to the HSE’s annual ‘Offshore Statistics and Regulatory Activity’ report. The category which generated the

largest number of issues was maintenance. At the end of 2020, a representative of Unite union expressed his concern, stating that “the build-up of outstanding work had increased in 2020 due to COVID-19”.

Turning threat into opportunity The disruption brought on by the pandemic provides an opportunity for change for the LNG sector. A portion of these maintenance backlogs are a result of employers reducing manpower on-site in an attempt to adhere with the social distancing measures in place. This has included the cancellation or postponement of traditional inspection methods such as scaffolding or rope access technicians. It is not surprising. Not only is it typically very costly to erect and dismantle scaffolding for manual inspections, costing operators potentially hundreds of thousands of pounds for large areas, it is a lengthy and dangerous process. Using pioneering drone technology to inspect LNG assets, onshore and offshore, reduces the need to send personnel into dangerous areas, or have them work at height over extended periods of time. For example, Cyberhawk drones can fly in

hard-to-reach confined spaces, often without the need for human entry, which is essential in the LNG sector as storage tanks and high areas of floating structures such as loading arms need to be inspected regularly. As a result, by adopting a drone-based inspection programme carried out by highly experienced pilots who are used to working in complex and high-risk environments and regularly complete intricate inspections to a high standard, operators have the power to reduce the maintenance backlogs at a lower cost, without the risk.

The largest LNG producers are embracing drone-based inspections In 2019, Cyberhawk supported a major global independent owner and operator of LNG midstream infrastructure by inspecting one of its largest floating LNG (FLNG) vessels, located offshore Kribi, Cameroon. Cyberhawk’s scope of work included the inspection of the structure and joints of the vessel, hoses and pipework, access ladders and platforms, and counterweight and ancillary components. In just four days, the team was able to identify a number of defects located on the vessel’s loading arms caused by

corrosion. This included damage to various hydraulic hoses, with one showing deterioration of its coating. In addition, a section of shielding on the top access platform had a connection that had corroded, which resulted in a corner left loose. The team also found a loose bolt on the hose and pipe supports, which would have been near impossible to detect using traditional inspection methods such as scaffolding or a rope access as the area was particularly difficult to reach given its height and limited space surrounding.

Armed with the drone inspection data, the operator was able to quickly gain a better understanding of the condition of its vessel and therefore plan and prioritise maintenance work overtime. This helped keep the personnel who were working onboard safe and ensure operations continued to run smoothly. In fact, the operator recently reported that it was able to maintain 100% commercial uptime for more than twobyears. If the operator had not taken this proactive approach to inspection work and enlisted Cyberhawk’s drone inspection services, and had instead relied on traditional methods, it would have taken weeks, if not months, to complete the inspection. There would be no guarantee that all defects would have been caught either. Having personnel working at height is notoriously dangerous, as is the failure to spot defects in a timely manner. It could result in debris or loose fixtures falling from a height and potentially cause harm to personnel working below, or even result in high-risk fires or explosions.

Data unlocks tomorrow’s efficiencies Figure 1. Cyberhawk pilot performing preliminary flight checks.

Figure 2. Cyberhawk pilot and inspection engineer performing a hand launch.

Given current market conditions, many operators may be tempted to defer maintenance or equipment inspections and upgrades as they look to reduce costs and manpower. This could have negative consequences longer-term, however. It creates a backlog of maintenance work that can quickly become unmanageable, as already seen across the upstream, midstream, and downstream industries. Defects can grow into larger, more complex, serious problems, which could potentially impact productivity at the site or vessel and even put a workforce in harm’s way. For many LNG operators, the market conditions and the pandemic will mean they have no other option than to keep maintenance budgets to a minimum, therefore carrying out expensive inspection programmes with large crews is no longer an option. Maintaining assets in the future comes down to putting appropriate control measures in place and prioritising maintenance by adopting innovative and efficient solutions. By deploying drones to carry out rapid periodical assessments of risk across their assets, operators can obtain a deep understanding of the condition of their infrastructure and equipment in a matter of weeks or even days, depending on the scale of the site. This allows them to establish a maintenance programme, underpinned by data including terabytes of high-quality inspection imagery and videos, point cloud data, orthophotos, and 3D digital twins, helping them prioritise the areas most in need of attention or remedial action, instead of deferring maintenance completely and creating a backlog of work that threatens future productivity. In doing so, operators are able to limit the personnel needed on-site, ensure equipment remains reliable and safe to operate, and help prevent corrosion and other defects leading to operational failure in the future.

Data management technology transforms maintenance planning Figure 3. Cyberhawk pilot and inspection engineer performing an under deck drone-based inspection.

July 2021

As stated in McKinsey’s ‘The Future of Liquefied Natural Gas: Opportunities for Growth’ report, LNG producers should apply digital techniques to realise significant hidden value across

their operations.1 The global management consultancy also predicted key trends including digital tools increasing the flexibility and responsiveness of LNG production. Where Cyberhawk believes digitisation really adds value is data visualisation over time. LNG asset operators, for example, have been faced with a long-standing challenge of collating, managing, and storing vast amounts of inspection data collected over years of asset ownership. Many now realise that without digitisation, it is almost impossible to maintain an accurate record of the history and usage of equipment over time, track maintenance work carried out, and gain a clear picture of the state of the asset. This becomes incredibly important when demonstrating compliance to the regulator, allowing operators to effectively predict and plan future maintenance work. Fortunately, the LNG industry will benefit from the impressive advancements in data management technology seen in recent years. Cyberhawk has developed its own cloud-based software, iHawk, which allows asset operators to completely digitalise their inspection reports. iHawk combines visual data gathered by the drones, ground 360˚ cameras with data from a myriad of field sensors, and Internet of Things (IoT) devices enabling real-time equipment location tracking and performance monitoring, locating specific areas of interest using RFID technology, and more, into a single visual interface. This is particularly useful for large scale onshore LNG plants. For any work being carried out on-site, it is important that a record is kept and accountability for tasks is clear. iHawk offers the option of assigning physical areas of the LNG site for a specific task and purpose, assigning a responsible

individual, and publishing this information to the stakeholders involved. A timeline is then created and made visible to every team member, which increases transparency and collaboration on a project. In addition, the position and usage of equipment can be closely monitored by seamlessly integrating industry leading IoT solutions. Each piece of equipment can be fitted with vibration sensors that report uptime and other telemetry data, which is aggregated in the iHawk for interpretation and analysis, helping the site managers to derive the most value from the investment in the equipment and helping them maintain it over time. Using cloud-based software, the operator can access up-to-date, full visual records of their assets. This allows for detailed information to be shared between asset management and operations teams, senior managers, and contractors. It can even be used to illustrate compliance to the regulator. Cyberhawk sees the trend of data visualisation and the adoption of drone-based inspections continuing across the LNG landscape. With recent investments in terminals and pipelines to connect gas to consumers, and accelerated demand growth in regions such as Asia, the world’s largest energy-consuming region, there is a critical need to ensure the integrity of LNG infrastructure. From floating vessels to onshore plants, drone-based inspections can offer an efficient, cost-effective, and safe solution to safeguard a bright future for the global LNG industry.

References 1.

McKinsey & Company, ‘The future of liquefied natural gas: Opportunities for growth’, (September 2020).

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15FACTS

...ON

Australia has some of the most emissionintensive LNG plants in the world

The Sydney Opera House took 14 years to construct The Pluto Train 2 LNG brownﬁelds expansion could reach a capacity of approximately 5 million tpy

Australia has overtaken Qatar to become the world’s top exporter of LNG

AUSTRALIA

A kangaroo can reach a top speed of 56 km/hr

Australia is the sixth largest country in the world at 7 682 300 km2

The North West Shelf (NWS) project was Australia’s ﬁrst LNG project, ﬁrst supplying gas to the domestic gas market in 1984 The emissions intensity of Australia’s gas production increased by approximately 30%

The federal government is currently subsidising

between 2014 and 2019

gas-ﬁred powered generation in NSW with AUS$723 million

Uluru stands 348 m tall above its surroundings

Capacity utilisation of gas peaking plants has fallen from 15.5% in 2014 to just 6.5% in 2020 The estimated total vineyard area in Australia is 146 244 ha.

The Australian coastline is approximately 34 000 km

The US$3.6 billion Barossa project gained Final Investment Decision from Santos and SK E&S

Australia has three time zones

July 2021

on 30 March 2020

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LNG Industry July 2021

Articles inside

Digitising the field

Taking inspection to new heights

Valves Q&A

Tank bottom corrosion: solved

Roadblocks and obstacles for the land Down Under

Meticulous performance monitoring

A masterclass in BOG management

Comment

Keeping it cool

Expanding the degrees of freedom

LNG news

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