Tanks and Terminals Spring 2022

SPRING 2022

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CONTENTS Spring 2022 Volume 08 Number 01

03 05 06

Comment World news International challenges and possibilities

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Gordon Cope, Contributing Editor, examines the obstacles faced by the energy sector across Europe and the Middle East, and the opportunities available to the tanks and terminals market moving forwards.

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he woes that beset the world’s energy sector are multitude: resurgent COVID-19 in Asia, wild weather in the Gulf of Mexico, tardy gas supplies from Russia, as well as gyrating oil prices. Their cumulative effect is changing the landscape in both Europe and the Middle East, forcing energy suppliers to respond, with inevitable consequences for tanks and terminals.

Europe The hangover from COVID-19 demand-destruction continues in Europe. ExxonMobil permanently shuttered its Slagen refinery in Norway during summer 2021, converting it to a fuel import terminal. In the Netherlands, Gunvor closed two crude processing units in Rotterdam and suspended its refinery in Antwerp. Galp is closing its Porto refinery in Portugal and will decommission and decontaminate the site. Neste has discontinued operations at its Naantali refinery in Finland, converting the plant to a terminal.

Biofuels offer a glimmer of hope, however. Total shut its crude processing unit at the Grandpuits refinery in France, converting it into a biofuel complex. Eni, which has already converted two refineries to biofuel, is now evaluating its Livorno refinery in Italy, with the aim of reaching 2 million tpy of biorefining by 2024.

In natural gas, Europe has been beset by parlous shortages since the fall of 2021, causing prices to rise dramatically. In December 2021, UK gas prices surged to an all-time high of

Gordon Cope, Contributing Editor, examines the obstacles faced by the energy sector across Europe and the Middle East, and the opportunities available to the tanks and terminals market moving forwards.

£3.50/therm (approximately US$46/1000 ft3), up over 500% from the beginning of the year. While the causes range from unexpected resurgence in post-COVID-19 demand, to events in Russia, a key culprit has been the drop in storage capacity, especially in the UK. A decade ago, storage companies did trade in the price spread between winter and summer gas, covering the storage fees and making a profit. As the availability of LNG in the US cut into European hub prices, however, companies across the continent wrote down over €1 billion in facilities. In the UK, Centrica closed the Rough gas storage facility in the North Sea (which held over 3.3 billion m3), significantly paring reserve capacity from 24 days to approximately 10 days.

Efforts to increase gas availability in Europe by building new LNG terminals are encountering obstacles. In December 2021, Vopak announced that it was stepping back from active involvement in developing the Brunsbuettel import terminal, located near Hamburg, Germany. It was initially expected to be operational by the end of 2022, but environmental permits are forcing delays, pushing the estimated start-up back to 2025.

Hydrogen Hydrogen has become a hot commodity in recent years because it has great potential to reduce the carbon footprint in refineries, heavy industry and transportation. The gas has a high energy density and can be produced using electrolysis

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The digital decision

Tim Hoffmeister, Implico Group, Germany, outlines the central role of the smart tank terminal within the ongoing energy transition, highlighting its ability to reduce emissions, handle alternate products and react to new developments.

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ISSN 1468-9340

Storage during transition

Danny Constantinis, EM&I Group, Malta, explains why robotic and digital technologies will play an important role in supporting storage facilities for cryogenic products.

The future of tank inspection

Stuart Kenny, Eddyfi Technologies, UK, discusses the role of remotely accessed robotics in the management of tank and terminal asset integrity.

The robotic revolution

Fintan Duffy, Re-Gen Robotics, Northern Ireland, outlines the benefits of robotic tank cleaning solutions through the real-life example of an operation at a refinery in the UK.

Accelerating action

Gurjeet Bansal, IntelliView Technologies Inc., Canada, highlights how automating remote monitoring with AI cameras can cut time, effort and costs, whilst improving safety and reducing environmental impact.

Bolstering fire safety

Edward Cass, Paratherm, USA, explains how the risk of fire in thermal fluid systems can be minimised.

The power of insulation

Mackenzie Michalski and Allen Dickey, Owens Corning, USA, present three goals for storage vessel insulation design.

Saving money, saving lives

Tony Collins, EonCoat LLC, USA, discusses how a considered choice of tank coating could help to improve workers’ health, as well as limit negative environmental impacts.

Acoustic distinction

Carolina Stopkoski, FLEXIM AMERICAS Corp., and Jörg Sacher, FLEXIM GmbH, discuss the benefits of using non-invasive sound speed measurements to improve tank dewatering operations.

Paratherm has been the premier heat transfer fluids provider in the industry for over 30 years, offering a wide range of heat transfer fluids and services. Paratherm provides users with an extensive fluid analysis programme, delivering results that matter. The company’s expert and knowledgeable technical staff provide excellent service, alongside its team of talented specialists and sales engineers. Learn more at www.paratherm.com

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CALLUM O’REILLY SENIOR EDITOR

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he burgeoning hydrogen sector has been hitting the headlines in recent times, as companies and countries increasingly view it as a major enabler to net zero greenhouse gas emission targets. As such, it is unsurprising that attention is turning to where all of this hydrogen will be stored.

In what would be a potential world first, the Government of Western Australia Department of Mines, Industry Regulation and Safety recently commissioned RISC to conduct a scoping study into the potential of storing hydrogen in depleted oil and gas fields in Western Australia.1 RISC also carried out a literature review of other examples of underground hydrogen storage, including aquifers, salt caverns, underground mine sites and tunnels.

After screening 23 onshore depleted oil and gas fields in the region, RISC identified seven fields as ‘strong’ candidates for hydrogen storage projects. In order of ranking, the top seven fields were Xyris, Yardarino, Beharra Springs, Red Back, Tarantula, Tubridgi, and Mondarra. Interestingly, all of these are gas fields, with oil fields downgraded due to added complexity and issues of storing hydrogen. RISC also notes that, technically, the Mondarra and Tubridgi fields are ‘very strong’ hydrogen storage candidates. However, their rankings have been downgraded due to existing natural gas storage projects in place in these fields, which impact their short-term availability. The Dongara field was also downgraded to ‘moderate’ hydrogen storage potential, despite it being the largest field evaluated (with approximately 458 billion ft3 of gas produced), as such large hydrogen storage volumes are not forecast in the short to medium-term. RISC estimates pure hydrogen storage demand to be between 1 and 10 billion ft3.

Despite these positive findings, RISC warns that the global subsurface hydrogen storage industry is at an “embryonic stage”, and there are no depleted oil and gas fields, aquifers, underground mine sites or tunnels currently used to store pure hydrogen. Hydrogen in porous media presents several challenges and remains “largely unproven”. The report explains that hydrogen is more chemically reactive than gas, which may affect the reservoir lithology, flow behaviour and seal capacity. It also acts as an energy source for subsurface microbial processes, which can turn the hydrogen into hydrogen sulfide or react with carbon dioxide to form methane.

Location is another issue. The largest renewable energy sites being considered in Western Australia – the Western Green Energy Hub (WGEH) and the Asian Renewable Hub (AREH) – are located over 1000 km away from suitable depleted fields.

The report claims that salt caverns are the most robust means of storing hydrogen and have been proven to work. However, once again, location remains a problem. The Canning Basin, which contains the thickest known salt deposits in Australia, is approximately 200 km away from the AREH project, while no salt deposits have been mapped adjacent to WGEH. As such, RISC recommends that surface storage options are also considered as they may provide more effective solutions for renewable hydrogen storage in the region.

We are likely to see increased interest and research into hydrogen storage in the coming months and years as the world transitions to a net zero future. If you’re interested in keeping abreast of the latest developments in the sector, I’d recommend that you sign up for a free subscription to Global Hydrogen Review – a new magazine from Palladian Publications, coming soon, that is dedicated to the entire spectrum of hydrogen production and storage: www.globalhydrogenreview.com/magazine 1.

‘Hydrogen Storage Potential of Depleted Oil and Gas Fields in Western Australia’, RISC, (August 2021)

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WORLD NEWS A selection of the latest news hitting the headlines on www.tanksterminals.com...

DIARY DATES

Construction commences at the IOR Lytton Terminal

13 - 15 April 2022

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OR has announced that construction has commenced at the IOR Lytton Terminal to deliver 110 million l of new diesel storage to the market in Brisbane, Australia. Taking place in the Port of Brisbane precinct, the project involves repurposing IOR’s existing 50 million l crude oil storage tank for diesel fuel storage and constructing two new tanks with combined capacity of 60 million l.

CB&I named tank contractor for Venture Global’s LNG project

23 - 25 May 2022 StocExpo Rotterdam, the Netherlands www.stocexpo.com

13 - 15 June 2022

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cDermott’s storage business, CB&I, has been awarded a contract by Venture Global for two 200 000 m3 LNG storage tanks as part of the first phase of the Plaquemines LNG export project.

ILTA International Operating Conference & Trade Show Houston, Texas, USA www.ilta.org

05 - 08 September 2022 Gastech Milan, Italy www.gastechevent.com

VARO Energy and GPS Group complete integrated biofuels facility

10 - 13 October 2022 API Storage Tank Conference & Expo San Diego, California, USA events.api.org/2022-api-storage-tank-conferenceexpo/

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ARO Energy Group and GPS Group have announced the successful completion of a new railway line and ethanol storage tanks at the Port of Amsterdam, the Netherlands. This new state-of-the-art infrastructure is one of very few rail facilities that enable the movement of traditional fuels and bio products in the ARA-region.

18 - 20 October 2022 AFPM Summit San Antonio, Texas, USA www.afpm.org/events

TotalEnergies acquires BP’s retail network in Mozambique

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24th Annual International Aboveground Storage Tank Conference & Trade Show Orlando, Florida, USA www.nistm.org

06 - 07 December 2022

otalEnergies is expanding in Mozambique with the acquisition of BP’s retail network, wholesale fuel business and logistics assets.

15th Annual National Aboveground Storage Tank Conference & Trade Show The Woodlands, Texas, USA www.nistm.org

READ MORE...

To read more about all of these stories, and keep up-to-date with the latest news and developments in the storage sector, visit www.tanksterminals.com and follow us on our social media platforms

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Spring 2022

Gordon Cope, Contributing Editor, examines the obstacles faced by the energy sector across Europe and the Middle East, and the opportunities available to the tanks and terminals market moving forwards.

Spring 2022

6

T

he woes that beset the world’s energy sector are multitude: resurgent COVID-19 in Asia, wild weather in the Gulf of Mexico, tardy gas supplies from Russia, as well as gyrating oil prices. Their cumulative effect is changing the landscape in both Europe and the Middle East, forcing energy suppliers to respond, with inevitable consequences for tanks and terminals.

Europe The hangover from COVID-19 demand-destruction continues in Europe. ExxonMobil permanently shuttered its Slagen refinery in Norway during summer 2021, converting it to a fuel import terminal. In the Netherlands, Gunvor closed two crude processing units in Rotterdam and suspended its refinery in Antwerp. Galp is closing its Porto refinery in Portugal and will decommission and decontaminate the site. Neste has discontinued operations at its Naantali refinery in Finland, converting the plant to a terminal.

Biofuels offer a glimmer of hope, however. Total shut its crude processing unit at the Grandpuits refinery in France, converting it into a biofuel complex. Eni, which has already converted two refineries to biofuel, is now evaluating its Livorno refinery in Italy, with the aim of reaching 2 million tpy of biorefining by 2024.

In natural gas, Europe has been beset by parlous shortages since the fall of 2021, causing prices to rise dramatically. In December 2021, UK gas prices surged to an all-time high of

£3.50/therm (approximately US$46/1000 ft3), up over 500% from the beginning of the year. While the causes range from unexpected resurgence in post-COVID-19 demand, to events in Russia, a key culprit has been the drop in storage capacity, especially in the UK. A decade ago, storage companies did trade in the price spread between winter and summer gas, covering the storage fees and making a profit. As the availability of LNG in the US cut into European hub prices, however, companies across the continent wrote down over €1 billion in facilities. In the UK, Centrica closed the Rough gas storage facility in the North Sea (which held over 3.3 billion m3), significantly paring reserve capacity from 24 days to approximately 10 days.

Efforts to increase gas availability in Europe by building new LNG terminals are encountering obstacles. In December 2021, Vopak announced that it was stepping back from active involvement in developing the Brunsbuettel import terminal, located near Hamburg, Germany. It was initially expected to be operational by the end of 2022, but environmental permits are forcing delays, pushing the estimated start-up back to 2025.

Hydrogen Hydrogen has become a hot commodity in recent years because it has great potential to reduce the carbon footprint in refineries, heavy industry and transportation. The gas has a high energy density and can be produced using electrolysis

7

Spring 2022

powered by renewable resources; when it is burned, the only emission is water.

PriceWaterhouseCoopers (PwC) noted in a 2020 report that green hydrogen exports could be worth US$300 billion/yr by 2050, supporting 400 000 jobs globally.1 BP has announced ambitious hydrogen plans for the UK’s Teesside port. In addition to a blue hydrogen project, it now aims to build a green hydrogen plant that will use renewable sources. HyGreen Teesside will have the potential to deliver 30% of the UK’s 2030 target for hydrogen production. Ineos, a UK-based chemicals company, also announced plans to invest US$1.37 billion in its Grangemouth refinery to produce blue hydrogen for export. “This will include capturing CO2 from existing hydrogen production and the construction of a world-scale carbon capture enabled hydrogen production plant”, noted the company.

In September 2021, the port of Rotterdam and DeltaPort Niederrheinhäfen joined forces to create a regional import hub to supply industries in the northern Ruhr area of the Netherlands with green hydrogen. Potential clientele include Thyssengas, energy company Eon, and cold-store operator Nordfrost.

In November 2021, Shell and Norsk Hydro announced a joint effort to produce hydrogen from renewable electricity with the goal of decarbonising operations and supplying heavy-industry and transport customers. The companies are now identifying European locations to produce gas using large-scale hydrolysis plants.

In December 2021, Spain’s government announced that it would spend €7.8 billion on renewables, green hydrogen and energy storage over the next two years, with the aim of attracting a further €9.45 billion in private funding.

Approximately €1.55 billion is to be allocated toward the development of green hydrogen through the country’s abundant sun and wind, with the goal to supply 10% of the EU’s target output by 2030. The rest would go toward smart-grid infrastructure, energy storage, training and research.

Additionally, in December 2021, Rolls Royce announced that its container terminal, currently under construction in Duisburg, Germany, will be partly powered by climate-neutral energy supplied by its latest hydrogen technology. The port, located at the junction of the Rhine and Ruhr rivers, is the largest inland terminal in the world, annually processing 20 000 ships and 25 000 trains for the 30 million nearby consumers, as well as iron, chemical and steel industries.

Rolls Royce fuel cells and hydrogen heat and power will supply peak load coverage for docked ships and related terminal needs. The four-year project is being funded by the German Federal Ministry for Economic Affairs and Energy as part of the government’s Hydrogen Technology Offensive.

All of this spells significant opportunity for new tanks and terminals; while hydrogen can be partly mixed and transported using existing natural gas networks, pure hydrogen causes brittleness in regular steel and requires dedicated infrastructure.

Middle East Egypt’s energy sector is on a roll. Over the last six years, 38 trillion ft3 of gas has been discovered, with the giant offshore Zhor gas field pumping 2.7 billion ft3/d. Two LNG trains and related export facilities at Idku and Damietta

Spring 2022

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have been recommissioned with the intent of shipping gas to Europe and Asia. The country has grand designs to become a regional energy hub, with plans to build terminals to receive Middle East oil and tranship it to Europe.

In September 2021, Brooge Petroleum and Gas Investments commissioned its Phase II storage facility in the UAE port of Fujairah. Located on the Gulf of Oman, Fujairah is connected to Gulf oil production via a 1.8 million bpd crude pipeline. The second phase adds 600 000 m3 of storage, bringing total capacity to 1 million m3, or 6.3 million bbl of crude. The move is part of efforts by the UAE and the US to expand total storage capacity to 17 million m3 by 2025 (approximately 100 million bbl of crude), in order to counter Iran’s threat to disrupt supplies flowing through the Strait of Hormuz chokepoint. In addition to storage expansion, the port has also built jetties to accommodate very large crude carriers (VLCCs).

Saudi Aramco is one of the world’s largest producers of grey hydrogen, primarily for upgrading crude. A major focus will be to capture the carbon emitted during the production of grey hydrogen and sequester it in order to create blue, or carbon-neutral, hydrogen. In addition, Saudi Arabia’s ACWA Power Corp. and US-based Air Products & Chemicals have entered into an agreement to construct a US$5 billion plant in the desert city of Noem to produce green hydrogen through the use of solar-powered electrolysis. Egypt said it would invest up to US$4 billion in a project to create hydrogen through electrolysis powered by renewable energy.

In order to maintain its dominant position in the LNG market, Qatar has announced plans to increase its current capacity of 77 million tpy to 126 million tpy by 2027. It is entertaining overtures from supermajors (Shell, Eni, Total, ExxonMobil and others), eager to participate in the development of the supergiant North Dome field, a 6000 km2 (along with Iran’s 3700 km2 South Pars portion) trap holding at least 1800 trillion ft3 of gas and 50 billion bbl of gas condensates. The world’s largest non-associated gas field allows Qatar to expand its capacity by 64% without compromising withdrawal rates. The country, which has the lowest breakeven point for LNG, has signed major deals with the Chinese to take significant amounts of the new capacity.

For the last several years, Oman has been proceeding with the Duqm project, a massive development of refinery and petrochemicals, located in the port of Duqm on the Arabian Sea. The project includes the 230 000 bpd Yousuf Al-Jahdhami refinery, set to come online in 2023, as well as a planned Liwa Plastics Project (LPP), which will produce 900 000 tpy of ethylene for use in high-density polyethylene and polypropylene. As part of the development, the nearby Ras Markaz Oil Storage Park will have an initial capacity of 26.7 million bbl when it opens in 2022, with plans to increase capacity to 200 million bbl. The majority of Duqm’s output is earmarked for China; billions are being spent to expand the ports export terminals.

The long-awaited development of a world-class container port at Al Faw in Iraq finally began in August 2021, with the laying of a ceremonial cornerstone by Prime Minister Al Kadhimi.

South Korea’s Daewoo Engineering and Construction has been contracted to build five unloading berths and a container yard.

When completed in 2024, the US$9.6 billion project will be able to handle 3 million containers annually.

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Challenges In November 2021, work on a shipping port near Abu Dhabi in the UAE was halted due to pressure from the US. China has been developing the commercial Khalifa port for the last several years. US intelligence indicated that Chinese military vessels disguised as commercial vessels were entering the port and docking at a military facility. The UAE denies that they have any agreement with China to develop a military base, but the US is concerned with the proximity of Chinese intelligence assets to its major troop facility at a nearby Emirati air base.

Strife continues to embroil the region. A protracted civil war in Yemen, fuelled by Iran and Saudi Arabia, continues to displace millions within the country and disrupt oil and gas activities. In late August 2021, drones attacked a tanker in the north Arabian Sea off the cost of Oman, killing two. The US and UK governments condemned Iran for the attack.

The future Fuel demand is slowly rebounding in Europe. By mid-2021, Italian regulators reported that demand for refined oil products had climbed almost 20% from the previous year, returning to pre-COVID-19 levels. Spain also reported similar increases as travel restrictions eased. In Poland, refiner PKN Orlen reported that utilisation increased to 78%, up from 70% a year prior.

Austria’s OMV reported utilisation rates of 93% at its Petrobrazi refinery, and Unipetrol reported that throughput at its Czech refineries rose 108%, and utilisation by 38%.

Uncertainty regarding Russia’s export of natural gas to Europe still hangs over the continent. If Europe experiences a cold winter,

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storage levels could theoretically fall to zero by March 2022.

Wood Mackenzie has suggested a potential solution: tap into 10% of the 150 billion m3 of ‘cushion gas’ in existing underground storage. Normally, cushion gas is not allowed to be sold as it has the potential to compromise the long-term viability of reservoirs, but if Europe is faced with such dire circumstances, regulators would be able to find a way to free up 15 billion m3 – enough to meet demand for several weeks, or more.

The future for hydrogen looks promising. Depending on the location, the cost of producing grey hydrogen from natural gas is currently around US$1/kg. Using renewable energy pushes the cost to above US$5; the US Energy Infirmation Administration (EIA) estimates that technology innovation and increased deployment have the opportunity to reduce green hydrogen costs to as low as US$1.30/kg by 2030. While bespoke tanks, terminals and pipelines already exist for hydrogen, the massive proposed increase in its use will require an expansion of greenfield infrastructure in Europe and the Middle East to handle both its domestic consumption and exports.

In conclusion, the hangover from COVID-19 persists, and is negatively impacting energy infrastructure in both Europe and the Middle East. The prospects for hydrogen look very bright, however, and portend a massive new market for terminals, tanks and related equipment over the next decade, as both regions move toward carbon-neutrality.

References 1.

'The dawn of green hydrogen', Strategy&, (2020), https://www. strategyand.pwc.com/m1/en/reports/2020/the-dawn-of-greenhydrogen/the-dawn-of-green-hydrogen.pdf

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Tim Hoffmeister, Implico Group, Germany, outlines the central role of the smart tank terminal within the ongoing energy transition, highlighting its ability to reduce emissions, handle alternate products and react to new developments.

A

rguably, the energy transition – which can be defined as the permanent shift away from fossil fuel energy sources to cleaner alternatives – is the most substantial movement of our time. It has a global sphere of influence, affecting each layer of society and impacting every aspect of our daily routine, be it personal or professional. In the eyes of many, it even marks humankind’s last given chance to ensure that upcoming generations will still be able to grow up in a stable, sustainable and future-ready environment.

Given its immense scope and magnitude, it comes naturally that the energy transition has a strong bearing on all sectors of

the economy, too. This is especially valid for the processing, storage and trade of hydrocarbons, as the usage of petroleum products has been tightly knit into our everyday world.

Hydrocarbons are used to fuel traffic and transport; to heat homes and cook meals; to create plastics and other synthetic materials; and much more.

The realisation of an event as vast as the energy shift is not a matter of simply flicking a switch. Rather, it is an elaborate transition, whereby meaningful progress is made along the way.

This is happening right now: the phase-out of various emissions-heavy means of energy production, such as lignite, has already been initiated and executed in many countries around the world. E-mobility is on the rise in numerous markets (both emerging and established). The subject of alternative fuels is constantly being pushed forward, with hydrogen currently rated as a promising option for addressing and achieving the agreed-upon decarbonisation goals.

However, it is clear that traditional fuels will not disappear anytime soon, and it is important to recognise the gigantic transport fleets carrying goods across the globe on road, rail,

11 Spring 2022

water and in the air, as well as the 1.2 billion motorcars inhabiting the streets across all continents.1 In order to uphold global trade and economy, society will continue to rely on classic energy sources for many more years. However, the progressive alteration and broadening of our energy mix, expanding it by a growing number of alternate sources with increasing impact and significance, is vital.

Finding new ways to meet the rising energy demand As progress is gradually made on the journey towards sustainable energy generation and usage, there is one particularly brightly-shining beacon: the binding treaty of the Paris Agreement from 12 December 2015, whereby 196 international parties consented to limiting the rise in global temperature to well below 2°C by 2050. This is a very demanding goal, especially considering that this limitation of the global temperature rise has to happen against projections that the world population – and with it, overall energy use – will grow significantly in the next decades.

Going forwards, it is therefore crucial to ensure that the ever-rising energy demand is permanently met with carbon-neutral power sources and alternative fuels derived from clean electricity and renewables. In other words, it is essential that society finds feasible ways to get more of the good (usable energy, yielding fuel) while simultaneously producing less of the bad (eco-threatening emissions, irrevocable exploitation). This is a tough equation to solve.

Bringing the tank terminal into focus The tank terminal will play an important role in mastering the ambitious task described above.

Since it directly resides at the junction between upstream and downstream, the tank terminal has meaningful touchpoints with all relevant industry partakers and stakeholders – from producers to forwarders, and from sellers to buyers. Consequently, every improvement made at a tank terminal will also have an effect on the rest of the supply chain, and vice versa.

Figure 1. Tank terminal.

Spring 2022 12

As an example: if we want to propel larger parts of our economy with alternative fuels such as green and blue ammonia, it is necessary to ensure that the fuels can be adequately stored somewhere. The logical solution is to re-equip existing tank terminals in such a way that they can handle alternative fuels as well, and to design new ones in a way that they can do the same.

On a physical level, this means that certain assets (e.g. pipelines, compressors, etc.) must be outfitted in a way that secures safe and sufficient handling of additional products. On a digital level, it means that the heart of the terminal – the terminal management system (TMS) – must be smart and flexible in order to quickly adapt to altered or all-new processes. With regards to the latter, shared cloud solutions provide an advantage. Based on use cases and best practices from numerous operators, these technologies are constantly developed to ensure up-to-the-minute functionality. The monolithic individual solutions, which are still in use at many plants, do not have such agility. In order to keep up with the times, a tank terminal running on such a legacy system would usually need to maintain its own IT department and invest time and manpower into keeping the software updated. In times of strict capital discipline and hard-to-predict market development, few companies still have this luxury.

Collaborating along the supply chain The industry’s need to adopt shared cloud services introduces another crucial topic: collaboration.

To this day, many partakers in the hydrocarbon industry remain somewhat reluctant when it comes to sharing software, data or insights with partners or even peers. Often, even the gainful move to the cloud is questioned because companies fear that it would mean a loss of control and a risk to security.

Practical experience shows, however, that the opposite is the case. Looking ahead, the broadening of perspective and a change in mindset across the industry will become mandatory. Regardless of the size of the company or the eagerness to innovate, it is difficult for a single enterprise to master the energy transition all by itself. As such, one major success factor is collaboration along the supply chain, especially at the friction points where physical products or digital information change hands.

This does not mean that energy companies should lay all of their operations bare. The market will always remain competitive. Within these confines, however, companies can work to establish and further promote a culture of transparency, interlinkage and cooperation.

The industry has already reached a point in time where well-guarded silos and isolated monoliths are no longer suitable in many areas of work, and they will become increasingly obsolete in the years to come. Shared cloud

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services, on the other hand, will unlock new potential and enable forward-thinking business models and offers.

A good example of a cloud service resulting in mutual gain is the online check-in for trucks at tank terminals. This helpful auxiliary is connected to both the plant’s terminal management system and the haulier’s tour planning system. It provides drivers and dispatch operators with the chance to handle the time-intensive check-in process at the gate prior to the truck’s arrival, and it helps streamline the onsite traffic on the basis of readily-available information on key topics such as asset status (e.g. loading bay availability or tank contents).

Aside from making the multi-step entrance-to-exit process easier for all parties involved, advantages of online check-in include the following: quicker truck handling, better traffic guidance, less queueing, reduced risk of empty runs, paperless operations at both the tank terminal and the haulier’s headquarters, and more.

Optimising asset usage When it comes to asset usage and overview, the digitalised tank terminal also has meaningful advantages. In the age of the Industrial Internet of Things (IIoT), equipment is increasingly given a voice. Via sensors, instruments and devices, the components are closely and permanently connected to the terminal management system at any time, providing real-time insights and status updates. This helps to identify inefficiencies or anticipate wear out at an early point. Therefore, the terminal crew has the opportunity to take quick action and, in many cases, significantly prolong the life cycles of gear. Additionally, the transmitted data

provides a sound basis on which individual workflows can be adjusted, in favour of rendering overall operations more streamlined and sustainable.

Conclusion The scenarios and examples outlined in this article are united by a common thread: digitalisation.

Whether a company’s aim is to make a small improvement or aspire to implement a massive reform, the one thing that is crucial is to embrace and leverage the usage of smart, forward-looking technology fuelled with comprehensive data, as the gains are plentiful.

Among others, the advantages include more aim-oriented workflows, leaner management of onsite traffic and improved asset usage, as well as better partner integration, paperless terminal administration, and the facilitation of new service or product offers. Making progress in these areas will help to persistently reduce a tank terminal’s carbon dioxide (CO2) emissions and render its overall operations more efficient, sustainable, transparent and future-ready.

Luckily, a company does not have to start from scratch, as digital transformation has been a topic in the hydrocarbon industry for a while. Many tank terminals, as well as other upstream and downstream units, have already made progress in this area, providing a solid foundation to build upon, one meaningful step after the next.

Reference 1.

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Danny Constantinis, EM&I Group, Malta, explains why robotic and digital technologies will play an important role in supporting storage facilities for cryogenic products.

E

nergy is critical to all economies – particularly emerging economies, as they cannot develop without adequate and reliable power supplies.

The transition to cleaner energy will inevitably require new technology for storing energy, be it oil, LNG, carbon dioxide (CO2) or hydrogen.

Supply chains have been stretched to the limit during the pandemic, and this has highlighted the problem with the current ‘just in time’ philosophy which cannot cope with unexpected disruptions.

15 Spring 2022

Inevitably, more (and different types) of storage will be required in the future to overcome these problems, and storage facilities – such as tanks – will need remain ‘fit for purpose’ throughout their operational life.

Inspection and maintenance will need to be carried out as safely, quickly and efficiently as possible to maintain the availability of tanks. Shortages of oil, gas and other specialist chemicals have all been experienced during the COVID-19 pandemic, so strategic reserves need to be established for most industrialised countries to cope with future disruptions. This in turn means more available storage capacity.

Keeping tanks safely in service can be made more efficient and a lower risk to workers by using robotic

methods of inspection, starting with designing or modifying assets to enable remote systems. Preferably, access ports to allow for robots to be inserted into tanks will need to be part of the basic design rather than introduced retrospectively.

Safety incidents in confined spaces have spiked in recent years. As such, risk assessments should be based on an acceptable level of safety set by the directors of the companies concerned, due to the huge financial, reputational and legal implications concerned (e.g. corporate manslaughter) if they knowingly allow more dangerous methods to be used when safer methods are available.

Robotic inspection will also play a greater part in inspecting storage facilities for cryogenic products, as robots can operate at much lower temperatures than is practical for manned entry and this saves out-of-service time when warming up and cooling down tanks.

EM&I has developed a number of robotic and digital technologies as a result of its leadership of joint industry projects (JIPs) for the oil, gas and floating offshore wind industries. These have been particularly successful in improving safety and efficiency whilst reducing manpower and costs.

Although there has been a lot of publicity surrounding renewables such as floating wind, solar and wave energy, there is no doubt that oil and gas will be a prominent feature of the energy mix for many years.

The oil and gas industry

Figure 1. A NoMan optical camera.

The oil and gas industry produces US$1 trillion of tax every year and employs approximately 6 million highly-skilled people worldwide, whereas renewables often require subsidies. It will take decades to gradually wind down this industry, particularly because of the rapidly increasing demand for petrochemicals, which require crude oil as the basic feedstock. Storage of oil products is a well-established process that will still benefit from improved inspection and maintenance methods.

Storage on floating storage regasification units (FSRUs) is a useful capability and enables hydrocarbon ‘atoms-to-electrons’ technology to quickly deliver power to areas where there is no effective grid structure. Again, the inspection of storage facilities will benefit from advanced methods.

Hydrogen in all its forms

Figure 2. A floating storage regasification unit (FSRU).

Spring 2022 16

Hydrogen will play an increasing role in clean energy usage, which can help to cope with the ‘intermittency’ of renewable energy. However, the methods of hydrogen production have different degrees of environmental impact, and the challenges of transportation and storage are yet to be resolved.

Green hydrogen is the most environmentally friendly as it is generated by using renewably-sourced electrical power, such as solar or wind,

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Figure 3. A NoMan laser scan of LNG membrane test

piece.

to electrolyse water. In some ways, the hydrogen produced can be considered as a ‘battery’ that enables electrical power that would be wasted or difficult to distribute by grids to be ‘stored’ in the hydrogen gas.

Hydrogen needs to be stored and transported at very cold temperatures, which is itself a challenge. One solution is to use a carrier gas such as ammonia, which has a high storage density and is easier to liquefy (-33˚C). There will be an important market in future for hydrogen electrolysis plants and facilities for storage before transportation to regions where the energy is required.

The facilities themselves – the storage and the transportation methods, primarily ships – will also need regular inspection and monitoring, which in turn means additional drivers for developing robotic and digitised methods to carry out this work with minimal out-of-service time.

For many other liquids and chemicals that are not ‘temperature sensitive’, multi-purpose tanks and terminals may be desirable in the future. The geographical position of tanks and terminals should ideally be convenient for port facilities so that alternative sources of supply can be used if pipelines are not practical or reliable.

In many cases, the ability to receive and store fuels in liquid form for regasification to a nearby thermal power station is served by FSRUs. These are being used increasingly, particularly in remote locations with little infrastructure or islands with peak seasonal demands, as they can be made available quickly and economically compared with onshore facilities, and can be supplied from anywhere in the world. Some are also equipped with power generation so that they can become offshore power plants as well.

New robotic inspection technologies It is clear that future storage will involve low temperature facilities both on and offshore. New cleaning, inspection and maintenance technology is required. The old methods need to be challenged and the regulatory framework undoubtedly reviewed in order to make the operation of floating LNG (FLNG) and hydrogen assets as safe and Spring 2022 18

efficient as possible. The FloGas JIP is currently focusing on LNG and is looking at issues such as the frequency and execution of tank inspections, and whether putting people into these areas can be avoided in the future.

The traditional approach is the following: prior to entering the dockyards, LNG trading vessels are warmed up, gas freed and opened up for a visual inspection. The classification society surveyor will focus on areas such as the pump and pump tower, and the tank bottom sides, to look for deformations or bonding issues and to establish leakage rates.

For the FLNG units, where the systems remain ‘live’ either by virtue of production or by send out, the time taken to remove one tank from service and bring it to a temperature for inspectors to safely enter, can be onerous. Likewise, returning the tank to service can be risky, especially if the thermal gradient exceeds the design parameters of the containment system. The FloGas JIP will explore whether this thermal cycling should be avoided or minimised.

As a result of the success of the Hull Inspection Techniques and Strategy (HITS) JIP, EM&I commissioned a study to see how laser technology can be used to ‘map’ the tank structure and to identify any anomalies in the membrane containment system.

The purpose of the first phase was to trial laser scanning on the various types of membrane containment using optical and laser systems such as the NoMan technology.

Typical anomalies principally included sloshing damage and leaks through the membrane. Trials were carried out in both China and Europe on representative, full-scale test pieces, and a number of challenges became apparent.

One challenge was the highly-reflective nature of the membranes, which had the effect of ‘blinding’ the laser scanner so that certain parts of the lining were not sending the laser signals back to the transmitter. This was overcome by scanning from multiple locations and selecting suitable targeting procedures so that areas that had been reflective in one position were now able to send back data for processing.

Looking ahead Now that the NoMan technology has been successfully trialled on full-scale containment system test pieces in China and the UK, the FloGas Working Group is looking at the requirements to enable the system to work in LNG containment without person entry.

As the basic physics have been proven, the next phase is to consider how these inspection robots can be introduced into the LNG storage space through the limited access available at the pump tower bend, or potentially through the vapour dome.

While still at the proof-of-concept stage, engineers working on this challenge feel confident that solutions are available, and work is underway to try out these systems on live assets towards the end of 2022. When compared with traditional methods, the system is expected to be safer, faster and greener.

Stuart Kenny, Eddyfi Technologies, UK, discusses the role of remotely accessed robotics in the management of tank and terminal asset integrity.

I

n 2022, the idea of remote access robotics for aboveground storage tank inspection is no longer a foreign concept.

Expedited by a global pandemic that forced the industry to rethink how to continue effectively performing structural integrity management amid travel restrictions and limited contact orders, the need for advanced inspection solutions became more pressing than ever before. Under normal conditions, the fundamental goal of keeping workers safe from the inherent risks surrounding confined space entry and working at heights was realised through the use of automated scanner and robotic solutions. While navigating the added complexities presented in recent times, a new

19 Spring 2022

way of working has emerged and redefined the future of tank and terminal inspections.

Historically, large assets such as pressure systems would be shut down for qualified technicians to perform internal vessel assessments directly inside the tank. Recognising how robotics can improve inspection output and reduce vulnerabilities to workers, non-intrusive inspection has since become the accepted norm. The adoption of remote-controlled crawlers progressed rapidly, with an emphasis on efficiency, repeatability and maximising worker safety.

All modalities of non-destructive evaluation technology can be integrated into commercially-available robotic systems, and data acquisition can form part of an automated mechanical sequence, be it ultrasonic thickness measurements, electromagnetic crack

Figure 1. An RMS PA robotic crawler in action.

Figure 2. Defect characterisation.

Spring 2022 20

detection, or close visual inspection. Standard non-destructive testing enabled robotic crawlers are regularly used to locate corrosion in the shell and dome ends, as well as cracking in welds and nozzle attachments.

With the ability to detect corrosion and erosion with a phased array probe head that offers increased speed for collecting high-resolution measurement data, the rapid motion scanner phased array (RMS PA) corrosion mapping solution was designed by Eddyfi Technologies to examine substantial structures such as pressure vessels and storage tanks.

The solution has a detachable R-Scan Array probe for manual corrosion mapping where needed, and the near surface dead zone is minimised. The introduction of automated corrosion mapping removes the hazards that come with rope access, or the increased costs for access to elevated areas by way of scaffolding.

Moreover, automation increases the likelihood of locating wall loss by rasterising an ultrasonic testing (UT) probe across the surface and collecting spot UT measurements at a stable interval. Using the RMS with a phased array UT probe, and either self-contained MantisTM or Gekko® portable tools incorporating the ultrasonic pulser, data storage and multi-touch display with workflow user interface significantly increases the efficiency of each scan.

For reference, a 1800 mm (71 in.) long x 300 mm (12 in.) wide scan with a high measurement resolution of 1 x 1 mm (0.04 x 0.04 in.) would take approximately 55 minutes to complete with a raster scan, using a single crystal probe. With a wider probe, fewer sweeps, and at the same measurement resolution, the RMS paired with a PAUT probe would take approximately 8.5 minutes.

This is a sixfold improvement in corrosion mapping efficiency, and the increased speed allows for 100% coverage.

Phased array is ideal for inspecting critical components with a surface temperature of less than 80˚C (176˚F); a wall thickness between 2 – 200 mm (0.08 – 8 in.); a minimum dia. of 150 mm (6 in.) to flat plate; immersion method with limited variables; and with or without a coating.

The integrated RMS PA solution has an increased probability of detection – as well as higher accuracy – and provides enhanced defect characterisation. The guaranteed 1 x 1 mm resolution is also ideal for detecting microbially induced corrosion (MIC).

This worldwide in-service integrity problem often manifests as isolated corrosion pits caused by biological growth. Real-time display for defect characterisation is made possible with onboard defect recognition, true

Introducing the Palladian Energy Podcast Series 1: Digitalisation in the oil and gas sector

Figure 3. Corrosion area with material losses of 2.2 mm from a 12 mm nominal, found from 1000 km away.

defect shape representation, multi-orientation displays, and 3D imaging with merged data sets. Offline gate manipulation is also possible. This data is necessary for a robust digital twin asset management programme. It can be exported to CSV format and overlaid with periodic data sets to analyse trends and make better informed decisions.

Case study NDE Solutions, a service provider based in Adelaide, Australia, is comprised of a team of experts in inspection technology. The company’s Founder and Director, Kimal Singh, is an expert in advanced ultrasonics. When Kimal received a phone call from one of his onsite scanner technicians, he was met with questions about how to operate the RMS PA corrosion mapping solution and perform the phased array calibration for the system. At the time, Kimal was in insolation due to government restrictions. However, Eddyfi Technologies’ phased array units feature fully-integrated control software, so the scanner is manipulated and driven through the Windows-based graphical user interface on the phased array instrument.

As such, despite being 1000 km away, Kimal was able to remotely login to the phased array tool and perform the calibration and scan on the tank. Having access to the control software, he could easily input the required commands from home for moving the scanner, capturing the high-quality data and remotely analysing the corrosion mapping data in real time.

This solution offered a bespoke learning perspective that would not have been possible had Kimal been on the job site.

Opening up opportunities to comfortably provide support remotely is one of the first steps towards the future of remote inspection with on-demand subject matter experts. Remotely accessed robotics are a possible answer to tank and terminal inspections

Spring 2022 22

burdened by limited access due to travel or similar restrictions.

Another example that supports the case for remotely accessed robotics is the growing concern of operational plant failure leaving no scope for deferment. In this case, data analysis was arranged remotely, but the equipment was incorrectly set up.

The ability to remotely login to the phased array tool and fully integrated robotic controls made it possible to perform the necessary calibration sequence, robotic manipulation and data acquisition from 1100 miles away.

This example demonstrates the technology’s increased utilisation with limited expertise.

Conclusion Remotely accessed robotics for tank and terminal asset integrity management not only reduce costs with regards to mobilisation and expertise, but they also allow for immediate decision making with Level III consultancy. The new way of working with remote services as an alternative to full onsite operations helps to ensure improved compliance with calibration sequences and accelerated and enhanced training programmes. Future developments will further improve data input and efficiency.

In conclusion, while the increased use of automation and robotics was anticipated for better tank integrity assessments, there has been an audible step change within the industry, with the newfound capacity to collect 1 mm resolution phased array corrosion mapping data from the comfort of one’s living room. With phased array reducing inspection times, 100% of the data collected while the tank remains online and robotic systems remotely controlled from virtually anywhere, the potential to reshape inspection operations is now a reality, and ongoing developments will continue to drive better data quality and efficiencies for optimal tank integrity management.

Fintan Duffy, Re-Gen Robotics, Northern Ireland, outlines the benefits of robotic tank cleaning solutions through the real-life example of an operation at a refinery in the UK.

U

ntil the launch of 100% no man entry robotic tank cleaning in March 2019, the only option available to terminal operators was to send personnel inside fuel tanks with highly-explosive atmospheres, using breathing apparatus and chemical suits.

Traditionally, people have had to enter oil tanks to implement inspections, de-sludge, and clean for product change. Although safety regulations and industry standards are stringent, accidents can occur due to human error and the failure of safety devices. Exposure to

hazardous petrochemicals, heat stress, lack of oxygen, slips and falls, fires and explosions are the main risks faced by personnel who manually clean oil tanks.

In response to the rising number of confined space deaths, and after years of extensive research, a patented solution was developed to help ensure that workers are not endangered by operations carried out in hazardous confined spaces.

Four main robotic tank cleaning services for fixed roof, floating roof, heavy fuel oil (HFO) and coned floor tank cleaning are offered. The operator remains in a Zone 1

23 Spring 2022

control unit where activity is scrutinised through a series of ATEX cameras and gas monitoring equipment fixed to a robot.

The entire tank cleaning system can be set up in 2 hours, which is a fraction of the time required for human crews to prepare for tank entry. Primarily, however, it removes individuals from hazardous spaces filled with chemicals and gasses that can lead to serious long-term health issues.

No man entry tank cleaning solutions have clear advantages for tank terminal operators: there are fixed costs, reduced paperwork and permits, and no requirement for capital outlay or standby rescue teams.

Since 2019, 10 000+ hours of confined space cleaning have been eliminated, leading to an overall reduction in both accidents and health and safety incidents onsite. The bar for safety has been raised in an industry with potential dangers, and the frequency of injuries and fatalities in the tank terminal sector has been significantly reduced.

Case study Following a full demonstration of its service, whilst cleaning a 48 m crude oil tank with steam coils, Re-Gen Robotics was commissioned on Phillips 66’s Humber Refinery site in North Lincolnshire, England, to clean a 50 m fixed roof, cone-up floor crude oil tank.

Phillips 66 Humber Refinery is one of the most complex refineries in the company’s portfolio and one of the most sophisticated refineries in Europe. The vast range of products it produces not only includes fuel, but also raw

materials that are transformed into everything from essential components for electric vehicle (EV) batteries, to toiletries. Approximately 20% of all UK petroleum products come from the Humber Refinery.

Given the information provided by the client, Re-Gen Robotics received a sample proposal on the indicative timings and cost of the tank clean, as exact tank furniture details and volume of sludge were unspecified.

The team then visited Phillips 66 onsite to gain a detailed understanding of the scope of work.

Following the site visit, a final proposal outlining the method, timeframe and cost was provided.

The tank had numerous steam coils which the robot was required to navigate. The volume of waste inside the tank was understood to be approximately 135 t and the product temperature was ambient.

This was the first no man entry tank clean for Phillips 66 and the company was pleased at the prospect of eliminating the need for personnel to physically enter the tank.

The robotic tank cleaning system has an offset suction head to allow meticulous cleaning underneath heating coils, as well as an auger system for the removal of heavy sludge.

In addition, it has front and rear ATEX CCTV and lighting for easy internal tank navigation and inspection. This tool alone can decrease tank cleaning time by 10 – 12%.

Using high pressure, low flow jetting systems, and a powerful 4800 m3 vacuum, the heavy oil tank cleaning robotic system was designed to easily fit through a standard 600 mm manway, using externally-fitted hydraulic ramps.

Results

Figure 1. Self-contained cranage system.

Figure 2. Control room.

Spring 2022 24

The operator remained in the Zone 1 control unit where he could monitor activity through a series of ATEX cameras and gas monitoring equipment that was fixed to the robot.

In total, 536 t of sludge was removed from the tank, with 92 t of water utilised during the entire tank clean.

Robots use up less water than human crews use when cleaning the same tanks. The robots also clean the tanks in half the time that humans do, reducing environmental impact.

Traditionally, it would have taken a team of six men 95 days to complete the clean. Using no man entry cleaning, the three-man team took 43 days (1520 robotic hours) to complete the job (30 of those days were spent on sludge removal alone).

Overall man hours onsite were reduced from 12 160 to 1032 and the standby rescue team was not required. Re-Gen Robotics is classed as a medium risk contractor, therefore less paperwork and permits were necessary. In addition, there was no requirement for capital outlay or spading of the tank, which can take a full day to accomplish.

Upon completion of the tank clean, client feedback was positive. This was the first tank to be completely cleaned and inspected by the company without the need for human presence in the tank.

Following the initial contract, Re-Gen Robotics was commissioned to clean a further three tanks at the site and has recently been included in the tender process for 14 tanks

over the next three years. At present, the company is 75% through its clean on the second of the three tanks.

Phillips 66 has acknowledged the success of the no man entry tank clean because the system could be adapted to suit the company’s individual needs and timeframes, resulting in safer, faster and cost-effective tank cleaning, with measurably better results than the man entry method.

The entire tank cleaning operation was recorded on CCTV from the ATEX cameras and was made available to Phillips 66 upon completion of the works. All files are date and time stamped to ensure the process is traceable for auditing purposes.

A record of gas detection readings was produced by the onboard gas monitoring equipment and issued on completion of the tank clean. The intelligent onboard truck telemetry system collects data that can then be aggregated and analysed to optimise the process. The combination unit provides real-time information on all key parameters, which helps monitor energy consumption and waste generation, and is vital for both conserving funds and running a cleaner, greener business.

Conclusion Hazards relating to tank cleaning are as many and varied as the designs and physical dimensions of the tanks themselves. As such, robotic tank cleaning technology continues to develop at pace so that the equipment can perform an increasing number of tasks remotely.

Rapid technological advancements are powering this new generation of smarter, more mobile, and safer robotic tank cleaning systems. They are dexterous and versatile and can navigate and work in their environmental using multiple sensors, while operators remain in an air-conditioned control room, protected from hazardous conditions.

Applying fully-integrated, 100% no man entry, closed loop robotic cleaning technology could make a significant difference to safety in the oil tank industry. Robotic tank cleaning is eradicating industry fatalities and decreasing all risk categories by eliminating human exposure to confined spaces.

In terms of speed and efficiency, the robotic system completes a job 40 – 80% faster on average than a manned crew. For example, a white oil tank that would usually take eight days to clean with an eight-person team can now be cleaned in two and a half days with just two people operating the robot. It has eradicated the requirement for 260 man hours of confined space entry, carrying with it an enormous safety benefit.

The last two years have been a groundbreaking time for the industry with respect to health and safety, and there has been a paradigm shift in attitude towards safety in the tank cleaning industry. To date, over 30 tanks consisting of white oil, black oil and distillate tanks in gas plants have been cleaned and the first worldwide, 100% no man entry tank cleans for oil majors such as Shell, Phillips 66 and Vermilion have been completed by Re-Gen Robotics.

These companies have now adopted no man entry tank cleaning and this service sits at the core of their safety strategy.

To this end, Shell has made a commitment to end manned tank cleaning across its operations by the end of 2022, with other majors looking at 2025.

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Gurjeet Bansal, IntelliView Technologies Inc., Canada, highlights how automating remote monitoring with AI cameras can cut time, effort and costs, whilst improving safety and reducing environmental impact.

W

hen the control room receives an alarm, perhaps from a leak sensor or even a flame detector, several steps are taken to confirm validity and assess the severity and location of the problem. Operators might follow up by checking the

27 Spring 2022

readings from another sensing device, such as a flow gauge or a gas sniffer, to eliminate malfunction as the cause. If still unsure, a technician equipped with appropriate safety gear is sent to the site to visually confirm the event that triggered the alarm and take necessary action onsite – which may be to repair or to call for backup.

At intermittently-manned or remotely-located terminal or storage facilities, days can go by before confirmation is received and action can be taken. Delays from this lack of visual access can be caused by a number of uncontrollable forces. Extreme weather, safety concerns or staff shortages, for instance, can postpone a site visit by a day or two, and also stretch windshield time.

An alarm’s validation time can highly influence the ability of an operator to manage incidents. The longer the response time, the more challenging and resource-intensive it would be to limit or avoid adverse impacts on many aspects of an operation – from

productivity, asset integrity and the environment, to worker safety.

Managing multiple issues at scale with current approaches (or blindly) can diminish operational efficiency and add financial stress. Additionally, as pressures mount to reduce costs while at the same time improve health, safety and environment (HSE) and business performance, operators are turning to centralised operations management and a range of automation toolsets that support these objectives.

Automating monitoring Oil and gas companies can “better manage their resources and data, improve safety, boost productivity, and increase profitability” by automating certain repetitive processes, according to Blancett et.al.1 Remote maintenance, remote monitoring and control, and human/robot collaboration have been identified by the McKinsey Global Institute to be some of the key functions that have the highest potential for automation in upstream and midstream operations. 2 The findings also suggest that automating these processes, along with other related measures, could cut maintenance costs by up to 40% and bring approximately 50% gain both in worker efficiency and asset utilisation.

Mainstream visual monitoring tools

Figure 1. The potential of automation in key oil and gas functions.

Source: the McKinsey Global Institute.

Table 1. A summary of vision technologies used in the oil and gas industry Features

Platform Handheld

Mounted

Fixed (non-AI)

Fixed (AI-powered)

Continuous

No

No

Staff limited

Yes

Real-time detection

No*

No**

No*

Yes

Fast validation

No*

No**

No*

Yes

Location estimate

Yes

Yes

Yes

Yes

All-weather

No

No

Yes

Yes

Operator safety risk

Yes

No

No

No

*Unless incident occurs during survey **Unless with AI or manual monitoring and incident occurs during survey

Spring 2022 28

Currently, for asset condition monitoring, maintenance inspections, leak detection and repair (LDAR), as well as security surveillance, the prevalent vision technologies within the industry are manned and/or mobile.

Handheld cameras, such as those used for leak detection or surveys, offer mobility benefits and manoeuvrability for hard-to-access areas.

However, being closer to equipment also means that the operator can become exposed to both known and

unknown environmental hazards at the site (e.g. toxic products and potential fire or explosion).

Mounting thermal cameras on vehicles or drones, often implemented for surveying vast areas or distant targets, effectively circumvents this safety challenge, but on the downside, the greater distance could also weaken sensor sensitivity. While both are enterprise-use friendly, their viability is significantly decreased in situations where strong winds or heavy snow can damage the equipment or affect sensor performance.

Stationary standard cameras are another method used for visual monitoring. They serve as eyes onsite via live and recorded video, but rely completely on manual monitoring, which is tied to high labour costs. Moreover, the job of watching multiple monitors for hours on end, especially during night shifts, is known to contribute to personnel fatigue, which could lead to missed incidents.

Additionally, streaming high-definition video for early detection can be infeasible – especially at remote locations – due to cost and infrastructure limitations.

Such platforms – when deployed in their intended frequency (intermittent) – are unable to provide real-time detection, unless the event of interest takes place during the survey. Being resource intensive, they are extremely impractical and expensive for continuous monitoring, which is imperative in high consequence facilities where incidents such as petroleum or gas seepage need to be addressed right away. These arguments make a compelling case for automating vision-based monitoring processes.

Automating cameras with artificial intelligence Powering cameras with artificial intelligence (AI) allows for continuous, autonomous operation at the edge. This integrated architecture not only automates monitoring and detection, but also provides remote visual access to facilities through the video and picture evidence generated with the alarm, as well as recorded footage.

AI can be processed in the cloud where data is first streamed to a remote server, or in real time through an analytic engine onsite. Edge-based AI has several advantages. Because video compression is not necessary prior to processing, the algorithms are applied to the highest quality radiometric data available direct from the sensors and in real time. This translates to higher accuracy and faster alarm delivery while keeping network bandwidth consumption at a minimum, as video data is only transmitted during an alarm.

Video analytics technologies have come a long way from simply detecting a thief or a coyote. Recent advancements have made more complex and pixel-data analysis possible in order to achieve increased detection accuracy while also lowering the number of daily false positives to near zero – the bane of camera automation.

Some of the key capabilities of AI cameras include: nn Complex analysis, which may be challenging or impossible for a person to accomplish. nn Multi-region analytics within one field of view, which allows for more than one unique detection

nn nn

nn nn

condition to be programmed (e.g. security and leak, wildlife and fire, monitoring products that have varying temperatures).

Co-relating of thermal and colour images to match perspectives and improve ease of visual validation.

Application of layered software solutions (e.g. algorithms, detection settings, machine learning, environmental filters, deep learning neural net object classification, and edge and cloud processing).

Many viewing options: live, recorded, zoom/full screen, analytics overlay, and pan-tilt-zoom features.

Multiple reporting options: control room, email, phone, SCADA, and web-enabled device applications.

Thermal vs colour – which sensor to choose?

Colour cameras, with high resolution and picture-perfect output, show exactly what the human eye would see. As such, it is easy to put complete confidence in this tool without realising that what is invisible to the naked eye will also remain hidden.

Thermal imaging, on the other hand, creates images from converting the heat signature of objects. Albeit in greyscale, thermal videos reveal much more than a colour camera, including the unseeable. Oil, bitumen, diluent, water/brine, vapour, steam, and NGLs such as butane and propane can be visualised by long wave infrared (LWIR) sensors. Fire and temperature are also visible.

For methane detection, mid-wave infrared (IR) sensor based optical gas imagers (OGI) are the gold standard.

This type of OGI is cryogenically cooled. As such, maintenance is heavy and expensive. However, owing to more recent innovations and demand for lower-cost alternatives, the newer uncooled microbolometers (LWIRs) now come with sensitivities near the 3 g/s (10 kg/hr) mark, which is sufficient for most cases, and with future development may soon also provide more reliable quantification.

While colour and thermal sensors are typically used independently of each other, their parallel implementation enhances remote monitoring capabilities. Given their friendliness to the human eye, colour videos are the prefect tool for validating thermal videos. Side-by-side deployment of dual sensors (thermal/colour) within an analytic platform also allows for the potential to implement AI software on each sensor, permitting even greater multi-target monitoring.

Camera lenses are available in a variety of specifications: from wide to narrow fields of view, sensitivity levels, detection ranges, and image resolution (HD, FHD, etc). Finding the right configuration would not be challenging. However, a small compromise could be inevitable. One example would be budgetary constraints restricting the number of cameras that can be installed per site. This could translate to less than full coverage.

The key to achieving greater or complete coverage in a cost-effective manner is prioritisation of the most critical and high-risk sections of a site, and supplementing this with other approaches.

29 Spring 2022

Figure 2. The IntelliView DCAM consists of a thermal sensor, a colour sensor, and built-in AI engine. It is designed to automatically detect and sound an alarm on pre-defined events. Thermal and colour images are rendered side-by-side, with analytic software tracking displayed to serve as visual aid (left), as shown in the screen grab of a simulated leak at commissioning.

Faster response

Figure 3. Installing AI cameras in high-priority regions is a cost-effective way to enhance monitoring capabilities. They work in conjunction with other methods, closing close coverage gaps and adding a layer of protection.

The gains of automating with intelligent thermal cameras Intelligent vision technologies can contribute valuably to field monitoring and hold the key to delivering many of the benefits and advantages of automation, across many levels.

Greater, continuous level of awareness

AI replaces hours and hours of manual screen viewing, freeing up valuable time that workers can utilise for more critical tasks, such as maintenance and repair.

Potentially disruptive events that take place during the day or night can be detected without human involvement. Additionally, with the combined capabilities of IIoT and wireless infrastructures, hundreds of enterprise-wide distributed cameras can be streamlined into a single platform, rendering the management of large-scale and complex monitoring needs effortless.

Improved detection

With intelligent thermal imaging, visibility and detection of objects in the dark is significantly improved even without an illumination source. The technology can also see early-stage liquid and wet hydrocarbon releases that are approximately 0.4 l/s in size, which can be up to 40 times smaller than what is detectable through computational pipeline monitoring methods.

Spring 2022 30

An alarm that is pre-validated onsite and accompanied by visual evidence removes the guesswork, allowing operators to confirm, pinpoint the location of the anomaly, and take informed and appropriate action at speed. This could be remotely shutting down the affected area of operations and dispatching a remediation crew instead of commissioning manpower or a drone scan first. AI cameras can also be linked to a control system (e.g. SCADA) to further reduce effort and response times. A midstream company in Colorado, US, uses vision-based leak detection technology in conjunction with a secondary sensor to facilitate autonomous shutdown.

Lower HSE impacts

By having the ability to respond immediately to leaks, fire, theft, or vandalism, the environmental footprint of operations, along with regulatory scrutiny and reputation damage, can be mitigated. Having remote video access to the field, either via alarm videos or recorded videos, provides a safe means for first responders and maintenance staff to conduct situational assessments. Additionally, unaware workers onsite can be warned very early on of the location and status of emerging dangers.

Cost savings

An onshore spill clean-up bill can amount to anywhere between US$300 000 – US$15 million. One example of this is the Buncefield Oil Depot fire that cost Total a little over US$1 billion (£750 million) in damages from tank overspill. Through timely notifications and actionable data, intelligent cameras can help lessen or avoid these financial liabilities, as well as product loss and production downtime. Operational savings can also be achieved by replacing manual video monitoring and in-person trips. Up to 50% reduction in site visit related wages were observed by a global energy company after installing AI leak detection cameras. Furthermore, adding more cameras to a site and more sites to the system will have minimal impact on operating expenses, and the use

of available structures, such as for mounting, will reduce installation costs.

Industry applications for AI cameras Many operations of an oil and gas depot can be automated using AI cameras.

Security monitoring

AI cameras have been extensively used to protect assets from unwelcomed guests, including intruders (humans and animals), thieves, arsonists and vandals. An oil and gas company was able to detect theft using a leak detection camera that was running 24 hr/d at the site. The alarm contributed to the identification and prosecution of the individual involved.

Figure 4. An intelligent vision solution plan for a crude oil terminal of a global midstream operator shows a single 25 mm camera providing sufficient coverage of the areas of interest.

Leak detection

The identification of petroleum product escapees, such as oil, liquids, and gases, is also one of the primary uses for AI cameras in the industry. A global midstream energy operator has installed an IntelliView DCAM system at two sites to survey water tanks (T-500 series) and pumps (K-700 series) for crude oil fugitives. One location is using a 25 mm lens for long range coverage, and the other uses a 13 mm lens to achieve wider field of view at a shorter distance.

Tank level monitoring

Thermal imagers can visualise tank content by detecting the temperature difference between the filled region and the empty region. With AI, product levels can be autonomously monitored to ensure that operations are moving efficiently and that potential overflows are identified before causing a spill.

Flame/fire ignition monitoring

Due to the chemical composition and characteristics of the products handled, tanks and terminals are high flammable and explosion risk zones. Deploying AI cameras for fire, flame and/or temperature detection in tandem with other sensors, whether visual or non-visual, can provide a more reliable early warning. For highly hazardous environments, explosion-proof rated cameras are recommended. They can withstand a significant degree of fire impact and will be able to provide visual data in a safe manner, both during and after an incident, which can assist with investigation and reporting.

Workforce and safety monitoring

Employing AI cameras to monitor personnel, contractors and vehicles onsite provides managers with visual data

that can be used to confirm work hour inconsistencies, improve scheduling, and identify unauthorised presences. Accessing live feeds can also assist in determining whether an asset or facility is safe to approach after an incident, while recorded footage may provide answers to OHS-related concerns.

Remote surveys

Asset and equipment inspections can be conducted from any offsite location (e.g. office, home, airport) at any time of the day, through internet-enabled devices.

This flexibility not only offers substantial time and cost savings through reduction of in-person surveys, but also allows operators to safely gain field insights even in the presence of risky site conditions, staff shortage, and environmental deterrents.

Conclusion With visual verification acting as the foundation of any executive decision making and action, AI cameras are expected to be a major driving force in the future of terminal automation. New applications and platforms (e.g. robotics, predictive tools), growing demands for safety and efficiency, and more stringent regulations will continue to provide the impetus for technology creation and betterment, propelling video AI companies such as IntelliView Technologies to continue moving forward, pushing the limits of their innovations.

References 1.

2.

BLANCETT, J., POCKER, S., and RANJAN, A., 'Automating the Petroleum Industry, from Wells to Wheels', Cognizant 20-20 Insights, Cognizant, (2019), https://www.cognizant.com/ whitepapers/automating-the-petroleum-industry-from-wellsto-wheels-codex4114.pdf McKinsey & Company, 'AI, Jobs and Workforce Automation', (May 2017), https://www.cloudave.com/57719/mckinsey-aijobs-workforce-automation/

31 Spring 2022

COVER STORY

Spring 2022 32

Edward Cass, Paratherm, USA, explains how the risk of fire in thermal fluid systems can be minimised.

T

hermal fluid systems have been operating safely for many decades, across a wide range of industries.

However, it is impossible to eliminate all risk in these systems as the necessary ingredients for fire – fuel, air and an ignition source – are all present by design.

While the established safety record of thermal fluid systems is a testament to proper system design and attentive maintenance practices, not all systems are designed and operated with best practices in mind. The evolution of remote sensing technologies and the Internet of Things (IoT) has helped to make thermal fluid systems even safer in modern times, but there remain several safety considerations for both new and existing systems that designers, engineers, original equipment manufacturers (OEMs) and operators should be aware of. Fire risk in thermal fluid systems can be minimised by understanding the causes of thermal fluid fires and mitigating those causes by observing key installation practices for design, installation, operation and maintenance of the systems.

Causes of fires in thermal fluid systems Fluid and vapour leaks are the most obvious causes of fires in heat transfer systems. Small volume leaks around flanges, valve stems, etc., generally do not present any significant safety hazard.

Leaked fluid usually oxidises, which creates smoke and eventually black stains. Nonetheless, small leaks can become

hazardous if left unaddressed. No leak, small or large, should ever be ignored.

Catastrophic failure of mechanical components such as pump seals, rotary unions or expansion joints can quickly lead to dangerous conditions. High volume leaks create more ignitable vapour, and more material that can find an ignition source in the immediate surroundings.

Explosive discharges may occur from rapid pressurisation of the system. This scenario is commonly experienced when hot oil and water find each other. Rapid vaporisation of liquid water to steam may lift a pressure relief valve, and the steam may atomise oil as it exits. Catch tanks containing water have been known to create this scenario.

Component failures such as pump couplings, malfunctioning bypass valves and plugged Y-strainers can reduce or interrupt the oil flow rate through the heater. Safety circuits are standard for monitoring temperatures and pressures throughout the system. However, if safety interlocks are bypassed, or probes become fouled or unresponsive, a runaway situation can occur, creating conditions for superheated fluid and possible system rupture.

Cracks in heater tubes may form when damaged or worn burners cause flame impingement on the tubes, resulting in localised hot spots that can lead to coke formation. The coke acts as an insulative layer resulting in uneven thermal expansion and fractures that leak oil into the combustion chamber. The oil then adds to the fuel value while the heater is running, but can pool in the chamber when the heater is off, and cause a major fire at start-up.

Start smart: design and installation tips Heat transfer systems should always be designed and/or reviewed by qualified engineers that are familiar with their construction and operation. There are several industrial standards that can be referenced for guidance in the 33 Spring 2022

construction of heat transfer systems. In addition to these standards and OEM recommendations, the next section of this article presents a few tips and best practices to improve the long-term safety and reliability of thermal fluid systems.

Putting it together

Piping networks should be designed for combustible fluid service – sized and installed to provide the required flow rate with an economical pressure drop. Standard construction material is schedule 40 seamless carbon steel pipe. All connections should be welded except where breakable connections are necessary, such as access/maintenance points around valves, pumps and equipment. Class 150 or 300 raised-face flanged connections are recommended, depending on the operating pressures/temperatures. To ensure proper gasket seating, raised-face flanges must have a proper surface finish.

Correct flange alignment is equally critical. Misalignment can result in overstressing one side of a flange while leaving the other without sufficient compression to seal the gasket. Once a flange pair is properly aligned, the lubricated fasteners must be incrementally tightened in a star pattern to maintain proper alignment and even compression. Applying adequate initial preload to the flanged connection will minimise the risk of leaks after system start-up. Once the system has started up, it is wise to ensure that flange bolts are checked for proper torque at normal operating temperature.

Flange gaskets are typically spiral-wound stainless or flexible graphite. Spiral-wound and grooved-metal gasket designs resist blowouts from sudden over-pressurisation, and are constructed for leak-free operation.

Threaded connections should always be avoided where possible. In lieu of threaded connections for instrument gauges/sensors, bendable tubing with compression fittings has

been found to be a satisfactory alternative. Where threaded connections are necessary, the use of schedule 80 carbon steel is recommended, with pipe diameters not to exceed 1.5 in.

(38 mm). Threaded connections should be joined using a thread sealant that is compatible with the thermal fluid and the operating conditions.

Expansion joints should be utilised to relieve stresses from thermal expansion of fixed structures (eg. circulation pumps).

Such joints may include steel expansion loops, or ‘U’ bends, bellows-type expansion joints, or high temperature flexible metal hoses. Flexible expansion joints must be supported on both ends and installed in such a way that they move axially.

Valves tend to be a major source of leaks in thermal fluid systems. Leaks can be minimised by utilising valves with metal bellows (as the primary seal) in combination with high temperature graphite packing (as a secondary seal). In general, globe, gate, and rising-stem ball valves are the preferred choices for thermal fluid systems. Since valve stems are potential leak sources, they should be installed with the stem in a horizontal position if possible (provided that the valve manufacturer does not advise against this orientation). Should a leak occur in this configuration, the fluid will drip away from the valve rather than down into any insulation around the valve.

Keep the air moving

Where possible, heat transfer systems should be installed in open structures. For closed structures, explosion relief construction and adequate ventilation are critical safety considerations. High air exchange rates help to rapidly cool leaked vapour to smoke, and cool leaked liquid to prevent further vaporisation. The general rule of thumb is for fresh air to enter low and exhaust high, maximising contact with any leaking material. There should be air movement around critical areas such as pumps. If the heater room temperature is more than 25°F (13°C) higher than the outside temperature, there may not be enough air flow.

Prevent wicking potential of insulation

Figure 1. Fluid selection is critical to continuous performance, safety and

reliability of the heat transfer system. It is important to specify a fluid that comfortably covers the entire operating range, including start-up conditions.

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It is well understood that a combustible fluid can ignite at temperatures below its published autoignition temperature, if spread in a thin film. The high surface area present in many types of insulation can promote this phenomenon when soaked with a thermal fluid. Open cell insulation, such as mineral fibre, can wick, leaking heat transfer fluid into its porous structure. The wicked fluid proceeds to oxidise, which can raise the temperature of the insulation above the fluid’s autoignition temperature.

Foamed glass insulation is the standard recommended insulating material because it cannot absorb oil.

Leaked oil will pool following the path of least resistance. Weep holes are sometimes drilled through the insulation to prevent excessive accumulation.

Mineral wool or fibreglass insulation can be safely used on horizontal pipe runs where the potential for a leak is negligible.

It is wise to consider installing a metal drip ring to separate the fibrous material from the closed-cell insulation. It is also recommended that the insulation be covered with aluminium cladding to protect from external hazards, and that the use of insulating flanges is avoided wherever possible, as they are potential leak points. If fluid-soaked insulation is discovered, it should be addressed with haste and caution. Cladding and soaked insulation must be removed very carefully and slowly, preferably with the system cooled down.

Pumps and seals

Most high temperature systems utilise heavy-duty cast steel centrifugal process pumps with air or liquid-cooled stuffing boxes and bearings that are suitable for the process temperatures. Mechanical seals constructed of tungsten or silicon carbide are widely used. Mechanical seals should be installed with care, as fingerprints or dust/debris can create leaks. Some pump manufacturers may also specify a seal flush or inert gas purge to keep the seal faces free of debris and assist with secondary cooling. Despite best efforts, pump seals will eventually fail, and should be replaced as soon as they start to leak. A catch pan under a pump is not an acceptable fix, as accumulated oil can auto-ignite.

Seal-less pumps such as mag-drive or canned motor pumps eliminate many of the leakage issues associated with mechanical seals, and are often specified for systems operating above the atmospheric boiling point of the fluid. These pumps

provide enhanced leak protection vs mechanical seals, but are more sensitive to accumulated degradation products and contaminants. Any vibration or noise at the pump should be investigated promptly. Expansion stresses on the pump should be alleviated by installing expansion loops, joints, or flexible piping rated for the process requirements.

Instrumentation and safety controls

Fire potential can be minimised by employing pressure, temperature, and flow monitoring controls throughout the fluid system, and at the process users. All specified components must be compatible with the fluid and the operating conditions, and failure scenarios should be considered during the selection process. Differential pressure gauges, flow control valves and temperature modulation should all be harmonised in such a way that the system responds uniformly to process demands.

Additionally, all safety controllers and components should be included in preventative maintenance schedules to ensure that they are working appropriately. Such controls may include over-temperature protection, low flow protection, expansion tank level alarms/interlocks, and relief devices that trigger when an abnormality occurs. In addition, continuous video surveillance at multiple points of the system can help to identify problems before they become catastrophic.

Catch/overflow tanks

These vessels are typically closed head and dished bottom with a centre-mounted drain valve to allow for complete

draining, and are outfitted with a high-pressure sight glass. The tank vent should be routed out of the heater room to a safe area or adequate containment system. Catch tanks may also be outfitted with fire protection to minimise fire hazard at the discharge point.

Fire containment

In the rare and unfortunate scenario that a fire occurs, provisions must be available to contain and extinguish it as quickly as possible. Remotely-operated fail safes such as pump or fuel shut-off valves can go a long way in preventing a catastrophe. Automated sprinkler systems are recommended for release at critical areas throughout the system, such as at the heat source, in control rooms, and around relief discharges and process users.

Automated deluge protection may also be considered for critical areas. A system of containment dikes and reservoirs should be implemented to safely contain large volume losses.

Figure 2. Routine system reviews should be conducted as part of an operational safety programme, and anomalies should be addressed to ensure long-term safety of the system.

Class B fire extinguishers should be available in all critical areas for emergency response. Fireboxes may be outfitted with snuffing systems designed to prevent tube-rupture fires. These systems typically use steam or inert gas to snuff the combustion chamber in the event of a high exhaust stack temperature failure. Electrical equipment should be designed and installed to prevent ingress of heat transfer fluid.

Fluid considerations and proactive maintenance The thermal fluid flash point is often the first thing that is scrutinised when determining the cause of a fire. In practice, nearly all high temperature heat transfer systems routinely and safely operate at temperatures above their fluid’s flash and fire points, but never above their autoignition temperature. The sequence of events that leads to most thermal fluid fires is nearly always a function of system failures and/or poor maintenance – independent of the fluid flash point. In practice, leaking fluid will cool quickly when exposed to air, dropping below the flash point. Any vapours produced will turn to smoke if the ventilation system is properly designed.

However, excessive heat flux can result in irreversible damage to the fluid, creating low boiling byproducts with lower flash points. These byproducts can reduce the operational safety margin of the fluid. As such, maintaining the health of the heat transfer fluid is also critical to the long-term safety and reliability of the system. In-service heat transfer fluid should be analysed at least once per year, and each time a process upset occurs.

For high temperature systems, testing should include a distillation range analysis to determine whether there are any accumulated low boilers. Excessive low boilers can cause mechanical problems (e.g. pump cavitation or unexpected pressure relief) and can generate higher vapour pressures if leaked from the system. Fluid oxidation level and solids accumulation should also be monitored, as these byproducts can also impact system safety. Accumulated sludges in the expansion tank have been known to interfere with proper functioning of the low-level switch, and sludges passing through the heater can further convert to coke, insulating heater tubes and creating hot spots, as previously discussed.

Provisions for a side stream filtration loop are advised to keep solids accumulation at a minimum.

Conclusion

Figure 3. Provisions for fire suppression should be part of the design phase, but all systems can benefit from fire safety analysis.

Spring 2022 36

Relatively few fires have originated in thermal fluid systems since their adoption many decades ago. The majority of these have been caused by ignition of fluid-soaked insulation, loss of flow, cracked heater tubes, or leakage – all the result of improper design or operation and maintenance of the system.

In general, all systems should be designed and/or reviewed by a qualified engineer who is familiar with the equipment.

By adhering to established design and installation guidelines, and by following all OEM recommendations and preventive maintenance schedules, the risk of a thermal fluid fire can be significantly reduced. All aspects of system design and fire prevention cannot be fully addressed within the context of this article. Designers and operators should always consult with knowledgeable experts and OEMs for the best recommendations.

Mackenzie Michalski and Allen Dickey, Owens Corning, USA, present three goals for storage vessel insulation design.

B

ullet tanks and storage spheres can be used to house a wide range of substances including anhydrous ammonia, LNG, LPG, NGL, gasoline, naphtha, butadiene, ethylene, oxygen, nitrogen, argon, biogas, sewage gas and wastewater, many of which are kept at below-ambient temperatures.

Spherical storage vessels are used throughout the petrochemical industry. There are several benefits to using spherical construction for storage vessels.

37 Spring 2022

Stress concentration in a sphere is reduced when maintaining pressurised materials, and the stress will be uniform across the surface. Additionally, there is less exterior surface per volume than for cylindrical geometry. Bullet tanks are also an integral element in the processing industry, serving as storage for materials before they are introduced into the process.

There are risks that challenge the long-term, efficient and cost-effective functioning of storage spheres and bullet tanks. These include moisture penetration, which will degrade thermal performance, lead to potential corrosion on the vessel or support structure, and risk of fire. Correctly designing and installing insulating systems that use impermeable insulation, such as close-celled cellular glass insulation, can mitigate these risks.

Goal one: protecting thermal performance Warm air can carry more moisture than cold air, so when warm, moist air meets colder air and cools, the warm air

Figure 1. Storage spheres and bullet tanks can contain liquids at a range of temperatures and face risk from vapour drive, corrosion and fire.

Figure 2. Temperature cycling can allow moisture to move further into absorptive, below-ambient insulation systems, creating a damaging freeze/thaw cycle that lowers system thermal performance.

Spring 2022 38

sheds moisture through condensation until a new equilibrium or ‘dew point’ is reached. Similarly, when warm, moist air interacts with a below-ambient insulated system, a vapour pressure drive is created, as the cooling air near the insulated surface seeks to equalise pressure by driving moisture toward colder temperatures inside the insulation. The end result is surface condensation. In the case of insulated storage vessels, this condensation will form on the outer edge of insulated systems and, if the insulation is absorptive, will result in moisture buildup in the insulation.

Moisture in insulation reduces thermal performance and increases thermal conductivity. Keeping moisture out of the insulation maintains the thermal efficiency of the system because water conducts heat at a rate that is approximately 20 times higher than the average thermal insulation. In other words, allowing moisture to enter and remain in the insulation increases heat transfer. A 1% increase in moisture within insulation can increase conductivity by 23%.1 Moisture in insulation can physically damage insulation. During temperature cycling periods – such as when tanks go from ambient to below ambient and return to ambient – freeze/thaw cycling will occur.

Freezing moisture in the insulation damages the insulation and further degrades the thermal performance. Designing a vapour-proof system using an impermeable material, such as cellular glass insulation, and using insulation thicknesses designed to maintain a surface temperature that will be above the dew point, can help mitigate the risk of thermal performance damage from vapour pressure.

Care also needs to be taken during the design to allow for slight changes in the dimensions of the vessel.

Insulation is usually applied to a sphere or tank at ambient temperature. As steel contracts and the temperature is reduced, the dimensions of the vessel will change slightly when filled and put into operation. The insulation system needs to be designed to account for this dimensional change and any potential temperature cycling during operation as the vessel is emptied and refilled. The coefficient of thermal expansion of cellular glass insulation is close to that of steel, and when fully adhered to a sphere or bullet tank using a flexible adhesive/sealant, the insulation system remains tightly bonded to the surface of the vessel during cycling and normal operation. As a result, the flexible adhesive/sealant combined with the impermeable cellular glass keeps the insulation system sealed against moisture and vapour penetration.

Using cellular glass insulation reduces the risk of product loss and decreased system efficiency by controlling heat transfer and preventing moisture intrusion. Additionally, using cellular glass means that the insulation will not absorb flammable liquids or hydrocarbons in the event of a leak. Some open-celled insulations can, even if they are hydrophobic materials, and this increases the risk of a fire occurring.

Goal two: mitigating risk of corrosion A second risk to consider when designing insulation is corrosion, which globally causes approximately

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Figure 3. Cellular glass insulation can provide passive fire protection for structural elements and storage spheres even in rapid-rise temperature fires.

US$2.5 trillion in damage every year.2 Carbon steel vessels, piping and supports are vulnerable to corrosion, which can lead to leaks or spills. However, for corrosion to occur, moisture must be present. Using water and vapour-proof insulation can help mitigate the risk posed by atmospheric water in humid conditions, or salt spray in facilities close to the shore or offshore completely.

If the insulation system is penetrated or absorbent insulation is used, moisture can be retained and react with underlying steel. If moisture reaches the underlying metal of a tank or strut, it can promote the development of corrosion under insulation (CUI). Since this damage is hidden, it can remain undetected until a leak occurs. These leaks can be particularly problematic when the materials stored are at pressure, are flammable, or both. If corrosion is not found, it could cause damage to the loadbearing capacity of structural elements.

Correctly designed and installed insulating systems, using waterproof insulation, can help prevent moisture from entering the insulation system. Selecting closed-cell, impermeable, non-absorbent and non-wicking insulation provides a layer of protection, preventing moisture from penetrating to tanks or support structures.

Goal three: reducing the risk of fire damage Fire is an ever-present risk at facilities that store flammable hydrocarbon and petrochemical products.

Steps can be taken to help mitigate those risks and improve facility and employee safety, should a spill or leak occur. In addition to limiting heat transfer for storage spheres and bullet tanks, insulation can be used to provide passive fire protection to the vessel and support structures.

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Applying non-combustible, closed-cell cellular glass insulation that will not burn, contribute to fire spread or generate smoke helps to protect both equipment and facility personnel by reducing the rate of heat transfer during a fire.

Hydrocarbon fires can reach temperatures of 1093.3°C (2000°F) very quickly, which is a danger to the integrity of structural steel supports used to hold storage tanks. Structural steel can lose up to 50% of its load bearing capacity when the temperature reaches 537.7°C (1000°F). Weakened supports pose a risk to personnel onsite and the stability of elevated containers.

Cellular glass insulation can be used to extend the time it takes for the steel substrate to reach the structural failure point in the event of a fire. This means that responders have more time to address the fire before the steel support structure holding the tanks in place reaches the point of failure. Third-party testing has demonstrated that a double-layer cellular glass insulation system applied to structural steel will prevent the insulated metal from reaching 537.7°C (1000°F) for up to 180 minutes, based on the UL 1709 Standard for rapid rise fire tests of protection materials for structural steel test method. 3 Along with slowing the rate of heat transfer into the structural steel, cellular glass insulation does not burn, generate toxic smoke, or promote flame spread.

Conclusion The main risk areas for damage that spheres, bullet tanks and the support structures face at an industrial facility include protecting thermal performance, mitigating corrosion and improving fire safety. All of these areas can be addressed using a properly designed and installed insulating system.

Using insulation with consistent thermal performance, which is impervious to moisture and prevents heat gain, helps ensure efficient thermal performance. An insulation system using closed-cell cellular glass insulation that is impermeable, non-absorbent and non-wicking helps to protect against the development of corrosion, and reduces the possibility of flammable liquids being absorbed.

Similarly, employing insulation that is non-combustible will not spread flame or generate toxic smoke and can protect structural elements from heat damage. This helps address fire safety and structural integrity at a facility. Although the list of requirements sounds lengthy, closed-cell FOAMGLAS® cellular glass insulation can address the primary areas of risk faced by storage spheres, bullet tanks, and the related support structures.

References 1.

2.

3.

GUSYACHKIN, A.M., et al., ‘Effects of moisture content on thermal conductivity of thermal insulation materials’, IOP Conference Series Materials Science and Engineering, (2019).

‘Measures of Prevention, Application and Economics of Corrosion Technologies Study’, NACE International, (2016).

‘Standard for rapid rise fire tests of protection materials for structural steel (UL 1709)’, Underwriter Laboratories, (2017).

Tony Collins, EonCoat LLC, USA, discusses how a considered choice of tank coating could help to improve workers’ health, as well as limit negative environmental impacts.

W

orking downstream has always been inherently dangerous, as the industry deals with flammable products. The sector has led society’s efforts to make the workplace safer, with safety equipment, training and procedures. It has saved a lot of lives, and improved the quality of many others.

Half a decade ago, a man walking an I-Beam at 300 ft without a safety belt or a safety line was a common sight, as was pulling asbestos blankets off a tank or pipeline with no PPE other than a hard hat and safety glasses.

Much has changed since then. It was not the case that people did not care about safety 50 years ago, but the information we have today was not available at that time.

Nowadays, everyone is tied off when working higher than 4 ft; no one is allowed in a confined space without a rescue plan; and asbestos is now removed by trained professionals who encapsulate it and safely dispose of it in sealed containers before taking it to landfill.

We are all grateful to those who pioneered safer ways to work, and the pursuit of safer ways of working is ongoing.

41 Spring 2022

A health and safety hazard that still needs to be addressed Despite the huge strides that companies in the downstream sector have made in protecting the workforce and the environment, there is a glaring aspect that has not been addressed.

In often-futile efforts to protect steel assets, chemicals that are toxic, flammable and bad for the environment are regularly used: paint and coatings. The unpleasant smell associated with paint is toxic chemicals. They are organic and intended to be volatile, so they evaporate into the environment to enable paint to cure.

Construction and maintenance painters have one of the highest injury rates among any profession. These professionals face multiple health and safety risks, but the most prevalent is exposure to toxic fumes.

Exposure to toxic fumes from high levels of volatile organic compounds (VOCs) can lead to neurological problems, known as ‘painter’s dementia’. Cancer and other health issues are also common. There is a direct correlation between VOC exposure and cognitive ability. A drop in IQ of 10 points or more is common.

Painters are regularly required to use coatings that are both toxic and flammable. Often, they enter confined spaces with these chemicals. They are provided with PPE to wear, but given the choice, eliminating the risk of exposure in the first place would always be the preferred option.

A better way In 2013, NASA wanted to find a coating for its launch pads that was safer for people and less toxic to the environment. As such, the agency conducted a study called ‘Validation of Environmentally Preferable Coatings for Launch Facilities’.

The specific dangers that NASA wanted to minimise were those fundamentally inherent in solvent-borne coatings, and present to a lesser degree in today’s waterborne coatings, including:

VOCs

VOCs damage cognitive ability. They cause cancer, central nervous system damage, headaches, nausea and dizziness, which may be why more falls are recorded by painters than by any other professionals. Additionally, they affect global warming by absorbing ground radiation and by creating greenhouse gas.

Hazardous air pollutants (HAPs)

HAPs are pollutants that cause cancer or other serious health effects, such as birth defects. Additionally, they have adverse environmental and ecological effects.

Isocyanates

Isocyanates, classified as potential carcinogens, are used in polyurethane paints. They irritate the eyes, nose, throat and skin, and can cause breathing difficulties.

Heavy metals

Zinc is toxic at high exposure levels. It can cause metal fume fever. The US Environmental Protection Agency (EPA) lists zinc as a priority pollutant. Waste inorganic zinc (IOZ) paint (and anything that it comes into contact with) is considered hazardous waste. Zinc impacts the environment by entering the water supply at levels which are toxic to fish and potentially to humans.

Low VOC coating performance

Figure 1. 10 environmentally-friendly coatings after

18 months on the beach, alongside the standard NASA uses to compare all test subjects. The standard, which scores 9.2, is in green. The coating in red is EonCoat.

Figure 2. EonCoat four years later, having maintained a score of 10.

Spring 2022 42

Many reading this will believe that while low VOC paints may be good for health, safety and the environment, they will not protect assets. NASA’s test data does not support this conclusion.

NASA identified and tested at least 10 paints and coatings without isocyanates and with low toxins, HAPs and VOCs, and even a few without zinc. Testing was completed using NASA’s Beachside test (Figure 1).

NASA has been conducting coating tests at Kennedy Space Center for many years. All manufacturers test there because it is the most corrosive location in the US, and the Beachside test is generally accepted as one of the world’s toughest real-world tests. No coating passes this punishing 18-month test next to the high tide mark on the beach. It is usually just a question of how well a coating performs on a score of 1 – 10.

In all the years of testing at NASA, the highest score ever recorded was 9.2. However, in 2014, one coating did not rust at all, earning the first ever score of 10. NASA continued to expose those same panels for more than four years, but they continued to score 10 (Figure 2).

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protection for the lifetime of the asset. It is not only safe for the environment, but perhaps most importantly, it is also safe for workers. An unexpected benefit is that it is also less expensive to apply and takes about half the time.

Implications for the downstream sector

Figure 3. Worker applying EonCoat to a tank roof.

Surprisingly, the coating that performed so well on the corrosion test had zero HAPs, zero toxins, zero VOCs, no isocyanates, and no heavy metals (including zinc). In addition, the coating is not flammable and does not create greenhouse gas.

As such, the most effective corrosion coating tested is also the safest for the environment and workers. The coating also offers monetary benefits as it reduces the cost of lost time and productivity, medical treatment, early retirement, falls and errors.

The solution The breakthrough technology, Chemically Bonded Phosphate Ceramics, can be applied directly to surface rust. It only requires one coat and will provide corrosion

This technology has been used for 10 years, with at least eight years in downstream applications. There are versions of the technology tailored to applications that are specific to the downstream sector.

The atmospheric version, such as the one NASA tested, is used for the exterior of tanks in refineries and petrochemical plants in many locations. That same coating is used on structural steel, including offshore platforms.

There is also a corrosion under insulation (CUI) version of the coating, which can handle up to 500˚C and is in use on both insulated tanks and pipelines in many downstream facilities.

The most recent development of Chemically Bonded Phosphate technology is a weldable version. It is possible to weld on one side of a plate without damaging the coating next to the weld or the coating on the other side of the plate. The first use of this coating was on the soil-facing side of oil and chemical storage tanks. Welded tank bottoms will no longer rust out from soil-side corrosion – now they can be protected, with or without cathodic protection.

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Carolina Stopkoski, FLEXIM AMERICAS Corp., and Jörg Sacher, FLEXIM GmbH, discuss the benefits of using non-invasive sound speed measurements to improve tank dewatering operations.

A

long the entire value chain of the oil and gas industry, water is an undesirable companion. Not only does it degrade the quality of hydrocarbon products, but it also presents enormous risks of damaging assets by corrosion and severely disturbing operations. Therefore, removing water from oil is of primary importance, from production through to transport, and storage through to refining.

The separation process in a typical tank farm is rather unsophisticated. Its principal agent is time, and a water-oil emulsion will separate in the tank. Due to its higher density, water sinks to the bottom and a dirty separation layer – the so-called rag layer – forms between the aqueous and the oily phase. This layer of mixed fluids causes several undesired operational effects. As an emulsion of water and hydrocarbons, it offers ideal conditions for microbial growth, which affects

both product quality and the integrity of the tank due to the formation of sludge and corrosion. This means that all tanks need to be dewatered regularly.

Automation relies on measurement The basic and traditional procedure for tank dewatering is executed manually – one or more valves are opened to drain out the water and are then closed again. Today, due to its evident inefficiency in terms of human labour and imprecise distinction of the media that is required to be separated, this kind of manual operation appears almost anachronistic. It is therefore no wonder that tank farm operators have sought out various means to automate the tank dewatering procedure.

The key component of any automated tank dewatering system is a measuring device to detect the water-oil interface.

Conventional solutions use conductivity, capacitance, microwave

45 Spring 2022

Figure 1. Measuring principle of the ultrasonic flowmeter, FLUXUS.

or optical measurements for this purpose. Such devices not only have a high purchase price, but the installation work is also costly, as insertions into a pipe or into the tank itself are necessary.

Welding presents the risk of affecting tank integrity.

Furthermore, these wetted measuring solutions have severe shortcomings, as they come in direct contact with the fluid and are affected by dirt build-up. As a result, they require frequent maintenance, which impacts the availability of the respective storage tank.

Clamp-on ultrasonic measurement

Figure 2. Sound speed of water and some crude and refined hydrocarbons.

Figure 3. Sound speed measurement allows for precise real-time monitoring of the dewatering process, including the rag layer.

Non-invasive sound speed measurement with clamp-on ultrasonic technology provides a simple solution for this task. When FLEXIM was founded by four university graduates in 1990 in Berlin, Germany, its initial key application was – and still is – non-invasive flow measurement. As ultrasonic signals travel faster in the direction of a flowing medium than against it, the difference between their transit times can be measured. Computation of the geometry of the measuring point and physical properties of the fluid allows for precise calculation of volume or mass flow.

Since then, FLEXIM’s ultrasonic flowmeters, FLUXUS, have been proven as an excellent solution for countless applications, be it monitoring the flow of medical oxygen in hospitals, measuring production rates at oil and gas wells onshore and offshore, or quantifying steam flow in industrial production or heating applications.

The technology can also be used for analytical purposes.

Exactly the same arrangement of clamp-on ultrasonic transducers mounted onto the outside of a pipe allows the meter to determine the acoustic velocity in the medium. This depends on the density – and therefore the temperature – of the medium, and is a substance-specific characteristic.

Consequently, the speed of sound can be used to distinguish between mediums, and even to identify them. In the oil and gas industry, this methodology is used to distinguish and identify different hydrocarbons that flow successively through a multi-product pipeline. Another common application of sound velocity measurement is to protect chemical tanks from dangerous misfilling. As the speed of sound of a substance depends strongly on its molecular structure, acids and alkalis, for example, can be very clearly distinguished from each other.

Water-oil interface detection

Figure 4. Sound speed measuring point at an automated tank dewatering system with clamp-on ultrasonic transducers.

Spring 2022 46

The same applies to the distinction between water and hydrocarbons. The two have clearly different sound velocities, which respond in opposite ways to temperature changes: the speed of sound of water increases with temperature, while that of hydrocarbons decreases. It is therefore very easy to automate tank drainage based on sound velocity measurement. As the clamp-on ultrasonic transducers are simply mounted on the outside of the drainage pipe, setting up the measuring point does not affect the integrity of the tank, nor does it require the pipe to be opened. In addition to this simple and correspondingly cost-effective installation, the non-intrusive acoustic measurement technology has the advantage that the passage of the intermediate layer – the oil-water emulsion – can also be precisely monitored.

Another additional benefit of interface detection with FLUXUS is that the ultrasonic system can also be used

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simultaneously for flow measurement. This ensures that the valves are properly closed again after the drainage process has been completed. Additionally, the flow data can be used for tank balancing purposes.

nn No risk of unwanted and dangerous emissions due to accidental hydrocarbon release.

Meeting industry needs

nn It can be easily retrofitted to an existing tank layout; no need for piping modifications. nn No process interruption during installation and commissioning. nn Reduces product losses. nn Cost-savings in water treatment through reduced amount of released hydrocarbons. nn No direct contact with the medium, resulting in no wear and tear, no drift through dirt, and no wax build-up. nn Zero maintenance. nn Simultaneous flow measurement allows for process monitoring and tank balancing.

In order to meet the needs of the hydrocarbon industry, FLEXIM has developed an ultrasonic measuring system: the FLUXUS H series. It combines highly precise non-invasive flow measurement with HPI-specific analytical capabilities.

Approximately 15 years ago, the first sound speed test measurements were made with FLUXUS flowmeters in tank dewatering operations. Thanks to the promising results, first implementations of the solution soon followed. Since then, the company’s measuring experts have consistently developed the application further, in cooperation with their customers. Today, it is a well-established solution that has become a standard for some of the largest refinery operators worldwide, particularly in the Middle East.

Key benefits The benefits of tank dewatering automation with clamp-on ultrasonic flow meters can be summarised as follows:

Increased occupational and operational safety

nn Acoustic interface detection eliminates human error. nn No risk of leakage.

Increased efficiency, full availability and overall cost reduction

Conclusion The technology outlined in this article offers a simple solution for the automation of tank dewatering. Measuring from the outside of the pipe means measuring from the safe side. As the ultrasonic transducers do not come into direct contact with the medium flowing inside, they do not suffer wear and tear. Automated tank dewatering increases safety and improves operations, which has an immediately-positive impact on the operator’s bottom line.

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Correct Inventory and Liquid Loss Control •

From a tank gauge (It’s not Radar, Servo, Magnetostrictive, etc.) Bottom referenced (Innage)

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Provides the most accurate product volume (Inventory) (Transfer Ticketing)

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Provides Overfill Protection beyond API 2350 Standard, 5th Edition

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Provides Rupture Protection for Over Pressure & Vacuum on CRT’s

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Provides Leak Detection (Tank tightness, Historical) and Unauthorized Movement

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Provides Vapor Monitoring (Optional ambient vapor monitoring)

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Provides Product Quality by continuous monitoring of product stratification over the height of the liquid (Water, Density, & Temperature) (Blending, De-watering, Sampling Top-Middle-Bottom in real-time, etc.)

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And provides this data to any system via a closed server with OPC/UA, PI, SAP, MQTT, Back Office, etc. connectivity (Real-time or Scheduled)

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TG Soft Server supports multiple applications that are tailored to providing a payback and profit from your gauging technology. What data do you need?

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(281) 980-3999