Tanks and Terminals Autumn 2021 by PalladianPublications

AUTUMN 2021 21

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CONTENTS Autumn 2021 Volume 07 Number 03

03 05 06

Comment World news An eye on Asia

ISSN 1468-9340

Floating roof inspections: an inside job Robert L. Ferry, Trinity Consultants, USA, looks at the recent revisions to the US Environmental Protection Agency’s NSPS Kb tank inspection requirements.

Ng Weng Hoong, Contributing Editor, provides an overview of the oil and gas sector in Asia, commenting on China’s dominance over the region’s oil storage and stockpile decisions.

Smooth operator Joshua James, Liquip, Australia, provides maintenance tips and advice to ensure smooth operation during loading operations.

Singapore success Venkatesh Deshpande, Endress+Hauser, and Darrick Pang, Metcore International, outline how traceable Coriolis mass flow meter verification will enhance the credibility and reputation of Singapore as a major international port.

Steps to overfill prevention Craig M. Carroll, Magnetrol Ametek, looks at the steps that have been taken to help prevent overfill spills, and how level instrumentation can help to reduce the risk of a catastrophic event.

39 12

Marianne Williams, Emerson, USA, explains the significant benefits that can be achieved through the remote partial proof-testing of level measurement instruments in an overfill prevention system.

The road to 2050 Danny Constantinis, EM&I Group, Malta, explores innovative asset integrity technologies for tanks and terminals in light of the energy transition and an evolving storage market.

A critical link Josiah Lau, Novlum Inc., Canada, outlines how 3D laser scanning works, and explains why the right software can significantly improve workflow efficiency.

Increasing availability

Essential design factors Brandon Stambaugh, Owens Corning, USA, presents three essential design factors to consider when insulating storage tank systems.

The sky’s the limit Adam Wishall, Varec Inc., USA, explains how recent updates have helped to improve automation and control functionality for a major fuel farm at the Hartsfield-Jackson Atlanta International Airport.

Upping the standard François Negroni, ALMA Group, outlines the benefits of using a standardised vapour recovery unit to handle emissions.

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CALLUM O’REILLY SENIOR EDITOR

s the weather starts to turn a little colder in the northern hemisphere, much remains unknown about the months to come. As I write this, the UK government has just outlined ‘plan A’ and ‘plan B’ options for dealing with COVID-19 over the autumn and winter period, and similar flexible policies are likely to be seen the world over as the number of coronavirus cases are closely monitored. However, it is hoped that the worst is now behind us, and now seems like a good time to take stock of the impact that the pandemic has had on the oil and gas sector. In part one of StocExpo’s recently published ‘Industry Trends Report’, the Chairman of Channoil Consulting, Charles Daly, compares the impact of the pandemic on the world’s economies to the effects of pruning a plant at the end of summer.1 He writes: “It might sound brutal, but the strategic damage caused by pruning can refresh a plant and stimulate stronger growth in the future.” Daly points out that while individual companies (and even entire industries) that were weak before the pandemic may not have survived, there are a number of positive changes “seeded before the pandemic struck” that have now been accelerated. Looking at the refining industry specifically, Daly suggests that it was inevitable that smaller refineries would eventually close, given that new refineries in the Middle East, China and India are being built with larger capacities and more complexity. The impacts of the pandemic have merely accelerated this trend, as refineries were hit with reduced demand as well as the change to 0.5% sulfur fuel oil for the bunker market. As for the storage sector, “the pandemic showed that storage rates can go down as well as up”. Daly explains that in a world driven by a push for sustainable fuels, biofuels are only likely to be an interim fuel and not the long-term answer for storage companies. “If wind or solar power is to be the main driver of power in the future, then a competitively priced storage system for this intermittent power must be found. Here the storage industry should look at how it can influence as well as compete for storing power. This can be in the form of liquid hydrogen and air, ammonia or methanol,” writes Daly, who also foresees an increased demand for naphtha, ethane and propane due to sustained growth in the plastics sector. The report also looks at automation transformation following the pandemic, as well as the role that digitalisation will play in the future of the storage sector. For more information, visit: www.stocexpo.com. This issue of Tanks & Terminals magazine is packed full of detailed technical articles and case studies examining how innovative technology is continuing to enhance productivity and efficiency, as well as improve health and safety in the storage sector. This month’s regional report looks at the current state of play in Asia and Australasia, as China dominates the region’s oil storage and stockpile decisions. We hope you enjoy. 1.

‘Industry Trends Report’, StocExpo, (2021).

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

DIARY DATES

Kinder Morgan and Neste partner on renewable fuels project

04 - 06 October 2021

Kinder Morgan Inc. is partnering with Neste to create a premier domestic raw material storage and logistics hub in the US, supporting increased production of renewable diesel, sustainable aviation fuel and renewable feedstock for polymers and chemicals.

First vessel discharged in Rainbow Phase 2 expansion project

ILTA 2021 Houston, Texas, USA www.ilta.org

11 - 14 October 2021 API Storage Tank Conference And Expo Nashville, Tennessee, USA www.api.org/storagetank

05 - 06 October 2021 AFPM Summit Online www.afpm.org/events

LBC Tank Terminals has announced the successful discharge of the first vessel in one of the new tanks of its Rainbow phase 2 expansion project.

15 - 18 November 2021

BP delivers first carbon offset LNG cargo in Asia-Pacific

01 - 02 December 2021

ADIPEC Abu Dhabi, UAE www.adipec.com

14th Annual National Aboveground Storage Tank Conference & Trade Show The Woodlands, Texas, USA www.nistm.org

BP Singapore Pte. Ltd has delivered its first carbon offset LNG cargo to CPC Corp. The cargo was delivered to the Yung An terminal in Taiwan in September 2021.

13 - 16 December 2021 Turbomachinery & Pump Symposia Houston, Texas, USA tps.tamu.edu

Harvestone Group acquires Gateway Terminals

08 - 10 March 2022

Harvestone Group has announced the acquisition of Gateway Terminals LLC, a bulk liquid terminal complex located on the banks of the Mississippi river in Sauget, Illinois, US.

StocExpo Rotterdam, the Netherlands www.stocexpo.com

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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Autumn 2021

Ng Weng Hoong, Contributing Editor, provides an overview of the oil and gas sector in Asia, commenting on China’s dominance over the region’s oil storage and stockpile decisions.

mid worsening tensions between China and the West, the prospects for conflict in the Asia Pacific region are rising, raising worries about energy security for a region that is increasingly dependent on imports for its oil and gas supplies. Australia has started increasing its oil stockpiles while India has just approved investment to more than double its strategic petroleum storage capacity. China itself has been investing heavily in expanding and upgrading its oil storage and logistical infrastructure. According to the Baker Institute in Texas, US, China has built up enough capacity to officially store

Autumn 2021

791 million bbl of crude oil and at least 360 million bbl of products. Unofficially, analysts believe China’s crude oil storage capacity exceeds 1.4 billion bbl. Its 210 refineries have a combined capacity to process up to 22.7 million bpd of crude oil. Platts Analytics, an analysis arm of S&P Global, expects China to add 70 million bbl of commercial tank capacity in 2021 to follow through on last year’s increase of 100 million bbl. The Chinese government is becoming more guarded about information pertaining to its oil stockpiling progamme and domestic energy infrastructure. As policy,

the Chinese government already does not reveal how much crude and products it maintains in its strategic and commercial stockpiles. The country’s growing capacity to stockpile both crude and products is empowering state planners to better manage market volatility. China is also building up oil stockpiles and storage assets abroad. In Asia, state-owned Chinese firms have invested in storage tank operations in Singapore, Sri Lanka, Japan and Myanmar. In Singapore, PetroChina owns a 25% stake in Jurong Universal Terminal, the island state’s largest independent oil storage terminal with 2.33 million litres

of capacity. In March, Singapore’s state-owned Jurong Port became the terminal’s largest shareholder when it acquired the 41% stake previously held by the collapsed Hin Leong trading group. Australian investment bank Macquarie Group owns the remaining 34% through a subsidiary called MAIF Investments Singapore. In Myanmar, PipeChina, a subsidiary of Chinese oil giant CNPC, is the majority owner and operator of a crude oil terminal and a major pipeline system that started up in April 2017. Crude oil is shipped to the storage terminal at Kyaukphyu Port on the Bay of Bengal before it is 7

Autumn 2021

delivered to the Kunming refinery in China’s southwest Yunnan province through a 771 km pipeline that runs mostly inside Myanmar. CNPC has also built oil storage tanks on the island of Maday or Made to support trade and infrastructure development in southwestern Myanmar.

Australia to boost oil stockpile Australia is now showing signs of urgency to boost its strategic oil stockpiles. Years of encouragement from the International Energy Agency (IEA) and threats of supply disruptions in the Middle East failed to do the job, but increasingly hostile relations with China seem to have fired up Australian fears about fuel shortages. With the equivalent of just 33 days of consumption, Australia’s landed oil stockpiles remain among the lowest in the world’s industrialised economies. The IEA publicly rebuked Canberra’s laidback approach through most of the 2010s when successive governments saw little risk in operating a ‘just-in-time’ policy for oil supplies. But sentiments are changing. In April, Australian Prime Minister Scott Morrison announced a massive US$500 billion upgrade of military facilities over the next five years. Data from the Department of Industry, Science, Energy and Resources show that Australia has made progress raising fuel stockpiles since Morrison took office in August 2018. From around 25 days in the 2010s, Australia’s landed oil inventory has risen to 33 days at the end of April 2021. The latest count includes 35 days of stockpile for crude and refinery feedstocks, 32 days for gasoline, 59 days for jet fuel, and 20 days for diesel. Still, they remain woefully short even in the best of peace times, never mind during war. The IEA wants its 30 member states to maintain at least 90 days of emergency fuel stockpiles.

Insufficient storage capacity The Morrison government has stepped up to address Australia’s domestic fuel vulnerabilities over the past year. In May, it unveiled an AU$2.3 billion plan to subsidise the operations of the country’s remaining two oil refineries. Without the funding that will last through 2027, Ampol’s plant in Lytton in Brisbane city and Viva Energy’s refinery in Geelong near Melbourne were headed for closure. Following the lead of other Australian refiners, the two companies said they had planned to convert their small ageing plants into storage terminals. The subsidies will buy time for the two refineries but not reverse their lack of competitiveness against bigger and more efficient rivals in Asia and the Middle East. In February, the Morrison administration became the first foreign government to purchase crude oil directly from the strategic petroleum reserves (SPR) operated by the US government. The US Department of Energy (DOE) said it sold 195 000 bbl of SPR crude oil

Autumn 2021

to its Australian counterpart. The deal is part of Canberra’s plan to increase reliance on the US for its energy security. In June 2020, the two governments signed an historic agreement for Australia to stockpile part of its crude reserves in the US. In a joint statement, the governments announced that their SPR Lease Agreement allows for Australia to include crude oil stockpiled in the US as part of its compliance with IEA regulations. In January 2021, Canberra announced an expanded domestic fuel storage programme, including an AU$200 million grant for companies to build new diesel tanks in Australia. “Holding more fuel stocks in Australia will increase our resilience to supply disruptions, thereby protecting consumers and the economy from fuel shortages. An additional 780 megalitres of diesel storage is expected to be required to allow industry to meet the new minimum stockholding obligation,” said the Department of Industry, Science, Energy and Resources. Despite these efforts, analyst Tony McCormack said Australia’s energy security is still a long way from guaranteed. “Increased storage capacity is all for nothing without fuel to fill the tanks. The key vulnerabilities for fuel supply in Australia continue to be the lack of domestic production and the fragility of logistics supply chains,” said the Australian Strategic Policy Institute fellow.

India to more than double crude oil storage capacity India will add 6.5 million t of crude oil storage capacity in a second-phase expansion to lift the nation’s total to 11.83 million t (87 million bbl). In a written statement to Parliament in late July, the Minister of State for Petroleum and Natural Gas Rameswar Teli said the government will build a 4 million t terminal in the northeastern state of Odisha and a 2.5 million t facility in southwestern Karnataka. He did not give a schedule for the start of construction and expected completion. The government has disbursed 2.1 billion rupees to Indian Strategic Petroleum Reserves Ltd (ISPRL) for the purchase of land for the new terminals at Jaipur district in Odisha and Padur in Karnataka. ISPRL is the state agency that builds, owns and operates the country’s strategic petroleum storage terminals. To date, it has established three storage facilities with a total capacity of 5.33 million t at Vishakhapatnam (1.33 million t) in the eastern state of Andhra Pradesh, and in Mangaluru (1.5 million t) and Padur (2.5 million t), both in Karnataka state. As the world’s third largest crude oil importer after China and the US, India is badly lagging behind in its oil stockpiling programme. The ISPRL’s current storage capacity meets just nine days of the country’s domestic oil consumption. With its limited capacity, the company could not take full advantage to build up inventory last year when the US WTI crude price plunged below zero.

For years, the business community has lobbied the Indian government to boost the country’s oil stockpiles to reduce the risk of supply disruptions.

Sri Lanka to expand Hambantota’s oil storage and supply role Sri Lanka is hoping to expand its oil supply role in southern Asia as it continues to beef up the logistical infrastructure in and around the island state’s second largest port of Hambantota. Backed by Hambantota International Port Group (HIPG), Sri Lanka’s energy ministry and state-owned Ceylon Petroleum Corp. (CPC) have unveiled a vision to develop the southeastern port into a ‘strategic energy centre’ to serve shipping traffic through the Indian Ocean. HIPG is 85% owned by a Chinese consortium comprising Hong Kong-listed China Merchants Port Holdings and Fujian TMSR, a state subsidiary of the government of China’s Fujian province. Sri Lanka Ports Authority is the junior partner with a 15% stake. In June, HIPG and CPC announced their plan to expand Hambantota port’s oil storage capacity that will boost the country’s fuel stockpiles to meet three months of domestic consumption. CPC said the country’s antiquated terminals currently can only store the equivalent of one month of Sri Lanka’s estimated oil consumption of 104 000 bpd. The partners did not reveal the project’s estimated cost and a deadline for its completion and start-up. CPC has allocated a 50-acre plot of land located 15 km from Hambantota for the new storage terminal. HIPG will build a network of pipelines to connect the terminal to the port and facilitate fuel distribution to the rest of the country. CPC Chairman Sumith Wijesinghe said the new storage capacity will enable the company to better manage “the impact of global fuel price fluctuations” on the domestic market. As Sri Lanka depends on imports to meet 70% of its fuel demand, he expects the expanded storage capacity to strengthen the company’s bargaining positioning with suppliers. Johnson Liu, HIPG’s CEO, said CPCs support is crucial to Sri Lanka’s vision to turn Hambantota into a major international port serving the maritime trade route between Asia, the Middle East, and Europe. Liu said Hambantota’s expansion “will support the smooth and efficient supply of fuel to customers” and “strengthen the position of this Sri Lankan port on the global maritime map.” HIPG has signed a strategic partnership with Sinopec Fuel Oil Lanka Ltd (SFOL) to supply bunkering fuels and support services for vessels calling on Hambantota. Sri Lanka’s neighbour, India, is increasingly concerned about China’s growing maritime ambitions in the Indian Ocean. China has made clear that the Indian Ocean is a key part of its ‘Belt and Road’ Initiative to connect the economies of Asia with those of other regions. Autumn 2021 10

India suffered a setback early this year when the Sri Lankan government of President Gotabaya Rajapaksa announced the cancellation of their bilateral agreement to develop oil storage and port facilities on the island state. India was looking to the projects to counter China’s growing influence in Sri Lanka. But India has only itself to blame for the loss as state Indian Oil Corp. had made little progress with its 18-year promise to develop the northeastern Sri Lankan port of Trincomalee into an oil storage and supply hub. In 2003, IOC had presented Colombo with a vision for the port’s revival when it secured a landmark 30-year deal to lease 99 oil tanks in Trincomalee. Frustrated by the lack of progress, the Sri Lankan government offered to cancel the agreement in 2012. When New Delhi stood firm, Colombo turned to Beijing for help to develop Hambantota into a competing project. Eight years on, Hambantota has grown rapidly to become a major hub of industrial activity and fuel supply for the country, while Trincomalee remains mired in its colonial past as a port built by the British nearly a century ago. India fears Trincomalee too might end up in the hands of the Chinese.

Malaysia’s Dialog starts up oil terminal Malaysia’s southern Johor state is continuing to expand its oil storage role in Asia with the start-up of another 430 000 m3 of capacity off the port of Pengerang. Dialog Group Berhad launched the phase 3A of its terminal to store clean petroleum products. The RM1.6 billion project, underpinned by a long-term contract with BP Singapore signed in December 2018, received its first shipment of products in March. The company’s storage facilities serve the region’s oil supply chain connecting refineries and petrochemical plants, including those located within Johor’s US$27 billion Pengerang Integrated Petroleum Complex. Dialog’s Executive Chairman, Ngau Boon Keat, said the company has grown since signing a memorandum of understanding with the Johor state government in 2009 to develop the complex. To date, the company has invested a total of RM13.5 billion, contributing to Johor state’s emergence as a viable oil storage and supply centre to rival neighbouring Singapore. Johor’s Chief Minister, Hasni bin Mohammad, said the terminal’s latest expansion, including shared infrastructure and deepwater marine facilities, will help attract more refining and petrochemical investments into the state. Listed on Malaysia’s main stock exchange, Dialog started in 1984 as an engineering services company before expanding to become an oil terminals owner and operator.

Indonesia’s eastern provinces to gain from oil storage projects Indonesia is hoping to jump-start the economy of two of its poorest provinces with the construction of oil

Autumn 2021 12

Danny Constantinis, EM&I Group, Malta, explores innovative asset integrity technologies for tanks and terminals in light of the energy transition and an evolving storage market.

he energy industry is entering an interesting period, in which most governments and major companies are committed to the transition from fossil fuels to renewables, such as wind, wave, tidal, solar, and hydro, etc. However, all these types of energy suffer from ‘intermittency’, meaning that back-up facilities are still needed in order to provide 24/7 power. Battery power and storage is still not developed sufficiently to provide peak power for more than a few hours at the most. Green hydrogen has possibilities and can be created in conjunction with wind farms, as there is plenty of water available. However, it still needs to be stored and/or transported to where it will be used to generate power. The question remains, will tanks and terminals be needed in a world where renewable ‘clean’ energy is a non-hydrocarbon future?

Energy transition The International Energy Agency (IEA) and others are faced with a difficult dilemma at the moment. Governments receive around US$1 trillion of tax every year from fossil fuels, whereas renewables usually require subsidies. However, there is increasing pressure to stop all new exploration. Despite this, Rystad Energy has estimated that thousands of new oil wells and hundreds of new oilfields will still be required to meet the anticipated demand for crude oil and petrochemicals.1 The Organization of the Petroleum Exporting Countries (OPEC) has also accused the IEA of being unreaslistic if they want to stop all new drilling and exploration for oil. So, it will not be easy to come to a consensus on this matter before the ‘net zero’ target of 2050 or earlier, and it will require some very imaginative thinking, international

1 13 Autumn 2021

agreements, legislation, and policing to achieve. The goal is commendable as climate has no borders, but achieving net zero in time to keep global warming within acceptable levels is certainly a challenge.

How will all this affect tanks and terminals? Tanks and terminals are the key to energy storage. It is likely that refineries will concentrate more on petrochemicals as demand increases. The huge and increasing demand for petrochemicals will still require crude oil feedstock – even if it is not required for fuel or heating. There are not many alternatives available for petrochemicals, meaning that tanks and terminals will still be required for the foreseeable future. The ‘tanks’ may be offshore as well as onshore in the future, particularly to help with the intermittency problem of renewables. Floating storage and regasification units (FSRUs) and floating storage regasification and power vessels (FSRPs) can help to provide power quickly – particularly for isolated and island communities or for developing nations with little or no infrastructure – with seasonal or emergency demands. LNG is plentiful and cheap, and a relatively ‘clean’ fuel compared with other fossil fuels, which can provide 24/7 power quickly, cheaply, and reliably. Inevitably, the solution will probably be a combination of many of these options, as unforeseen issues such as the drought in Brazil this year, which has seriously affected hydropower plants,

Figure 1. Laser scan of cargo oil tank.

may require back-up power to be provided. This is symptomatic of the problem with renewables – intermittency. Ghana had a similar problem with drought a few years ago which affected its hydropower plants and the country has investigated FSRU back-up plans, even though it has oil and gas resources.

Remote inspection and monitoring Remote inspection and monitoring will be increasingly desirable for safety and efficiency, so while remote inspection technology can be applied to existing assets, where possible tanks and terminals could benefit from being designed with remote/robotic integrity in mind. Resident robots and access ports for remote inspection equipment such as cameras, lasers, and crawlers, etc. will be essential for economic and safe operation.

Ensuring that tanks are ‘fit for purpose’ Ensuring that oil, chemical and gas tanks are ‘fit for purpose’ throughout their operational life will require periodic inspections both for structural strength, corrosion protection and other damage depending on the stored material. These vary considerably, so an understanding of the integrity requirements is important and necessary if a move is to be made toward more risk-based or remote-based inspections, and possibly repair methods, as is the case in other industries. Fortunately, onshore tanks are usually easily accessible from the outside, meaning that conventional methods of non-destructive testing (NDT) can be used. However, inside is where robotic methods such as cameras and synchronous laser systems can be used to avoid manned entry. These have been very successful in the offshore industry, particularly in avoiding deaths in confined spaces or working at height. Developments of these ‘no-man’ robotic technologies are already being used on oil and LNG tank structures, pressure vessels, FPSO turrets, and other structures to reduce risk and cost. But what about structures, piping and other components found in terminals?

Innovations ‘fast-tracked’ from other industries Many innovations have been ‘fast-tracked’ from other industries such as the nuclear, aerospace, civil engineering, medical profession, and forestry industries. These are therefore all well proven technologies which have been adapted for the oil and gas industries.

Jetties piping and other components?

Figure 2. NoMan optical camera tank inspection.

Autumn 2021 14

In 2019, a requirement to inspect a jetty structure and slide bearings by alternatives to rope access was solved by using a robotic camera system. The work was completed safely and in under half the time and cost of the conventional method. This approach can be applied to other inaccessible structures and components such as pressure systems and support structures.

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Figure 3. ExPert image at height.

The NoMan technology is class approved and has been used extensively on numerous assets with great success. On a recent project on an FPSO in the North Sea, two technicians were able to inspect four cargo oil tanks in just two days – without manned entry – achieving a 90% reduction in the man-hours normally required for tank preparation and inspection. This resulted in a substantial saving in both time, money, and tank availability, and was carried out to the complete satisfaction of both the client and classification society.

Technology for inspecting electrical components

Figure 4. Digirad image of pipework.

Statistical technology Terminal piping and vessels would also benefit from reducing inspection costs and time – the solution can be directly ‘borrowed’ from experience on pressure system piping where statistical analysis of data can reduce inspection costs significantly with the added benefit of improved insights into current and future pressure system condition. The ANALYSETM technology was developed with a leading university in London for reducing ultrasonic thickness measurements (UTM) on pipework and pressure systems. Historically less than 5% of UTMs detected any anomalies, which means that around 95% of inspection costs are traditionally wasted. The ANALYSE statistical programme optimises the number of readings required and safely saves around 50% of the workload and cost of this vital inspection activity.

Remote camera and laser scanning technologies The NoMan® remote camera and laser scanning technologies are ideal for inspecting the interiors of storage tanks quickly, simply, and safely. They can be inserted through existing or purpose built access ports and can pan, tilt, zoom and scan the interiors to confirm the condition of the component without the risk and cost of man entry or working at height. This has worked well offshore and saved substantial sums, as well as minimising tank out of service time. Autumn 2021 16

The ExPertTM technology for inspecting Ex electrical components is another major innovation, as electrical items are notoriously difficult and time consuming to inspect manually. They normally need to be visually examined closely, which can involve working at height. A number of Ex items also need systems to be isolated and some components to be dismantled for inspection before reassembly. This can lead to challenges in shutting down critical systems for dismantling and reassembly, and runs the risk of introducing errors when reassembling. The ExPert technology uses specialised scanners which can ‘see through’ the electrical items concerned and detect anomalies while systems are online, so the items do not need to be isolated, dismantled or reassembled unless an anomaly is detected. The benefits of reduced time, risk and avoiding system shutdowns are clear. The NoMan camera can carry out close visual inspections of Ex equipment without the need for working at height.

RTR to detect CUI A technology which was originally used to detect drugs in car tyres has been developed to detect corrosion under insulation (CUI). Removing insulation to find CUI is a very costly and time-consuming business. Real time radiography (RTR) and digital radiography only requires a two-man team and can inspect up to 50 m of piping a day without removing the insulation. This is a fast and safe way to inspect insulated pipework that may be present on terminals. A recent client calculated that if it saved removing just 6 m of insulation it would pay for the RTR team for three weeks.

Conclusion Transition is going to stimulate many changes in the way the storage sector works and the technologies used. As skilled manpower becomes scarcer, and safety considerations become more important, robotic and digital technologies will become more dominant. These technologies are already making a big impact on offshore installations where reducing manpower to the minimum is also a requirement, which also saves on helicopter flights and greenhouse gases, etc. This will inevitably be interesting for onshore assets such as tanks and terminals as well.

Reference 1.

https://www.reuters.com/business/energy/unlike-iea-rystadenergy-sees-need-hundreds-new-oilfields-2021-05-28/

Josiah Lau, Novlum Inc., Canada, outlines how 3D laser scanning works, and explains why the right software can significantly improve workflow efficiency.

ight Detection and Ranging (LiDAR), more commonly known as 3D laser scanning, has been around since the 1960s. Today, 3D laser scanners come in many forms and are used in applications ranging from large area 3D aerial surveys to collision detection on autonomous vehicles. Within the last several years, the use of 3D laser scanning to assess structural integrity and capacity of aboveground storage tanks has gained popularity. While 3D laser scanners can capture vivid 3D images of these large, tall, and internally dark structures in a short amount of time, the software required to transform the 3D data into useful information is lacking. This is the main reason that 3D tank inspection has not become the mainstream tank inspection method even though the information gleaned from this

technology is extensive when compared to traditional inspection methods.

Scanning In order to understand the software required to process laser scanning data, also known as point clouds, it is important to first understand how 3D laser scanning works. At a high level, 3D laser scanners send out laser pulses that are reflected back to the scanner when they hit objects. The measured distance is equal to half the round trip flight time multiplied by the speed of light (Figure 1). The accuracy of each measurement depends on the ability of the scanner to resolve the peak intensity of the reflected laser pulse, which is affected by how energy 17 Autumn 2021

propagates, absorbs, and reflects off surfaces. Factors that affect the return intensity include ranging distance, ambient light, surface characteristics, and surface incidence angles. Since light travels in a straight line and cannot penetrate objects, physical obstructions in the scan area create shadow areas behind them (Figure 2). Because of these limitations, numerous scans are required in order to capture the entire structure of a storage tank and to meet the accuracy requirement for tank inspection (Figure 3).

Figure 1. 3D laser scanners send out laser pulses that are reflected back from objects.

Registration

Each scan is an independent 3D representation of the storage tank from the perspective of the scan location. To achieve a complete representation with sufficient coverage of the entire tank, the scans need to be merged together to create a registered 3D model, a process called data registration (Figure 4). Many off-the-shelf software packages can be used to perform data registration, which is a well understood process because it is a common step for all 3D laser scanning work. Point cloud registration typically follows the same process regardless of whether the scan subject is a factory, a building, or a storage tank. The two most Figure 2. Single scan showing shadows on shell common data registration techniques are target-based caused by scaffolding, decreasing point density on registration and cloud-to-cloud, or targetless, registration. floor with increasing scan distance, and decreasing Target-based registration uses artificial targets during point intensity on floor due to increasing incidence scanning such as checker targets. These targets serve as angles. A shadow area is always seen underneath the common points, or tie points, between the scans. The scanner. registration software uses these tie points to co-locate the scans. The speed and accuracy of registration depends on a software’s ability to accurately detect targets within each scan and correlate these targets between the scans. Because automatic algorithms often fail, efficient manual tools to override target selection, placement, and correlation are necessary to improve accuracy and success. While this registration technique is most commonly used, it relies heavily on proper scan planning and preparation and requires longer in-field time for target setup. Furthermore, there is a higher risk of failure if the number of targets used is inadequate, or the targets are not sufficiently visible from all scans. Figure 3. 3D model created by registering multiple Cloud-to-cloud registration uses physical features in scans together. Complete coverage is achieved on the scans as natural targets, such as surfaces, hard edges, shell and floor, including beneath individual scan locations. and corners to select tie points between scans. This technique is software intensive, but if done properly can yield a more accurate registered 3D model than target-based registration. The advantage of this Figure 4. Registration is the process of merging several independent 3D scans (left) into a single technique is registered 3D model (right). Each colour represents points from a different 3D scan. that targets Autumn 2021 18

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are not required, which reduces in-field preparation and risk of registration failure. It can be more robust than target-based registration because an unlimited number of tie points can be used, or tie points can be localised to enhance accuracy in an area of interest. For example, if the upper levels of a tall structure is of interest, but scanning is done from the ground, selecting tie points in the upper levels as opposed to the ground level will ensure a better fit in that area. When using targets, the target placement is limited to locations that an operator

is able to physically access, which is typically close to the ground. While cloud-to-cloud registration has its advantages, the results are highly dependent on the algorithmic implementation in each software package. Sometimes, a hybrid approach can be used where artificial targets are used to automatically align the scans and natural targets are used to refine the registration. Regardless of registration technique, the software of choice should have tools to quantify overall registration accuracy, visually review registration quality using cross-sections, and manually adjust the registration if needed. The interactivity of these tools makes a tremendous difference in workflow efficiency. While fully automated approaches can save time, a trained operator should always review the registered model to ensure accuracy.

Classification

Figure 5. Registered data model (top), classified data model (centre), and isolated floor points (bottom).

Once a registered 3D model has been created, each data point must be assigned to a specific class such as shell, floor, roof, columns, or other clutter. Accurate classification of data points is required for proper analysis. For example, all shell data points must be identified and extracted in order to analyse shell out-of-roundness. However, in order to analyse shell settlement, only floor points nearest the shell are required, but shell points must be excluded. Misclassification of data points can lead to false anomalies in the results. For example, data points of columns or equipment (Figure 5) misclassified as floor can result in false floor bulges, and data points of manways misclassified as shell can result in shell roundness being exceeded. The accuracy of the analysis is highly dependent on the accuracy of point classification. Many software packages have tools to classify data because this is a standard process for all 3D laser scanning work. While software packages made for generic point cloud analysis will provide basic manual tools for classification, they are time-consuming to use. However, software specifically designed for tank analysis can significantly improve workflow efficiency because it understands the basic components of tanks, such as cylindrical shells, cone floors, domed roofs, columns, girders/rafters, etc. Since the shell to floor weld area is

Figure 6. Analysis results showing floor deformations from best-fit cone (left) and shell deformations from best-fit cylinder (right).

Autumn 2021 20

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Figure 7. Analysis results showing shell out-of-roundness at bottom (left) and plumbness from top to bottom

(right).

critical for tank inspection, it is not sufficient to simply divide the tank as a vertical cylinder with top and bottom caps. Software that is specifically designed for tank analysis has the ability to cleanly differentiate shell points from floor points at the bottom weld, taking into account shell and edge settlement in the floor. Even though automated tools can significantly speed up classification, manual or semi-automated tools are necessary to review, cleanup, and reclassify data if needed. In one of the projects that Novlum Inc. worked on, a storage tank was flagged for further engineering review because it failed the shell settlement analysis. Upon review of the scan data, it was found that the code failure was not due to structural deformations, but rather misclassified data. During scanning, the tank floor was wet, creating areas of void and high noise in the scans. These outliers caused by reflections were misinterpreted as floor points, raised the floor elevations, and caused the shell settlement analysis to fail. Had the 3D data been interpreted properly, the engineering review and remediation costs would have been avoided.

Analysis and reporting The last step in the workflow is analysis and reporting. Tank analysis is only possible after the difficult tasks of data registration and classification have been completed. Although it is possible to extract basic metrics by comparing tank shells to cylinders and tank floors to planes, more comprehensive and detailed analysis requires software specialised for storage tanks. In order to compute tank capacities according to calibration standards, software specifically designed for tank inspections is required. Complete integration of governing standards into the software greatly reduces the effort required to manipulate the outputs and to present them meaningfully. While the presentation of outputs may differ slightly across different software packages, the underlying analysis is generally the same. Tank shells are compared to vertical cylinders to show out-of-roundness and Autumn 2021 22

plumbness, and tank floors are compared to planes, cones, and domes to show local deformations. Floor elevations nearest the shell are extracted to compute shell settlement, and floor elevations along radial lines running inwards from the shell are extracted to calculate edge settlement. Floor and shell deflections are often portrayed as heat maps showing deviations from nominal dimensions (Figure 6) while out-of-roundness and plumbness are shown as exaggerated radar plots (Figure 7). While many software packages are able to generate the graphics and tables required for a tank inspection report, automatic report generation can not only reduce effort, but can also drastically reduce human error. While the tasks for assembling a report are not difficult, they are time consuming, repetitive, and susceptible to mistakes. To a client, simple errors in a tank report can put into question the integrity of the entire workflow and jeopardise a business relationship.

Workflow integration Each of the steps in the workflow can be accomplished by off-the-shelf software. However, there is significant advantage in being able to complete all of these steps within the same software package. For example, if a registration error is found during analysis, it is ideal if the registration error can be rectified without having to reclassify the data afterwards. Often, software packages merge all of the scan layers into a single layer when exporting data, meaning it is not possible to go backwards and correct a registration error in the workflow, without having to reclassify all of the data. While there is no magic solution for 3D tank inspections, the right software can significantly improve workflow efficiency. Automation can vastly speed up the process by completing repetitive tasks and reducing errors, but it cannot replace the role of a trained operator who is able to review and interpret the data and the results. The benefits of using 3D laser scanning for storage tank inspection are many, and depend heavily on the ability to accurately and efficiently analyse the data.

Robert L. Ferry, Trinity Consultants, USA, looks at the recent revisions to the US Environmental Protection Agency’s NSPS Kb tank inspection requirements.

long-standing interpretation issue for storage tanks subject to US Environmental Protection Agency (EPA) regulation 40 CFR part 60 Subpart Kb1 (NSPS Kb) has been whether the tank must be removed from service and cleaned in order to conduct the 10-year up-close inspection required for internal floating roofs (IFRs). This up-close inspection of the IFR is required each time the tank is emptied and degassed, but in any case at intervals not greater than 10 years [§60.113b(a)(4)]. The question has been: if an IFR tank subject to NSPS Kb comes to the 10-year milestone without having been emptied and degassed, is it acceptable to conduct the up-close inspection with the tank in-service, or does the tank have to be emptied and cleaned to conduct the inspection? A final revision to NSPS Kb was posted to the Federal Register on 19 January 2021 [86 FR 5013] that resolves this issue. This revision adds a paragraph at §60.110b(e)(5) titled “Option to comply with part 63, Subpart WW, of this chapter.” The option to comply with Subpart WW2 in lieu of NSPS Kb had already been available in multiple rulemakings, such as 40 CFR part 63 Subpart CC3 (Refinery MACT), but the provisions for opting to comply with Subpart WW rather than NSPS Kb under those rules are applicable only to storage tanks that are subject to those rules. This revision to NSPS Kb now extends the Subpart WW option to any storage tank subject to NSPS Kb and not just those that are also subject to another rule such as Refinery MACT. The significance of the Subpart WW option with respect to the 10-year IFR inspections is that it expressly allows these 10-year up-close inspections of IFRs to be conducted with the tank in-service.

Background The rationale for the specified inspection frequency in NSPS Kb was the expectation that tanks, on average, would be emptied and degassed once every 10 years for structural inspection of the tank. The specified frequency, then, was intended to allow the up-close IFR inspection to be conducted when the tank had been cleaned and gas-freed for inspection of the tank itself, thereby avoiding a cleaning and degassing of the tank solely for the purpose of conducting the floating roof inspection. The express concern was to avoid unnecessary degassing of the tank, because the degassing process involves emissions to the atmosphere.4 The intention of avoiding degassing of the tank solely for purposes of conducting the up-close inspection of the IFR for air regulation compliance has been frustrated by the frequency subsequently specified in API Standard 653 (API 653) allowing up to 20 years between internal inspections for tank integrity purposes.5 Thus, an internal inspection of the tank for structural integrity purposes is often conducted on a 20-year cycle, per API 653, but an 2 23 Autumn 2021

up-close inspection for compliance with air regulations is required on a 10-year cycle. In that API 653 internal inspections are conducted with the tank out-of-service, air regulation up-close inspections will also be conducted whenever the tank is out-of-service for the API 653 inspection. The question, then, has been whether the up-close inspections of IFRs that become due between API 653 inspections may be conducted with the tank in-service, thereby avoiding unnecessary tank cleaning and degassing events.

Subpart WW vs NSPS Kb Subpart WW has clearer language In the preamble to the proposal for revising NSPS Kb, the EPA characterised the difference between Subpart WW and NSPS Kb as follows: “The storage vessel design, operation, inspection frequency, inspection procedure, and repair requirements are largely the same between NESHAP Subpart WW and NSPS Subpart Kb. However, the organisation and phrasing of the two rules is different. Where they differ, the requirements in NESHAP Subpart WW are clearer and more stringent than the requirements in NSPS Subpart Kb.” [85 FR 65779, 16 October 2020 – first column, second paragraph.] By virtue of having clearer language, Subpart WW is less prone to adverse misinterpretation than is NSPS Kb.

Subpart WW is more stringent The provisions of Subpart WW that are more stringent than NSPS Kb include the following requirements for specific deck fittings: Whereas NSPS Kb requires the covers for access hatches and gauge float wells to be bolted closed only for IFRs, Subpart WW requires these covers to be bolted or fastened closed for external floating roofs (EFRs) as well. Whereas NSPS Kb requires roof drains to have a cover over at least 90% of the area of the opening only for EFRs, Subpart WW requires IFR drains to have these covers as well.

However, under Subpart WW, it is possible to wait until the next time the tank is emptied and degassed to complete these deck fitting upgrades, as long as the upgrades are accomplished within the next 10 years.

Clarification of Subpart WW gap limit A question that has sometimes arisen with respect to Subpart WW has been whether the 1/8 in. gap limit specified at §63.1063(d)(1)(v) is applicable to rim seals or only to deck fittings. The EPA addressed this issue in a footnote to the preamble for the proposed revisions to NSPS Kb as follows: “EPA does not apply this 1/8-inch maximum gap width criteria to rim seals.” [85 FR 65779, 16 October 2020 – footnote 10.]

Conducting the inspection in-service Safety considerations A concern that arises when considering in-service inspection of IFRs is whether it is safe to do so. Conducting the inspection in-service necessarily involves sending personnel into the tank which, of course, would constitute a confined-space entry. Safety issues, however, are beyond the purview of the EPA and thus evaluation of the safety concerns is a separate consideration from whether the requirements of the air regulation can be met by inspecting the IFR while the tank is in-service. Individual companies make their own determination of whether a given IFR can be inspected safely in-service.

Robotic inspections The question arises as to whether the up-close inspection of the IFR can be conducted robotically, thereby avoiding human entry into the tank. When evaluating the suitability of a robotic option, it should be kept in mind that the requirement in Subpart WW reads as follows: “Floating roof (IFR and EFR) inspections shall be conducted by visually inspecting the floating roof deck, deck fittings, and rim seals from within the storage vessel. The inspection may be performed entirely from the top side of the floating roof, as long as there is visual access to all deck components specified in paragraph (a) of this section.” [40 CFR Part 63 Subpart WW, paragraph §63.1063(d)(1).] Thus any robot or drone used as a means of conducting the up-close inspection must be able to gain visual access to gaskets that may be located beneath lids or covers as well as primary rim seals that may be located beneath secondary rim seals.

Remaining questions

Figure 1. Cable-suspended aluminum IFR (courtesy of Allentech).

Autumn 2021 24

While the 19 January 2021 revisions to NSPS Kb brought certainty to the issue of up-close inspections of floating roofs being allowed to be conducted with the tank in-service, the wording of the revisions left a few questions unanswered. Industry groups submitted comments to the proposed revisions raising these questions, but the EPA responded in the preamble to the final rule that these questions were outside the scope of this rulemaking and may be considered in the future. These questions are: Can the Subpart WW option be made available to other regulations that reference NSPS Kb? As worded, the Subpart WW option added to NSPS Kb is available to tanks

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that meet the applicability criteria of NSPS Kb. However, there are certain regulations (e.g. BWON6, GD MACT7) that invoke NSPS Kb requirements for tanks that do not meet the applicability criteria specified in NSPS Kb itself. It would be helpful if the EPA would further revise NSPS Kb to expressly extend the Subpart WW option to tanks that become subject to NSPS Kb requirements through another rule. Can reporting under the Subpart WW option be on a semi-annual basis? NSPS Kb specifies different deadlines for different types of reports. In rules promulgated by the EPA since the early 1990s, however, it has transitioned to requiring all reports to be submitted on a semi-annual basis. It would be helpful if the EPA would further revise NSPS Kb to accommodate semi-annual reporting. What is the actual deadline for the up-close inspections? While NSPS Kb requires the up-close inspections to be conducted at least every 10 years, the rule does not specify when within the tenth year the inspection would become past due. The EPA has specified in other rulemaking that compliance tasks which are required at a specified frequency are due at some point within the specified calendar period. It would be helpful if the EPA would further revise NSPS Kb to specify that these 10-year up-close inspections must be conducted prior to the end of the calendar year in which the deadline occurs.

Conclusion The 19 January 2021 revisions to NSPS Kb expressly provide for conducting the 10-year up-close inspection of floating roofs while the tank is in-service. The mechanism for doing so is to elect to comply with Subpart WW in lieu of NSPS Kb. The EPA further clarified that the 1/8 in. gap limit in Subpart WW is applicable only to deck fittings and not to rim seals. While this rulemaking brought certainty to the resolution of these two issues, certain other questions were deferred for future consideration.

References 1.

2. 3. 4. 5.

6. 7.

'Standards of Performance for Volatile Organic Liquid Storage Vessels (including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984,', US Environmental Protection Agency, 40 CFR Part 60, Subpart Kb. 'National Emission Standards for Storage Vessels (Tanks) – Control Level 2,' US Environmental Protection Agency, 40 CFR Part 63, Subpart WW. 'National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries,' US Environmental Protection Agency, 40 CFR Part 63, Subpart CC. Preamble to 40 CFR Part 60 Subpart Kb proposed rule, 49 FR 29708-09, 23 July 1984. API Standard 653, 'Tank Inspection, Repair, Alteration, and Reconstruction', Fourth Edition, April 2009, Addendum 1, (August 2010). Paragraph 6.4.2.2 specifies a maximum interval of 20 years if certain corrosion rate procedures are used, and up to 30 years if other specified measures are taken. 'National Emission Standard for Benzene Waste Operations,', US Environmental Protection Agency, 40 CFR Part 61, Subpart FF. 'National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations),' US Environmental Protection Agency, 40 CFR Part 63, Subpart R.

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Joshua James, Liquip, Australia, provides maintenance tips and advice to ensure smooth operation during loading operations.

o reduce downtime and ensure continual smooth operations at each terminal, it is vital to implement and follow a regimented equipment maintenance programme. For instance, API couplers and loading arms provide a critical connection between the tanker and terminal, and it is not unusual for API couplers to experience in excess of 50 connections in a single day. By looking out for and addressing the following areas within their existing maintenance schedules, terminals can ensure their equipment is cared for and will continue to provide the utmost safety, reliability and performance:

Seal selection As the temperature fluctuates in warm or cold climates, and depending on which products and additives flow through the loading arms, it is crucial to use the right product seals for the job. Using incorrect seals may cause the coupler and loading arm seals to become compromised, leading to product leaks. There are a wide variety of product seals available on the market ranging from seals designed to handle typical loading of fuels to those designed to handle ultra-low temperatures and even some harsh chemicals. To determine which seals are best suited to an application, an API coupler manufacturer should be contacted.

Seal wear A coupler performs a high number of connections each day which can cause seals to wear over time. Worn seals may cause minor leaks during loading or after the coupler has been disconnected from the truck API adaptor. This is usually an indication that the product (nose) seal, or one of the other seals such as the poppet adaptor O-ring or bush and O-ring, are due for replacement. Terminal operators should inspect couplers on a regular basis and

2 27 Autumn 2021

changeout any seals at the first sign of wear. To assist with seal changeouts, Liquip, OPW and other manufacturers can provide detailed changeout procedures.

Safety interlocks API couplers are fitted with safety interlocks whereby the coupler cannot be opened until it is fully latched on to an API truck adaptor and it cannot be disconnected until the API coupler has been closed. During maintenance, the

latching function of a coupler should always be checked to continue trouble-free operation.

Dirt build up on latches API couplers come into contact with a number of different vehicles each day and during this process dirt and other debris can build up on the API coupler latches. If too much dirt builds up on the latches, it may create a flawed seal and might prevent the coupler from latching correctly to the truck adaptor. Operators should regularly inspect and remove dirt and debris from coupler latches.

Latch wear As a result of the large number of connections API couplers experience with truck adaptors, latches may wear over time. It is important for operators to check that all latches operate correctly when conducting routine maintenance. To assist operators in determining latch wear, API-LI gauges have been developed that allow operators to quickly and effectively measure the latching capability of API couplers.

Loading arms adjustment

Figure 1. Three-arm bottom loading skid configuration using gas strut loading arms.

Over time the balance mechanism of all loading arms, whether compression, torsion spring or gas strut style, will droop and could lead to the loading coupler sitting just outside of the API envelope (based on API RP 1004). This could result in a coupler position that is too low to ergonomically operate or connect to the tanker. If the loading coupler is no longer in its most optimum loading position, operators will need to increase or decrease upward force to adjust the loading arm. It is important to remember that the horizontal spool must always be suitably supported before commencing any adjustments to the arm. When it comes to gas strut operated arms, adjustments are easily completed by turning the nut on the adjustor bracket. A successful adjustment will allow the coupler to be easily manoeuvred within the API envelope.

Loading arms clashing with obstructions

Figure 2. The LYNX API bottom loading coupler shown in a typical loading configuration.

Autumn 2021 28

The up/down stops can be used to allow the loading arm to move freely without clashing into any nearby obstructions. During maintenance, it is good practice to check that the horizontal arm is parallel to ground and to adjust it as needed, as this will ensure the maximum vertical movement of the arm. To simplify terminal operations, many bottom loading equipment manufacturers have developed advanced technologies to address the above areas and improve bottom loading operations. Liquip’s LYNX API coupler and 'Velvet Touch' LBM gas strut loading arms are just one example of this. When used together, these technologies create an effective bottom loading process. The LYNX seal design of the coupler allows for increased site safety and minimal product leakage during disconnect. Four ‘true interlocking’ stainless steel latches ensure good automatic latching and maximum product

containment during delivery. The coupler can be quickly disassembled through a U-Pin design, while the main seals can quickly be replaced, on or off the arm. The coupler, which has a typical coupler pressure of 80 psi (5.5 bar/550 kPa) and a maximum surge pressure of 493 psi (34 bar/3400 kPa), also has a 150 – 200 mm handle with a positive lock. Liquip’s LBM 800 gas strut balance mechanism has 360° rotation in the horizontal plane, allowing it to easily move from a parked to loading position and, in some applications, to service vehicles on either side of the loading bay. It can be easily configured to suit different styles of loading arms including low profile Figure 3. Components of the LYNX API bottom loading coupler. loading and unloading, A-frame bottom loading, and Pantograph and long reach top loading Conclusion arms. The millions of litres of fuel that pass through a storage The LBM mechanism has a slim line drop leg bracket, terminal every year would have nowhere to go without which provides easy and out of the way installation, and API couplers. Therefore, their design and reliability must can be easily adjusted through a heavy-duty adjustment be second to none if a terminal is to feature a truly mechanism. efficient loading-rack operation. By incorporating the The LYNX API coupler and the LBM800 balance above tips into terminal maintenance regimes, loading mechanism coupler can be equipped with seals to equipment will continue to provide safe and reliable handle various products and temperatures ranging from performance. -40°C to +90°C.

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ingapore continued to remain the world’s top bunkering port in 2020. The bunker sales reached 49.8 million t, an increase of 5% year-on-year.1 Introduction of Coriolis mass flow meters (MFMs) in the bunker transfer process has acted as a catalyst for this growth. Today there are more than 200 MFMs installed on board the bunker tankers that securely oversee close to US$19 billion worth of very low sulfur fuel oil bunker fuel transactions in Singapore.2 The margin of error here is razor thin; even a 0.5% error would amount to close to US$93 million in losses. With so much at stake and the bar raised with high standards set using MFM for technology excellence, something special was needed to maintain and safeguard this standard in a sustainable way. Although the mass flow metering system (MFM system) has demonstrated reliable performance over the years, local regulations and custody transfer requirements warranted that MFM be periodically re-calibrated to maintain its capability for bunker fuel transactions. In the absence of a local traceable calibration facility which covers the flow/fluid characteristics for the bunkering application, the MFM must be sent overseas for a re-calibration. This process is expensive and time consuming as it requires a MFM to be removed from the installation site and sent to the suitable calibration laboratory. To avoid financial burdens on the tanker operators and to ensure availability of bunker tankers, the local authority recommended meter verification, a metrologically acceptable pragmatic approach.3 It recommended periodic zero verification (ZV), starting with

Autumn 2021 30

quarterly ZV in the first year followed by half yearly in the following year. After three years of use, the MFM is required to be calibrated by a recognised and traceable flow facility. Although this approach does not verify the meter’s performance in-situ at actual operating conditions, it ensures that the health of MFM is validated. However, the industry demanded a more holistic approach of validating the meter's performance to ensure continuity of bunker custody transfer operations. Given the challenges the application presented, meter verification using a master meter (MM) was the only viable option.

General requirements Generally, a custody transfer application demands stringent accuracy requirements. The MFM system for bunkering has to fulfil the overall measurement uncertainty (MU) of 0.5%, in accordance with SS 648. The MFM from this system must be water calibrated to +/- 0.1% permissible error, and not exceeding 0.2% MU of uncertainty claim for conversion from water to hydrocarbons fuel measurement. Comparatively for the MM, the requirements prescribed for use as the reference standard were more stringent and complex. These included requirements for bidirectional flow, linearity, stability, reproducibility, repeatability error, etc. The MM together with its associated devices are required to be calibrated in an IEC/ISO 17025 accredited calibration laboratory with water and oil of similar properties as bunker fuel. As a rule of thumb, the MM needs to be at least three times better than the MFM under test.

Venkatesh Deshpande, Endress+Hauser, and Darrick Pang, Metcore International, outline how traceable Coriolis mass flow meter verification will enhance the credibility and reputation of Singapore as a major international port.

Manufacturing process Preparation To comply with the requirements set forth by the authority, this MM was manufactured with the most stringent production process with relevant qualified specialists and professional experts monitoring each stage of the process. The utmost professional care was taken in the selection of material and components to ensure the best performance of the meter for the intended application.

Calibration The MM was subjected to rigorous calibrations, first a bidirectional calibration with water, at Endress+Hauser’s ISO/IEC 17025 accredited calibration laboratory in Reinach, Switzerland, which has a best measurement capability of 0.015%. The results obtained were extremely accurate. Coriolis MFM measures independent of the fluid flow profile and has long been recognised to be largely immune to varying process and installation conditions. However, the research has shown that there is a considerable effect on Coriolis measurement accuracy because of fluid property changes, which can be represented by Reynolds number. This error is particularly prominent at low flow rates in high viscosity fluids such as bunker fuel. All flow metering technologies are affected by this Reynolds number effect. Following years of research on the Reynolds number effect, Endress+Hauser has developed a patented algorithm that dynamically compensates for the changing Reynolds number. This algorithm has been implemented on all of the

company’s Promass Coriolis MFM. Thanks to this algorithm, the meters, with a standard factory water calibration, can measure any fluid within the prescribed MPE of +/-0.2% per OIML R117-1.4 This has been validated and endorsed by NMi Certin B.V. in the evaluation certificate of Promass.5 However, the hydrocarbon industry’s relentless quest for improvements in measurement capability required a fuel oil calibration for this Endress+Hauser MM supplied to Metcore. It was then calibrated as a fully assembled skid with hydrocarbon products that have similar bunker fuel viscosity range, at an ISO/IEC 17025 accredited independent hydrocarbon flow facility in Europe. To maximise the accuracy, Endress+Hauser deployed the enhanced metering accuracy (EMA) procedure during the oil calibration. As part of this procedure, the company’s algorithm provides an output signal that enables the flow computer to apply a real time meter factor for every change in the fluid properties. EMA calibration covered the entire Reynolds number range that the meter would encounter in the field. The calibration results with different products were repeatable and accurate within +/-0.05%. The calibration results and overall measurement uncertainty was computed and reviewed by NMi Certin B.V. and the MFM was endorsed with a declaration enabling it to be used as a MM.

System design Special considerations were given while designing and selecting the components for the MM system. The system consists of 3 31 Autumn 2021

three major parts: piping section, structural assembly, and electrical and instrumentation (E&I) components. The piping was designed specifically for harsh marine environments and conditions including vibrations, and a proper stress analysis was performed. Piping components were assembled using qualified welders and procedures and tested as per international standards to check for any defects or discontinuity using the most reliable and sophisticated testing technologies. The skid assembly and structural design was primarily constructed for its mobility and flexibility, so as to ensure easy interfacing with the bunker tankers’ MFM system. The E&I components were selected based on their suitability for hazardous area installation and usage. Flow computer and human machine interface (HMI) were designed to be modular, offering flexibility and easier operation even in hazardous locations. After assembly, the metering system underwent rigorous tests in the factory, following the stringent Endress+Hauser quality procedures. Maximising operational efficiency and easier mechanical and electrical interconnections in the field were the key aspects considered during the skid design.

The verification process To perform the meter verification using the MM solution, the meter under test (MUT) is connected in series with the MM.

The flow is circulated in the loop while the process stability is monitored. Several flow parameters are considered for ensuring suitable process conditions are met prior to the start of the meter verification runs. This process stability criteria has been established from years of experience surrounding the operations and maintenance of flow measurement systems in bunkering applications. Once the stable process conditions are met at tanker operating flow rate, multiple measurement readings are recorded and results on the repeatability and error are tabulated. As stipulated in TR 80, the MUT is verified to be within 0.12% repeatability and average error of not exceeding +/- 0.3% for the MUT to be deemed suitable for bunker custody transfer application. A verification report is generated which is endorsed by the relevant authorised parties.

Development of new standards Following the successful implementation of Coriolis MFM and their resulting benefits,6 the industry was looking at harmonisation of measurement methods across the bunker supply chain. This was in addition to the industry need for a traceable, pragmatic, cost-effective and sustainable means of verifying the meters on board the bunker tankers. The Standards Development Organization/Singapore Chemical Industry Council invited experts from the bunkering industry into the working groups to establish Singapore Standards for meter verification and loading operations of bunker fuel from terminals. This led to the development of two new Singapore Standards:7 SS 660: 2020: Code of Practice for bunker cargo delivery from oil terminal to bunker tanker using mass flow meter. TR 80: 2020 Code of Practice for meter verification using mass flow meter. These standards generally addressed the needs of a harmonised measurement method and meter verification of the respective MFMs used across the bunker supply chain.

Operational experience Figure 1. Bunker sales volume.1

Figure 2. MM water calibration results.

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So far, close to 100 meter verifications have been performed using the Endress+Hauser MM solution. These verifications include MFMs from a number of suppliers. One of the key considerations for successful meter verification is achieving process stability. There are many contributing factors that impact this process, including: consistent pumping flow rate, pressure, temperature, and aeration during the verification process. Achieving process stability during meter verification is challenging and requires a great deal of expertise in understanding the bunker operation and its process behaviour. The flow computer and its associated HMI was specifically programmed to utilise the diagnosed parameters of MFM to determine stability of the process conditions before the start of verification run. The complete verification operation becomes more efficient with the MM verification. Overall, the meter verification approach has improved the operational efficiency for tanker operators as it is more viable and practical as

Many sectors are transitioning to Industry 4.0 by implementing the Industrial Internet of Things (IIoT) in their operations, and this will be a key ingredient in the future roadmap of Endress+Hauser’s MM solution.

Summary

Figure 3. MM assembly undergoing hydrocarbon calibration.

Figure 4. Meter verification in progress using MM. compared to the current system re-validation tests. The downtime needed to evaluate the MFM system performance is minimised substantially, adding to the significant financial savings. Ultimately, the meter verification methodology enables customers to improve on their bunker tankers’ operating efficiency management, while optimising their MFM systems for custody transfer purposes.

Further development The Coriolis MFM’s verification process using the MM solution has been well received by the bunkering industry. The successful use of a MM as a means of verifying MFMs on board bunker tankers has fuelled interest in not only the global bunkering fraternity, but also from the major oil and gas stakeholders.8,9 There has been an increase in demand for MM solutions by the developing bunkering ports across the globe. Future development of new ISO standards along the lines of TR 80 and SS 660 will provide the much-needed guidelines for the global oil and gas sector, as well as the marine industry. In the foreseeable future, the use of the MFM will bring about significant improvements and greater visibility with regards to the digital mass balance of the various stakeholder’s assets. With the improved visibility and good standing, the auditing exercises conducted by financial organisations, such as banks, will become easier. Autumn 2021 34

Coriolis MFM have been used in the oil and gas industry for many years as MM to periodically verify the performance of the meter in service in the field. International guidelines such as API and OIML are commonly referenced to perform the meter verification/proving the use of the MM. With the meter verification approach using Coriolis MM, the concerns of the industry stakeholders regarding the re-calibration and performance validation of the custody meter can be holistically addressed. This method enables a reliable and traceable way of ensuring the continuous performance of the MFM on board the bunker tanker without removing the MFM from service, thus eliminating the possibility of downtime in the MFM operations. MFM are being used in these sectors for reasons such as accuracy, simplicity of operation, low operating costs, stability, availability, proven track record, and compliance to the transparency requirement from regulatory bodies for audit purposes. By applying the proprietary EMA method utilising optimised Reynolds number linearisation, a new level of MM accuracy can be achieved to address the demands of high precision. The design of the MM system using a Coriolis MFM is the product of advanced proprietary technological expertise from Endress+Hauser and the extensive experience in the bunkering industry from Metcore International. This collaboration had the support of the Singapore Authorities and the bunkering industry stakeholders, which ensured the success of this project. Traceable MFM verification will further enhance the credibility and reputation of Singapore as a major international port and is of great value when monetised.

References 1.

2. 3. 4. 5. 6.

'Singapore’s 2020 Maritime Performance Resilient Despite COVID-19 Pandemic', Maritime and Port Authority of Singapore (MPA), (13 January 2021), https://www.mpa.gov.sg/web/portal/home/ media-centre/news-releases/detail/d95e9e96-7df3-4235-80e393dde03dae3e 'Graph: 2020's average bunker price 8% lower than 2019', Ship & Bunker, (18 December 2020), https://shipandbunker.com/news/ world/240274-graph-2020s-average-bunker-price-8-lower-than-2019 SS 648 : 2019: Code of practice for bunker mass flow metering. Organisation Internationale de Metrologie Legale, International Recommendation R117-1: Dynamic measuring systems for liquid other than water: Metrological & technical requirements. NMi Certin Evaluation Certificate, https://portal.endress.com/ dla/5000910/6098/000/07/TC7149_Pmass300-500_ZE016.pdf 'Factsheet on Case Study on TR48: 2015 on Bunker Mass Flow Metering', https://www.mpa.gov.sg/web/wcm/connect/ www/8564a1bf-0179-47f7-9a84-0ed5cce14fbf/Annex+A+-+Factshe et+on+Case+Study+on+TR+48+2015+on+Bunker+Mass+Flow+Meter ing.pdf?MOD=AJPERES 'SIBCON 2020: Singapore introduces new MFM bunkering standards SS 660 and TR 80', Mainfold Times, (7 October 2020), https://www. manifoldtimes.com/news/sibcon-2020-singapore-introduces-newmfm-bunkering-standards-ss-660-and-tr-80/ 'Singapore: Coriolis Master Meter for MFM verification garners international interest', Mainfold Times, (18 February 2020), https:// www.manifoldtimes.com/news/singapore-coriolis-master-meter-formfm-verification-garners-international-interest/ 'Singapore: Milestone achieved as first bunker tanker undergoes MFM verification via Master Meter', Mainfold Times, (22 October 2020), https://www.manifoldtimes.com/news/singapore-milestone-achievedas-first-bunker-tanker-undergoes-mfm-verification-via-master-meter/

Craig M. Carroll, Magnetrol Ametek, looks at the steps that have been taken to help prevent overfill spills, and how level instrumentation can help to reduce the risk of a catastrophic event.

n the early morning hours of December 2005, the largest fire in Europe since World War II engulfed the Buncefield Oil Depot in Hemel Hempstead, England. Tank 912 located within the complex had overflowed, which allowed the rapid formation of a vapour cloud; rich with a mixture of fuel and oxygen. Condensing and then flowing outward from tank 912, the vaporous cloud spread in all directions. While the source of the ignition is not clear, something ignited the rich mix and the first explosion rattled the oil storage terminal at 6:01 a.m. local time. Eventually, 20 large storage tanks ignited, which required a massive firefighting effort. The fire burned for five days, destroying much of the depot before the blaze was finally extinguished. Thankfully, there were no fatalities from the explosion, but the scale, damage and potential for loss brought a focus to overfill prevention on a global scale. The investigation ultimately revealed the cause to be the failure of an overfill safety system (a combination of electro-mechanical servo gauges and a failure of the high-level switch for tank 912 in bund A combined to allow

the overfill event). This safety system failed to operate and shut off the supply of petrol to the tank. The petrol would not easily explode in a liquid state, but when a large amount spilled out and mixed with oxygen, a concentration was reached which supported combustion. The transition of the petrol to a vapour state was rapid and exponentially increased the reach of the cloud. Since that time and with a renewed focus on preventing occurrences such as Buncefield, guidelines, best practices and standards have been developed to provide operations with a clear direction for overfill prevention. The final Buncefield report was released in 2008 and helped outline recommended practices for primary, secondary and tertiary containment of a potential overfill situation. These standards cover a wide range of overfill prevention areas. Even with the best practices, in recent years overfill incidents have resulted in loss of life and billions of dollars in damages to petroleum facilities worldwide. Some of these incidents have been traced to the failure of the level control 3 35 Autumn 2021

Figure 1. Action levels and response. equipment which resulted in loss of containment of the flammable liquid. More common are minor spills that cause significant environmental impact and result in millions of dollars in clean-up fees and environmental agency fines. There are multiple steps and activities that can be engaged to mitigate tank overfill issues. In order to keep standards relevant, the American Petroleum Institute’s API 2350 5th edition guidelines for overfill protection of petroleum storage tanks have been revised. The latest edition combines the revised prescriptive standards with the functional safety standards of safety instrumented systems (SIS) as described in IEC 61511. The following are guidelines standardised per API 2350 to mitigate the potential for overfill: Verify that all tanks have level control equipment and operational procedures. Review with senior leaders to embrace the principles of safety and environmental protection, as well as each being held accountable in mitigating risk. Employ a management system including a formal approach to: training, risk assessment, scheduled inspections, periodic testing, and equipment maintenance programmes. Vital to these new requirements is the application of level instrumentation as one part of a comprehensive overfill prevention process (OPP), which now addresses Autumn 2021 36

operational processes, including capabilities and response times as well as operating parameters for every tank; including equipment category, level of concern (LOCs), response times and alarm procedures. Magnetrol Ametek has provided instrumentation that has met or exceeded the API guidelines for decades, but complying is not simply about the equipment being used to avoid overfilling vessels. Additional best practices have been included related to the environmental consequences of tank overfills which can also produce vapour clouds that may escape the secondary containment and reach an ignition source resulting in a vapour cloud explosion (VCE). Implementation of a risk assessment system is a key step in this process. While the API 2350 5th edition does provide an example of a risk assessment, it does not provide instruction on how to perform the risk assessment. It is also required that written procedures for operating under normal, abnormal, startup and shutdown conditions be performed. Lastly, communications between the supply facility and receiving facility should also be formally reviewed and available as written documents. Risk management is a process put in place to reduce risk to an acceptable level by managing probability and consequence of potential hazardous events: Risk =

Probability (likelihood)

Consequence (severity)

If the risk is deemed unacceptable, it must be reduced by taking the necessary steps outlined as shortfalls: procedures, instrumentation, training or documentation. When evaluating the consequences, a qualitative or quantitative approach can be taken. The use of descriptors such as minor or severe injury can be based on experience or the potential outcomes to better estimate the consequences: Jet fuel fire. Flash fire. VCE. Boiling liquid expanding vapour explosion (BLEVE). Spills.

If the risk assessment covers multiple tanks, a risk screening activity may assist with prioritising and focusing resources on the highest risks first. Screening can point out areas that are higher in priority and suggest which tanks or operating equipment merit first consideration and resources. More than one risk assessment is recommended, as the review is considered subjective by the personnel who perform the assessment and each assessment is to be simply a tool to aid in making informed and educated decisions. The oil and gas industry is no stranger to incidents that have resulted in stricter regulations and guidelines for operating safely and responsibly. Both the API and Health and Safety Executive (HSE) have guidelines to help ensure proper overfill prevention through management systems and safety integrated processes for level measurement in storage tanks. All of these guidelines are targeted at reducing the risk of a Buncefield-type incident occurring at any storage terminal; however, there are benefits to risk reduction that go beyond incident prevention, including a reduction in liability insurance for storage terminals. Storage terminal operators and insurance providers have different perspectives on liability insurance and how they evaluate and minimise the risk.

Assessing insurance risk Insurance agencies look at how much a storage terminal location has minimised the risk of events deemed catastrophic to the environment and employees. Overfill prevention is one aspect of the risk mitigation that is reviewed for liability insurance. The insurance agency will review the local

Figure 2. Buncefield complex at the Hertfordshire Oil Storage Terminal.

jurisdictional requirements and industry guidelines when determining the insurance rates. During this review, the insurance agent is looking for evidence that the safety measures are properly maintained, as well as having each safety measure functioning properly. It is important for the devices that are used as safety guards to have an ability to be easily tested and maintained. Many insurance agencies will make recommendations based on failure modes they have experienced to ensure safety. These recommendations include processes to maintain operation, but also features of the level transmitters or switches themselves. Level transmitters for tank level should have internal diagnostics that are able to identify issues when they exist. Level alarms (or switches)

should be able to be proof tested either electronically or manually to ensure proper functioning. By choosing the appropriate level transmitters and switches with these capabilities, along with additional safety measures outlined in API 2350, the overall risk of an incident is reduced and the insurance premium is much lower.

Assessing operation risk From the insurance customer’s perspective, the narrative changes. Plant operations staff are concerned with the ability to operate efficiently based on expenses and costs. Storage

terminals have to manage both fixed and variable costs in order to operate profitably. As previously noted, this can be managed by making sure that risk has been reduced across the terminal. As facilities and their operators come into compliance with API 2350, they can justify to insurance agencies the effort towards reducing and mitigating risk. Typically, they can expect to be audited by the insurance entity (external or internal) to review their level instrumentation annually, so it is important to stay compliant. Operators take on a large amount of risk by not following the recommendations of the insurance agencies and could face fines for not complying with industry standards if an incident were to occur. They can evaluate the level instrumentation on the market, but it can help to seek guidance from suppliers for insurance agency recommendations.

Level transmitter and switch providers

Figure 3. External floating roof storage tank.

Figure 4. Fuel storage depot.

By selecting the appropriate level instrumentation, a storage terminal site can demonstrate that it has taken measures to reduce the risk of overfill or other hazardous situations. As level instrumentation technology has advanced, continuous level transmitters have become more prevalent in storage terminal level control. There are many transmitters on the market that have self-diagnostics continually running health assessments of the device. Based on the storage terminal’s assessment of critical tank levels, the transmitter can identify when these levels are reached, allowing ample time to remove product from the tank as part of the overfill prevention system. Beyond previously using point level controls, continuous level measurement devices can provide real time level readings to control rooms while tanks are being filled/emptied. This helps the operator reduce the risk of having a dangerous event by knowing the tank level in real time. A further risk reduction step is to utilise additional point level controls as the fail-safe alarms. The continuous level device can have the output set to alarm certain functions, but if those were to fail, then the additional alarms at high and low level can provide emergency shutdown or emergency pumping of product to avoid an overfill. These devices can be as simple as a mechanical level switch with manual proof test capability, or they can be as sophisticated as an electronic point level switch using ultrasonic technology with built-in self-test diagnostics. Either of these are industry acceptable and provide an added layer of protection to meet industry standards and reduce overfill risk.

Overfill prevention resources

Figure 5. Vertical oil storage tanks with staircase.

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There are many level instrumentation products on the market that can help an owner/operator reduce the risk of an overfill spill or catastrophic event. They range from simple to complex, but all add to the goal of reducing the possibility of an incident. Magnetrol Ametek outlines information on industry standards with the offering of an overfill prevention kit. This kit outlines how to assess the important levels where instrumentation must control either a pump or a valve to ensure the product in the tank remains at a safe level. It then recommends the appropriate technologies based on tank alarm needs, the product that is in the tank and the type of tank configuration. Using these level technologies demonstrates a reduction in risk. This can result in reduced insurance liability costs and improved profit margins.

Marianne Williams, Emerson, USA, explains the significant benefits that can be achieved through the remote partial proof-testing of level measurement instruments in an overfill prevention system.

he overfilling of process vessels and storage tanks containing hazardous materials has long been a leading cause of serious incidents in the refining, gas processing and petrochemical industry. The consequences of a product spill can be catastrophic, including injuries or fatalities to personnel, significant damage to assets, harm to the surrounding environment, and damage to an organisation’s reputation. The best way to deal with a potential incident is to prevent it from happening in the first place, and best practice for minimising the risk of overfills involves employing several independent layers of protection. The critical first line of defence is the basic process control

system (BPCS) that monitors and controls the production processes. If the BPCS is functioning correctly, there is no need for the other layers of protection to become active. An overfill prevention system (OPS) provides an independent second layer of protection. The OPS is normally dormant but operates when the BPCS fails to prevent the tank level from reaching the critical high point. The OPS stops the situation from escalating by alerting an operator, closing valves and/or shutting down pumps. A thorough safety plan must also consider the worst-case scenario, where both the BPCS and the OPS fail to stop a spill from occurring. A third layer of protection is typically provided by a dyke or concrete wall 3 39 Autumn 2021

that surrounds the tank to contain a spill. If required, the fourth and final layer of protection is to alert the emergency services.

Safety standards

Figure 1. Traditional proof-testing methods require

operators to enter hazardous locations or work at height to access devices, which poses a potential risk to their safety.

The OPS is the last line of defence for preventing a spill from happening and should be designed and implemented in compliance with the key global safety standards relating to overfill prevention. These are: The International Electrotechnical Commission’s IEC 61511 standard: this outlines best safety practices for implementing a modern OPS within the process industry and is an industry-specific adaptation of IEC 61508, which is an industry-independent standard for functional safety. The American Petroleum Institute’s API 2350 standard: this provides minimum requirements to comply with modern best practices in the specific application of non-pressurised aboveground large petroleum storage tanks, but can also be applied to certain tanks outside this specific scope.

Components of an OPS

Figure 2. Remote partial proof-tests can be initiated by an operator issuing a command from the comfort of the control room.

An OPS can be either manual or automated. Manual OPS are easier to implement and less complex, with lower initial costs. They typically consist of a level sensor or switch that transmits an audio-visual alarm to an operator, notifying them to take appropriate actions such as manually opening or shutting off a valve to prevent an overfill. An automated OPS includes three basic elements for each of its safety instrumented functions (SIF): a sensor to monitor product level, a logic solver to poll the sensor and act when necessary, and a final control element in the form of actuated valve technology to safely shut down the process. The reliability of the overall OPS is derived from the reliability of these individual components. A formal methodology has been established to assess the reliability of each of the components and then calculate the overall reliability of the system. Probability of failure on demand (PFD) is used to indicate reliability. PFD is the likelihood that the component or system could fail at the very moment when it is needed. Reducing PFD therefore achieves greater risk reduction, and robust and reliable hardware reduces PFD and creates a more reliable OPS.

Proof-testing

Figure 3. Partial proof-tests bring the PFD of the

device back to a percentage of the original level and ensure it fulfils its specified SIL requirement. Partial testing can provide a technical justification for extending the time interval between comprehensive tests.

Autumn 2021 40

Age increases the potential for hardware to fail. However, periodically checking the functionality of OPS components maintains confidence in their ability to perform correctly when there is a safety demand, and verifies that they are operating at the required safety integrity level (SIL). These checks are known as proof-tests and involve testing each component individually as well as each SIF as a whole, as a failure of any component would compromise the SIF’s ability to safely shut down a dangerous process. The latest level measurement devices for OPS applications incorporate diagnostic software that detects

a failure and takes the device to a safe state. However, some failures are not detected by the device diagnostics. These are known as dangerous undetected failures (DUs) and are identified during proof-testing. DUs are expressed as failures in time (FIT) and measured in DUs/109 hrs in operation. Ideally, the FIT rate should be extremely low, and selecting an instrument that provides a high level of diagnostic coverage will minimise FIT. The effectiveness of a proof-test in finding DUs is known as the proof-test coverage factor, and this should be as high as possible. Ideally, the proof-test coverage would reach 100%. However, in reality, tests are not 100% effective. A high proof-test coverage does not always ensure a low PFD, but all things being equal, a device with a lower FIT will achieve a lower PFD. Two types of proof-test – comprehensive and partial – may be performed in compliance with both IEC 61511 and API 2350.

Comprehensive tests Comprehensive tests achieve the highest proof-test coverage and involve testing the entire SIF to ensure that all of its components are functioning correctly. This returns the PFD of the SIF very close to its original level. These tests are traditionally performed manually by technicians in the field, with another worker in the control room verifying the reaction of the system. To prove that a level sensor is functioning correctly, the product level can be raised manually to the activation

point of the device under test. The danger of this approach is that if the device is a high-level sensor and fails to activate, this could lead to a spill. As a result, the latest version of API 2350 does not recommend that the tank level be raised above the maximum working level. Performing proof-tests in this way consumes a significant amount of time and manpower and can lead to the process being offline for an extended period, affecting process availability and having significant cost and worker safety implications. An alternative approach is to remove the instrument from the tank and perform a simulated test (known as an immersion test) in a different environment, such as a bucket. If the device is removed from a tank containing a hazardous or unpleasant product, the test would be performed in water instead. However, this would not prove that the device would work in the specific application, and the proof-test coverage would consequently be reduced. This method of testing also involves tanks being taken out of service for an extended period, thus affecting profitability and exposing workers to safety risk. This method is also prone to human error when restoring equipment after testing.

Partial tests Partial proof-tests have a reduced scope compared to comprehensive tests and are performed to ensure an individual device has no internal problems. Partial tests bring the PFD of that device back to a percentage of the

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original level and ensure that it fulfils its specified SIL requirement. Whereas a comprehensive proof-test verifies all three functional elements of a device – output circuitry, measurement electronics and sensing element – a partial test verifies only one or two of them. However, a combination of partial tests that covers all three functional elements will reach a proof-test coverage close to that of a comprehensive test. Partial tests do not replace comprehensive tests – they complement them. As a partial test detects only a percentage of potential failures, a comprehensive test must eventually be carried out after a given time interval to return a device to its original PFD. However, partial testing can crucially provide a technical justification for extending the time interval between comprehensive tests, while remaining within regulatory requirements. This provides organisations with the freedom to schedule testing around planned shutdowns, resulting in significant operational cost savings.

Remote partial proof-testing The digital technology available in modern level instruments enables partial proof-testing to be performed remotely rather than through the traditional on-location approach. As a result, partial testing can be performed in minutes, thereby minimising process disruption, and can be performed in-process, without the need for raising and lowering the process material. Performing a partial test keeps workers out of harm’s way and results in significant time and cost savings. Consider the example of vibrating fork devices, which are typically applied within an OPS to provide high and low limit detection. In the latest advanced devices, remote partial proof-testing can be performed by issuing a HART® command from the control room. Upon receiving the command, the device enters test mode, whereby its fork frequency is simulated for on, off and alarm conditions. It then cycles through the different current output levels, verifying that there are no faults preventing the device from switching from the on state to the off state, or vice versa. The test exercises the processing and output electronics of the device, and since it is performed in-process, it can take less than one minute to complete the test cycle. On completion of the proof-test, a status is displayed within the control room to show whether it was successful. The device then automatically returns to operational mode, thereby eliminating the risk of it accidentally being left in test mode. Remote partial proof-testing provides significant benefits in terms of reduced time and complexity. As the instrument remains installed and does not need to be immersed during the test, tank downtime is minimised, and worker safety increased. Consequently, the ability to perform partial proof-testing remotely has become a key selection criterion when implementing point level technology as part of an OPS.

Real world savings A major US refining and gas processing company is using this technology to help make significant efficiency and Autumn 2021 42

cost savings. The company operates a large number of compressor stations across several sites. Each compressor uses between two and four scrubber bottles, in which fluid levels must be measured. The existing level measurement solution consisted of float switches installed to provide a high-level alarm. The devices offered no real-time certainty of their functionality, were prone to wear, and required frequent rebuild. In addition, parts sometimes got lost in the scrubber bottle, causing additional issues. The scrubber bottle works by knocking out any residual fluid from the gas stream before it enters the compressor. High-level alarms are used to prevent liquid from entering the compressor and causing damage. A separate level switch is used to operate the dump valve to remove the fluid build-up in the scrubber bottle. Proof-testing was a very important part of the process. If a high-level alarm failed, it would risk a spill. The compressor stations are spread over a vast area, in remote locations and in areas where weather conditions can be challenging. Company policy required all the high-level alarms to be periodically checked and tested to verify functionality. This was a time-consuming, costly and potentially risky process. The scrubber bottle units were shut-in annually for inspection, testing and maintenance. Each float had to be removed from the vessel for immersion testing, causing multiple safety concerns. This process resulted in substantial lost time and production, as well as additional maintenance scheduling. Removing the floats tended to cause thread damage to both device and vessel over time. Including travel to and from the site and the draining of the tanks, the total testing time per float switch could be several hours. The manpower required for testing meant costs added up to hundreds of dollars per unit tested. To optimise its scrubber bottle maintenance procedures, the company replaced the float switches with Emerson’s RosemountTM 2140:SIS vibrating fork level detectors. In total, 220 of these devices were installed across 110 compressor stations. The remote proof-testing capability of the device enabled functional high-level alarms to be confirmed without having to travel to, or shut down, the scrubber bottle or compressor station. The remote proof-test is now performed in-process and completed in just a few minutes per device. The solution eliminated the company’s safety concerns because operators are not exposed to the process media during testing. The devices were found to be very reliable, maintenance-free, and had the advantage of an adjustable switch delay which prevents false switching from turbulence. The company was able to reduce maintenance by approximately 1000 hours/yr and reduce its maintenance budget by US$264 000 through eliminating the need for annual manual testing of the float switches. Avoiding shutdowns enabled the company to increase profit by US$1 144 000, and the project’s payback period was approximately four months, with a return on investment of 28%.

Brandon Stambaugh, Owens Corning, USA, presents three essential design factors to consider when insulating storage tank systems.

nique in shape and often storing volatile contents, storage tanks are no ordinary structures. They can reach 50 m (164 ft) in height, 90 m (295 ft) in diameter and hold up to 270 000 m3 (9 450 000 ft3). From a thermal perspective, storage tanks house materials demanding a range of temperature environments – from cryogenic (LNG, LOX, LIN) to high temperatures (thermal fluids, bitumen asphalts, molten salts). Storage tanks present complex challenges for those charged with ensuring an insulation system supports safety, helps preserve contents inside the tanks, and protects long-term operational efficiencies. Addressing these challenges as part of the design process can support the performance and longevity of the storage tank asset. This article will consider three essential design factors for insulating storage tanks.

43 Autumn 2021

Essential design factor 1: compressive strength, stability, and weight load When considering insulation materials, compressive strength is often overlooked as a distinguishing feature; however, compressive strength is needed to support loads, such as in tank bases. Compressive failure of insulation can cause deterioration of the insulation system and lead to damage of mechanical systems and equipment. Tank base insulation must provide the necessary compressive strength to support filled containment tanks. Failure to provide adequate support can allow for settlement of the base, which may generate ground heaving, permit foundations to reach unwanted hot or cold temperatures, and reduce thermal insulating capacity. If damage continues, the tank bottom could eventually rupture, allowing contents to leak or resulting in reduced process control and solidification of the contained liquid. Insulating materials used on tank bases also need to resist long-term creep or compressive creep. This distortion may cause insulation to move or deform and can occur when insulation is under a persistent mechanical load. In addition to providing compressive strength, insulation used on tank bases needs to provide dimensional stability when exposed to extreme temperatures. Organic and open-celled insulation materials, which are generally not suitable for service in this application, may exhibit swelling, warping, distortion and expansion or shrinkage, depending on the temperatures they encounter. Material selection is critical, and choosing an inorganic, closed-cell material, like cellular glass insulation, can provide the necessary stability over time and across the temperature range involved to protect long-term tank function. Tanks containing cold to cryogenic materials are expected to comply with industry standards such as EN 14620:2006 – ‘Design and manufacture of site built, vertical, cylindrical, flat-bottomed steel tanks for the storage of refrigerated, liquefied gases with operating temperatures between 0°C and -165°C (32 °F and -265 °F)’ – EN 14620-4 and API Standard 625.1 The initial standard dictates elements and application rules for design, while the related EN 14620-4 addresses the use and design of insulation and specifies the structural requirements involved.2 Tank and support structure insulation should be able to handle the loads involved, providing for considerations related to seismic conditions and capable of withstanding both normal operating conditions and hydrostatic testing pressure. Similarly, API Standard 625 – ‘Tank systems for refrigerated liquid gas storage’ – addresses components of tanks intended to house liquefied gases.3 Additionally, insulation system designers can consider how insulating materials to be used with tanks and tanks bases are examined. Standards such as ASTM C165 – ‘Standard Test Method for Measuring Comprehensive Properties for Thermal Insulations’ – may be used to help determine compression behaviour.4 At above ambient temperatures, if insulation without the necessary compressive strength and dimensional stability is used on storage vessels housing materials, it can put the contents at risk of increasing viscosity and solidification. Foundation settlement under the tank’s weight may also Autumn 2021 44

reduce the thermal performance of the vessel. However, use of an inorganic, high weight-bearing insulation, such as cellular glass insulation, can provide the required comprehensive strength and dimensional stability to insulate tanks and protect tank base function. Because cellular glass insulation does not warp or deteriorate, it can also provide consistent thermal performance while managing a heavy weight load.

Essential design factor 2: storage temperature and thermal performance Tank building standard EN 14620 also outlines thermal requirements for the insulation components used with tanks.1 The installed insulation must maintain internal tank temperature to prevent more boil-off than is permitted while keeping outer tank components above a set temperature. These temperature requirements are in place to help prevent the formation of ice or condensation on the exterior of the tank, along with keeping the ground under the tank from freezing. The consistency of the thermal performance of an insulation across the temperature range influences facility efficiency and helps to limit heat transfer, achieve minimal thermal expansion or contraction, and supports employee safety. Another essential practice for reducing energy loss is insulating the tank walls and roof systems. Properly insulating the entire system helps limit energy loss by creating a thermal barrier between the internal process temperature and the external environment. Proper insulation system configurations can also help reduce maintenance costs and support employee safety. Regardless of content temperature, insufficient insulation may permit excessive heat transfer. When tanks contain below ambient liquids, insufficient insulation may allow the surrounding ground to freeze, adding to the potential for instability or movement. This transfer may mean that the support structure starts to freeze, becomes brittle or develops cracks and mechanical issues. These conditions can damage the tank and could lead to evaporation of tank contents. In addition, when working with cryogenic liquids, the whole tank system should be insulated to help reduce boil-off, which can increase operating costs. When heat enters the cryogenic tank, it gives a cold liquid, such as LNG, the opportunity to evaporate, creating boil-off gas (BOG). Reducing the boil-off helps control pressure within the tank and reduces methane, a prolific greenhouse gas, or other products of methane combustion, such as CO2, from venting or flaring processes from being released into the atmosphere. At the other end of the temperature spectrum, insulated tank bases are needed to protect materials stored at higher temperatures. In these instances, insulation on the supporting platform can protect the concrete foundations from heat damage and help maintain thermal efficiency. Failing to properly insulate tank bases also can increase energy losses – especially when storage tanks holding hot liquids are not completely full. In these cases, the hot liquid is primarily in contact with the base of the tank and, if the base is not insulated, there is little to limit heat transfer, ensure process control or prevent the contained material from increasing in viscosity.

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tank holds toxic or flammable liquids/gases. Corrosion concerns can be mitigated by insulating, ambient and high-temperature carbon steel tanks with non-permeable, non-absorptive closed-cell insulation systems – such as those designed to include cellular glass insulation. Using cellular glass insulation, which is impervious to moisture and water vapour, helps protect the system. Installing a non-absorptive insulation also avoids risk of flammable liquids or chemicals being retained if a leak should occur.

Figure 1. Insulation systems for industrial storage tanks take design and planning.

Despite the range of difficult conditions these systems face, 100% closed-cell FOAMGLAS® cellular glass insulation is able to address the challenges and support essential design factors. Used to insulate tank bases for a range of temperatures, FOAMGLAS® High-Load-Bearing (HLB) insulation provides compressive strength to help protect tanks from unwanted settlement and thermal transfer while remaining dimensionally stable. As labour is always an important consideration, this insulation also comes in a range of larger block sizes to help with installation efficiency. Properly installed and maintained insulation can also help protect underlying supports from becoming brittle, warping or being otherwise damaged depending on the temperature of stored materials. On all parts of the system, the insulation aids in maintaining internal process/storage temperatures, reducing boil-off and limiting the potential for liquids to have undesirable changes in viscosity. Inorganic cellular glass insulation also remains impermeable to moisture vapour – helping avoid corrosion – and will not absorb water, water vapour or other liquid hydrocarbons.

Figure 2. Insulation systems in flat-bottomed storage tank bases and walls help maintain thermal performance.

Essential design factor 3: moisture and corrosion risk The physics of air and water can also pose a risk as temperature differences between the contents of low-temperature storage vessels and ambient air can prompt condensation to form on the outside edge of storage tanks. Under certain conditions, if permeable or absorptive insulating materials are used, moisture could lead to corrosion under insulation (CUI) and insulation performance could be degraded. Over time, this also may impair the mechanical strength of the tank if corrosion is allowed to progress to a critical state. Corrosion development under insulation can continue undetected until a leak occurs. A containment breach is a safety concern and may pose a particular hazard for employee safety when the materials contained are high in temperature or pressure, or if the Autumn 2021 46

A specification strategy to mitigate risk

References 1.

3. 4.

'Design and manufacture of site built, vertical, cylindrical, flat-bottomed steel tanks for the storage of refrigerated, liquefied gases with operating temperatures between 0°C and -165°C', General, British Standards Institution, (BS EN 14620-1:2006), (2006), retrieved from https://shop.bsigroup.com 'Design and manufacture of site built, vertical, cylindrical, flat-bottomed steel tanks for the storage of refrigerated, liquefied gases with operating temperatures between 0°C and -165°C', Insulation components, British Standards Institution, (BS EN 14620-4:2006), (2006), retrieved from https://shop.bsigroup.com 'Tank Systems for Refrigerated Liquefied Gas Storage', American Petroleum Institute, (API STD 625), (2018), retrieved from https://global.ihs.com/ 'Standard Test Method for Measuring Compressive Properties of Thermal Insulations', ASTM, (ASTM C165-07[2017]), (2017), retrieved from https://www.astm.org/Standards/C165.htm

Adam Wishall, Varec Inc., USA, explains how recent updates have helped to improve automation and control functionality for a major fuel farm at the Hartsfield-Jackson Atlanta International Airport.

SM Group is a North American professional services group specialising in aviation fuel. Some of the group’s key offerings include into-plane services (the refuelling or supply of fuel to an aircraft), fuel farm maintenance and operations, fuel logistics, and ground support equipment services. FSM Group has been managing the Delta Air Lines fuel farm at the Hartsfield–Jackson Atlanta International Airport in Georgia, US, since October 2020. Prior to the change in management, Delta managed its own fuel farm. Over the past few years, significant upgrades have been made across the fuel farm to replace ageing equipment, as well as to improve the electrical infrastructure and upgrade software and systems. Since 2008, Varec’s FuelsManager® suite of software applications and 8130 remote terminal unit (RTU) have been an integral component of the legacy fuel management system at the Delta fuel farm. As part of the most recent 4 47 Autumn 2021

updates, Varec provided its airport fuel control system (AFCS), which included the control cabinet and operator station, an 8810 RTU, as well as a FuelsManager software upgrade. These enhancements provided significant improvements to various automation and control functionality across the fuel farm.

Situation The fuel farm for Delta Air Lines was originally built in the 1970s, and many of the systems put in place over 40 years ago to help manage the day-to-day operations were still in place just a few years ago. The long-time general manager for the fuel farm, formerly a Delta employee and now working for FSM Group, began designing the plans for a major upgrade across the entire fuel farm nearly a decade ago. The control panel was over 40 years old, analogue, very large (7 ft x 14 ft x 3 ft), and took up too much space in the control room. The terminal manager wanted a new control panel that included a cabinet where other parts of the system could be stored in order to streamline space. He also wanted a modern programmable logic controller (PLC) because the current PLC was no longer functioning efficiently as it was an older system with outdated technology that was difficult to update and maintain. The biggest PLC issue revolved around managing pumps and valves during peak departure times that would drive a high spike in fuel demand. During these peaks – where there could be 20 or more planes on the ground being fuelled at the same time – the hydrant pump pressure would drop too low. The system would respond by turning on more pumps. However, before the entire system could recalibrate each time an additional pump was brought online, the PLC would trigger another pump to start. These premature starts would cause the pressure to rise too high. It had become a common occurrence that the pressure would reach critical high levels during these peak periods, which triggered an emergency fuel shut off (ESFO) and delayed aircraft fuelling. To try and mitigate this problem, the fuel farm operators had to spend a lot of time manually managing the pumps during peak periods. In doing so, they were spending less time performing the day-to-day maintenance checks on the tanks. There were other updates already completed, underway or still pending as a part of the large tank farm upgrade project, such as replacing the aged communication and electrical wires

and cables, updating the computers and servers, upgrading the RTU, and updating the FuelsManager software. Several vendors were involved at different stages of the project, working collaboratively on their respective areas of expertise.

Solution After several consultations with engineers on some of these issues that the facility was facing, the general manager selected Varec for multiple aspects of the fuel farm upgrade. The biggest component was deploying Varec’s AFCS. Key physical components of the system included a control cabinet that housed the PLC and the manual control panel (MCP) on the doors. The 8810 RTU, the new tank gauging interface, was also housed in the cabinet. The new PLC had advanced logic to provide better automation and control for the fuel farm’s pumps and valves. The PLC logic is the key automation component of AFCS. It was designed to operate using the first-in, first-off (FiFo) smart pump sequencing instead of the traditional lead lag method. With FiFo, run times would be better distributed across the pumps, eliminating quick starts and stops for some pumps and long run times for others. This results in a more optimal performance and reduces the wear and tear on the first few pumps in sequence. Now, as pumps are brought online to meet the fuel demand, the pump that has been running the longest will be shut off as demand decreases. Another key component of AFCS is to base the automation logic on both pressure and flow to determine when to start and stop pumps. FSM Group also selected some of Varec’s other products, which are not required for AFCS. The new tank gauging communication interface – the 8810 RTU – replaced the legacy 8130 RTU. The interface is Ethernet-enabled, uses the OPC Unified Architecture (UA) communication server, and supports up to six modules, 24 channels and 400 tanks. The existing servo gauges were replaced with NMS81 Servo Gauges. This device upgrade was not a part of the original project, but FSM Group decided to make the change during the project to eliminate performance issues and ensure long-term technology compatibility with the other enhancements. Lastly, the facility’s FuelsManager Inventory Management, Accounting and Movement Tracking modules were also upgraded as a part of the technology refresh to the latest operating systems.

Figure 1. Previous control panel, PLC, servo gauge, and 8130 RTU (left), and new control cabinet, PLC, 8810 RTU, interior wiring/cables, and NMS81 Servo Gauge (right).

Autumn 2021 48

Results Benefits of the new system were realised almost immediately. The new control panel and PLC streamlined operations. The need for manual intervention to help manage the pumps was completely eliminated. With the MCP built into the front of the cabinet, operators can easily visualise how things are running at any moment in time.

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reading each night from each gauge, and input those readings into the system. It could take up to 45 minutes per tank to complete this task. Now, standard and real-time density data captured in the NMS81 Servo Gauges automatically updates FuelsManager, freeing up operators to focus on other tasks. While FuelsManager had been installed for over a decade, the recent upgrades have refined some of the tracking, reporting, and reconciliation processes. Through the standard reports available, operators can effectively manage inventory levels to understand gross and net, track and Figure 2. The Delta Air Lines fuel farm at the Hartsfield–Jackson Atlanta reconcile gains and losses, and manage days International Airport. of supply, a critical metric to know at all times. At a glance, they can see outgoing system pressure and flow, The facility also tracks and records which tank(s) are actively receiving from the pipeline, which movements with FuelsManager. This feature is used as an tank(s) are issuing to an aircraft, and the number of pumps additional check and balance within the system. Movements currently running. In the past, this visualisation was only are tracked from the pipeline into the tanks and out of the available at computer work stations in the control room. tanks through each allocation transaction. With the standard Operators can also individually route control of each device to pipeline report, they know when each valve was opened, the automated system or easily control them manually from the which tank the fuel went into, and the start and stop times for panel, providing an operations backup control and monitoring each transaction. They are also able to compare what the workstation. MCP also serves as an automation system back up pipeline says was sent to what was actually received to if the primary control station software or the PLC were to stop determine if there are variances. Since all of the upgrades have working. been in place, there have not been any variances outside of The new servo gauges helped eliminate another manual tolerance. Fuel receipts and disbursements are extremely process. Previously, operators would manually take a density accurate, even down to the into-plane services.

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François Negroni, ALMA Group, outlines the benefits of using a standardised vapour recovery unit to handle emissions.

vapour recovery unit (VRU) is an engineered industrial system dedicated to downstream petroleum storage and transfer activities. Before loading new hydrocarbons, trucks need to unload volatile organic compounds (VOCs) out of the tank. A VRU is the only clean solution to handle VOC emissions generated during day-to-day operations. Alternative options are to release directly into the atmosphere via a vent or to burn the system via a flare

advanced stack, both of which are not environmentally friendly. However, VRUs are a highly-specialised field that require specified knowledge. Poor maintenance of a unit can lead to emission problems, safety complications, operational problems and financial inefficiencies. The capture and recovery of hydrocarbon vapours to reduce emissions of environmentally hazardous VOCs is a vital concern in modern oil and gas production and

51 Autumn 2021 5

Emission limit requirements Emission limit requirements (ELRs) include the following: 94/63/EC directive, the US Environmental Protection Agency’s (EPA) ‘Clean Air Act’, TA-Luft 01 in Germany, LRV in Switzerland (Air Pollution Control Ordinance [LVR00 App 2]) and NER in the Netherlands (the Netherlands Emission Guidelines for Air). VRUs must be regulatory tested to demonstrate that the amount of hydrocarbons emitted into the atmosphere is below the limit. As such, VRU projects can be designed for classical ELRs such as 35 g hydrocarbon/m3 or 10 g hydrocarbon/m3, as well as more stringent conditions such as 150 mg hydrocarbon/m3, and even 50 mg hydrocarbon/m3.

Figure 1. A customised VRU based on

The goal of a standardised unit

transformation. Increasingly more countries are adopting regulations to force oil and gas businesses to set up VRUs systematically for three main reasons: Environmental considerations, such as air pollution, VOC control, and impact on the health of humans and animals. Safety considerations, such as reducing the risk inherent to working in hazardous environments. Economic considerations, such as the loss of valuable products.

The aim of a standardised unit is to propose reliable, simple, optimised systems for the treatment of hydrocarbon vapours in depots. This is based on the well-known pressure swing adsorption/absorption process, described previously. The new unit will respect industrial standards and norms such as: 97/23/EC – ‘EU Pressure Equipment Directive’ (PED). 2006/42/EC – ‘EU Machinery Directive’. 2014/35/EC – ‘EU Low Voltage Directive’. 94/9/EC – ‘EU Directive Explosion Protection Guidelines’ (ATEX). 99/92/EC – ‘EU Directive for improving the safety and health protection of workers potentially at risk from explosive atmospheres’. 2004/108/EC – ‘EU Electromagnetic Compatibility Directive’.

client-specifications (three aromatic units) in Saudi Arabia.

VRU process flow The VRU process consists of three steps: Adsorption: hydrocarbons contained in the vapours are absorbed on activated carbon stored in large recovery units, once they are sent from the vehicle tank. Desorption: regeneration of carbon through the removal of hydrocarbons by means of vacuum. Absorption: hydrocarbons are re-absorbed in a liquid petroleum product (referred to as ‘absorbent product’) that is available on site. The absorbent is taken from one of the site storage tanks and then sent back together with the recovered product. Vapour concentrations in hydrocarbons are influenced by the following: The type of products loaded (gasoline, diesel, etc.) and their chemical characteristics as Reid vapour pressure (RVP)/True vapour pressure (TVP). Site conditions, such as temperature and pressure. The type of loading operations (e.g. marine, railcar, truck, etc.). The recovery configuration at gas stations (top or bottom truck applications). Concentrations may vary between 0 – 60 vol% (average mole weight is 65 g for standard gasolines). The aim is to find the optimum ratio between the emission limit, recovery rate and energy consumption, without falling into an ecological issue (a lot of energy is consumed for a low recovery result, leading to a positive carbon footprint). Autumn 2021 52

Standardised units include a programmable logic controller (PLC). To reinforce the PLC, VRUs from Carbovac (ALMA Group) respect a strict internal safety policy: Explosion shock proof design. General monitoring by a SIL3 Safety Relay. Vacuum systems based on dry screw vacuum pumps. Absorbent circulation pumps for supply and return, sealless with leakage. Double valves in absorbent lines to prevent leaks. Double monitoring on critical temperatures. Flame arrestor at the inlet of vapour line. The vacuum system based on a dry screw vacuum pump has the best carbon footprint (compared to liquid ring technology) and minimum total cost of ownership (CAPEX + OPEX + waste cost) compared to rotary van technology.

Size design of different units Generally, VRUs are designed according to the expected vapour profile that they have to treat. This profile depends on the terminal activity and the loading process, as stated before. Unfortunately, the loading process is not the same from one country to another. Some countries are still using top-loading gantries, while others are using multi-product bottom loading gantries. The trucks are either mono-products or multi-products with several

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Thirdly, a large unit is used to handle the vapours from four multi-product loading gantries. The installed vacuum pump is a medium vacuum flow capacity and the vapour line connection size is 8 in. Fnally, an XL unit is used to handle the vapours from eight multi-product loading gantries. The installed vacuum pump is a high vacuum flow capacity and the vapour line connection is 10 in. Standardised units are suitable for medium and high concentrated hydrocarbon containing gaseous effluents. The systems are initially designed for a level emission of 10 g/m3, but in most cases the units are able to reach very low concentrations of hydrocarbons and solvents by reducing the amount of inlet vapours or by switching to the next size of unit.

Figure 2. A 12 500 m3 XL unit in Western Europe, with

Automation

Figure 3. Standard VRU in Eastern Europe.

A VRU is fully automated, controlled through a PLC and monitored through supervisory control and data acquisition (SCADA) supervision. It starts and stops based on the loading process at the filling station, and uses a saving software to reduce the energy consumption and the running time of the unit. In this respect, a typical feature of Carbovac technology is that its energy consumption is low, whilst maintaining a high operational flexibility in respect of variable throughput, concentrations and range of products. For example, for typical gasoline vapours with 40% hydrocarbon concentration (1200 g hydrocarbon/m3), the energy consumption will be approximately 0.1 kWh/m3 of treated vapours. The Carbovac PLC configuration principle includes one main process PLC as well as a secondary watchdog PLC, which guarantees redundancy in all shut down functions. All rotating equipment is also frequency controlled to optimise the rotating speed and the life of the equipment and its energy consumption

maximum 150 mg hydrocarbon emission per m3.

Installation and maintenance compartments, and the requested emission is also different from one country to another. All of these parameters have an influence on the quantity of the carbon and the size of the vacuum system that has to be designed for the units. Based on these facts, the best compromise is to design four different sizes based on the quantity of loading gantries connected to the vapour treatment system. The following example illustrates the options with a dry screw vacuum pump: Firstly, a small unit is used to handle the vapours from a multi-product loading gantry. The installed vacuum pump is a low vacuum flow capacity and the vapour line connection size is 4 in. In certain cases, depending on the loading process, this unit can be also suitable for two gantries. Secondly, a medium unit is used to handle the vapours from two multi-product loading gantries. The installed vacuum pump is also a low vacuum flow capacity and the vapour line connection size is 6 in. Autumn 2021 54

By employing a standardised unit solution, on-site work is reduced. The mechanical installation and commissioning can be completed within two weeks by a reduced installation team. For both environmental and economic reasons, it is essential that vapour recovery equipment is maintained at its optimum performance. Process equipment requires regular attention to ensure levels, temperatures and flow rates are within normal ranges and the plant is working correctly. Spare parts should be available in stock and easily accessible to reduce shut down of the installation.

Conclusion The intention of using a standardised unit is to find the optimal solution with regards to cost efficiency and environmental impact. The recovery of VOCs is a pressing issue for all parties concerned. An operator’s impact on the environment is under scrutiny. By capturing VOCs effectively, operators are able to reduce their environmental impact and create a leaner process by reducing product losses.

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Tanks and Terminals Autumn 2021

Articles inside

Upping the standard

The sky’s the limit

Essential design factors

The road to 2050

Increasing availability

An eye on Asia

Singapore success

Steps to overfi ll prevention

A critical link

Floating roof inspections: an inside job

Smooth operator