Hydrocarbon Engineering June Issue 2022 by PalladianPublications

June 2022

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CONTENTS June 2022 Volume 27 Number 06 ISSN 1468-9340

03 Comment

39 Getting fired up

05 World news 08 Crisis? What crisis? Alan Gelder, Wood Mackenzie, UK, discusses the key attributes of successful future refineries as the oil and gas sector recovers from the COVID-19 pandemic.

15 Yielding efficient operations Michael Gaura, AMETEK Process Instruments, USA, details the importance of an air demand analyser (ADA) in the quest to manage sulfur recovery units (SRUs) more tightly.

19 From data to optimised performance Philippe Herve, SparkCognition, USA, presents various artificial intelligence applications in the downstream oil and gas sector.

22 Staying ahead of the game Kjell Wold, John Bromley-Barratt and Gaya Somasundaram, Emerson, explain how to identify pipe replacement needs using digital remote corrosion monitoring.

27 Keeping an eye on corrosion Bruce Pellegrino, Sensor Networks Inc., USA, explains how to improve corrosion monitoring yield advancements in ultrasonic technology applications.

31 Oil and gas safety takes flight Zacc Dukowitz, Flyability, USA, details how drones are helping to improve safety at oil refineries.

35 A new look at inspection Kieran Boyd, Avestec, Canada, discusses the use of a non-destructive testing inspection method to monitor equipment at a refinery.

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Stuart Bradbury and Doug Sinitiere, Carboline Global Inc., delve into the grudge purchase mindset and optimisation opportunities for passive fire protection products or systems used to mitigate the thermal effects of fire in the downstream sector.

43 Safety in a flash Michael Jones, Watlow, USA, explains the value of arc flash management of large electric process heaters in order to minimise the risks of fire and/or injury.

48 Pattern vs performance Salem Bouhairie and Syed Haq, Heat Transfer Research Inc., discuss how airflow patterns within air-cooled heat exchangers (ACHEs) degrade performance.

53 Batteries: a stepping stone to green heat technology Ilan Toledano, Wattco, Canada, outlines how batteries are fuelling the evolution of industrial heat technology.

55 The show must go on

Salim Akçaoğlu, Gökhan Özkan and Yavuz Bingöl, Tüpraş, Turkey, discuss how the company managed a battery shutdown under the challenging circumstances of the COVID-19 pandemic.

61 Metals matter Brad Cook, Sabin Metal, USA, examines what is happening within the world of platinum group metals (PGMs), and explains the importance of responsible recycling.

65 Catalyst Q&A

Hydrocarbon Engineering talks to a number of leading experts in catalyst technology about a range of topics.

At the forefront of innovation in processing technology, Sulzer Chemtech is here to drive your success. With advanced solutions, extensive expertise, and customer-oriented strategies, the company can help you to meet current and future trends, market demands, and diversified supply.

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COMMENT CALLUM O'REILLY SENIOR EDITOR

arlier this year, I had the pleasure of sitting down with Alan Gelder, Vice President of Refining, Chemicals and Oil Markets at Wood Mackenzie, for an episode of the Palladian Energy Podcast. For the uninitiated, the Palladian Energy Podcast is a new podcast series for oil and gas professionals brought to you by Hydrocarbon Engineering, along with our sister publications Oilfield Technology, World Pipelines, and LNG Industry. Series one covers the topic of digitalisation in the oil and gas industry, and it was great to get Alan’s thoughts on the important role that digitalisation will play in the downstream sector, specifically. We also took the opportunity to pick Alan’s brain on a number of other topics, including the broader outlook for the global refining sector in the year ahead, and the long-term trends for the industry. I’d encourage all of our readers to go ahead and give the episode a listen, if you haven’t done so already. You can subscribe to the Palladian Energy Podcast for free wherever you usually get your podcasts. Our chat with Alan took place just before Russia’s invasion of Ukraine, and although this crisis was foreseen in our conversation, it’s fair to say that the global landscape has shifted dramatically since we last spoke. As such, I’m pleased to report that Alan has also provided the keynote article for this issue of Hydrocarbon Engineering, which starts on p. 8. As well as briefly touching upon the geopolitical crisis that the Russia/Ukraine conflict has created, Alan’s article looks at how the sector has recovered from the COVID-19 pandemic, and the future opportunities for the refining industry in the face of the energy transition. This issue of Hydrocarbon Engineering also includes articles on the application of artificial intelligence (AI) in the downstream oil and gas sector (p. 19), methods to improve corrosion monitoring (pp. 22 – 30), the use of drones to revolutionise plant safety during inspections (pp. 31 – 38), and optimisation opportunities for passive fire protection products (p. 39). Amongst other topics, this issue also features an informative piece from Sabin Metal Corp. on the importance of responsible recycling of platinum group metals (p. 61), and a special Q&A session with a number of leading experts in catalyst technology and services (p. 65). We also have a detailed article from AMETEK Process Instruments looking at the role of air demand analysers in the quest to manage sulfur recovery units more tightly. And on the topic of sulfur, I’d like to remind you all that our second annual SulfurCon virtual conference is taking place on 29 June 2022. We have an excellent line-up of expert speakers from ICIS, Comprimo, Merichem, Howden, and Malvern Panalytical, who will be providing detailed presentations, case studies and product demonstrations on a range of topics including gas treating, small-scale sulfur recovery for renewable fuels technology, sulfur recovery for the energy transition, and low-level sulfur analysis in automotive fuels. To ensure that you don’t miss out on these insightful presentations and live Q&A sessions, as well as a host of networking opportunities including a virtual exhibition, sign up for your free space at SulfurCon here: www.hydrocarbonengineering.com/sulfurcon2022. And if you’re not able to join us live for SulfurCon on 29 June, that’s no problem at all. Sign up to attend, and we’ll be sure to send you an email with links to download each of the presentations, so you can watch them at a time that suits you.

We make chemistry happen Sulzer Chemtech is global market leader in reaction, separation, purification, static mixing as well as polymer processing technologies. With a comprehensive offering that includes process components all the way to complete process plants and technology licensing, we can serve a broad range of industries with key solutions to intensify processes, increase efficiency and improve product quality. With an ever-expanding portfolio of cutting-edge products that supports circularity while reducing material and energy use as well as emissions, we are the ideal partner to support the net zero transition of businesses across the chemical and polymer value chains. We also offer our technology innovations to support the sustainable manufacturing of bio-plastics, renewable fuels, chemical recycling for unrecyclable materials as well as carbon capture technologies.

WORLD NEWS Thailand | Aramco

and PTT sign MoU

audi Arabian Oil Co. (Aramco) is exploring further collaboration with Thailand’s national oil company, PTT, as it expands its downstream presence in Asia. The two companies signed a Memorandum of Understanding (MoU) at a ceremony in Bangkok, Thailand, on 11 May 2022. The companies are aiming to strengthen cooperation across crude oil sourcing and the marketing of both refining and petrochemical products, and LNG. Other potential areas of activity include blue and green

hydrogen, and various clean energy initiatives. Disathat Panyarachun, PTT Senior Executive Vice President, International Trading Business Unit, said: “PTT and Aramco have built strong ties around the supply and trading of crude oil and other products. Extending our collaboration across the value chain to include emerging decarbonisation initiatives is a great opportunity to strengthen our relationship and foster further business growth. This also aligns with our ‘green and clean’ strategy.”

Worldwide | Rio Tinto and BP to trial marine

biofuels

io Tinto and BP have agreed to work together on a one year biofuel trial to help reduce carbon emissions from Rio Tinto’s marine fleet. Under the trial, BP is supplying Rio Tinto with marine biofuel for approximately 12 months. The fuel will be trialled on Rio Tinto’s RTM Tasman vessel, in one of the longest-duration marine biofuel trials to date. The results of the trial will help Rio Tinto to study ways to reduce carbon emissions from its marine fleet, and inform its future biofuel strategy.

The trial is using a BP-manufactured B30 biofuel blend composed of 30% fatty acid methyl esters (FAME) blended with very-low-sulfur fuel oil (VLSFO). This B30 biofuel blend can reduce life cycle carbon dioxide (CO2) emissions by up to 26% compared to standard marine fuel oil. The extended trial agreement follows a successful journey on the RTM Tasman after it refuelled with biofuel in Rotterdam, the Netherlands, in March 2022.

Asia | Crude

distillation unit capacity additions continue to rise

ccording to GlobalData, Asia is expected to witness the most crude distillation unit (CDU) capacity additions globally, contributing approximately 47% of the total CDU capacity additions by 2026. The region is likely to witness a total CDU capacity addition of 7.1 million bpd by 2026. Of this, new-build capacity would be 4.3 million bpd, while the rest would come from the expansion of existing refineries. Teja Pappoppula, Oil and Gas Analyst at GlobalData, comments: “China and India primarily drive refinery CDU capacity additions in Asia by 2026. Yulong and Jieyang, both in China, are the largest upcoming new-build projects in Asia during the 2022 – 2026 outlook period, each with a capacity of 400 000 bpd. Among the expansion projects, Vadinar in India is expected to witness the highest capacity additions of 515 000 bpd by 2026.” GlobalData suggests that Africa will be the second highest contributor, with the Middle East ranking third globally.

USA | TotalEnergies and New Hope Energy partner on advanced

recycling project

otalEnergies and New Hope Energy have announced a commercial agreement under which New Hope Energy will build an advanced recycling plant in Texas, US, to transform end-of-life plastic waste into a recycled feedstock that TotalEnergies will partly purchase and convert into virgin-quality polymers,

which can be used for food-grade packaging. The New Hope Energy plant is expected to start production in 2025, and will use a patented pyrolysis technology that was developed in partnership with Lummus Technology to process and convert more than 310 000 tpy of mixed plastic waste that

would otherwise be destined for landfill or incineration. TotalEnergies will use 100 000 t of recycled polymer feedstock (RPF) in its production units to manufacture high-quality polymers suitable for food-grade applications such as flexible and rigid food packaging containers.

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June 2022

WORLD NEWS DIARY DATES

UAE | TA’ZIZ

07 - 09 June 2022

Shaheen

and Reliance partner up with

29 June 2022

bu Dhabi Chemicals Derivatives Company RSC Ltd (TA’ZIZ) has announced that Shaheen Chem Holdings Investment LLC (Shaheen) will join the proposed TA’ZIZ ethylene dichloride (EDC) and polyvinyl chloride (PVC) joint venture (JV), aimed at the construction and operation of a world-scale chlor-alkali, EDC, and PVC facility, at the TA’ZIZ Industrial Chemicals Zone, in Ruwais, Abu Dhabi, UAE. With an investment of more than US$2 billion (AED 7.34 billion), the project will provide new opportunities for local manufacturers, supporting the

SulfurCon 2022 Virtual Conference www.hydrocarbonengineering.com/sulfurcon2022

USA | Phillips

Global Energy Show Calgary, Alberta, Canada www.globalenergyshow.com

08 - 09 June 2022 Downstream USA 2022 Houston, Texas, USA www.reutersevents.com/events/downstream

13 - 15 June 2022 ILTA International Operating Conference & Trade Show Houston, Texas, USA www.ilta.org

22 - 26 August 2022 ACHEMA Frankfurt, Germany www.achema.de

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

11 - 14 September 2022 GPA Midstream Convention San Antonio, Texas, USA https://gpamidstreamconvention.org

13 - 15 September 2022

growth of their knowledge and capabilities, and catalysing local industrial development. The chemicals to be produced by the project have a wide range of industrial applications and will create opportunities for export, as well as providing local industry with a source of critical raw materials manufactured in the UAE for the first time. Investment in the production of chemicals is a priority for the UAE’s industrial growth strategy, championed by the Ministry of Industry and Advanced Technology.

66 to convert San Francisco refinery to renewable fuels facility

hillips 66 has made a Final Investment Decision (FID) to move forward with Rodeo Renewed, the project to convert its San Francisco refinery in Rodeo, California, US, into one of the world’s largest renewable fuels facilities. The project, which recently received approval from Contra Costa County, is expected to cost approximately US$850 million and begin commercial operations in 1Q24.

Upon completion, the converted facility will no longer process crude oil and will instead use waste oils, fats, greases and vegetable oils to produce an initial 800 million gal./yr of renewable transportation fuels, including renewable diesel, renewable gasoline, and sustainable aviation fuel (SAF). Production of these fuels is projected to reduce life cycle carbon emissions by approximately 65%.

Turbomachinery & Pump Symposia Houston, Texas, USA tps.tamu.edu

Group receives first delivery of LNG for the Klaipeda terminal

18 - 20 October 2022

2022 AFPM Summit San Antonio, Texas, USA www.afpm.org/events

24 - 26 October 2022 Sulphur + Sulphuric Acid Conference & Exhibition The Hague, The Netherlands www.events.crugroup.com/sulphur/home

24 - 26 October 2022 8th Opportunity Crudes Conference Houston, Texas, USA www.opportunitycrudes.com

June 2022

HYDROCARBON

ENGINEERING

Lithuania | PGNiG

he PGNiG Group recently received its first cargo of LNG to be delivered to the LNG terminal in Klaipeda, Lithuania. The delivery of almost 65 000 t of LNG from the US is a step towards further integration of gas markets in this part of Europe, strengthening the region’s energy security. The gas came from a liquefaction plant in Freeport, Texas, US. The LNG terminal, operated by KN (Klaipedos Nafta, AB), is one of the key elements of Lithuania’s energy

infrastructure. Its launch in 2014 paved the way for the emergence of a natural gas market in the country, diversification of gas supply sources, and improvement of energy security in the area. Gas from the first cargo received by the PGNiG Group in Klaipeda will be supplied not only to the Polish market, but also to the Baltic states. Elenger, one of the major energy companies in the Finnish-Baltic region, has bought part of the LNG delivery for its customers.

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Ideal

2,5

Manageable

Challenging

Transportation Fuels Light Olefins PE, PP Vegetable Oils Biomass Crude Oil

1,5 1

Deoxygenation Required

0,5 0 0

0,1

0,2

0,3

0,4

0,5

Oxygen to Carbon

0,6

0,7

0,8

June 2022

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Alan Gelder, Wood Mackenzie, UK, discusses the key attributes of successful future refineries as the oil and gas sector recovers from the COVID-19 pandemic.

he global refining sector is currently enjoying a post pandemic recovery boom, with its March 2022 composite monthly margin at record highs. This is a very different situation from the depths of the global pandemic, which was only two years ago. Wood Mackenzie’s Refinery Evaluation Model indicates that few refiners in Europe were cash positive in 2020. Other regions experienced similar challenges, triggering the rationalisation of almost 3 million bpd of refining capacity. Since then, oil demand has recovered strongly, and it is expected that 2019 levels will be breached during 2023. In the meantime, global distillate inventories have fallen to record lows, lifting diesel crack spreads and the global composite refining margin to unprecedented levels, as shown in Figure 1. The existential threat to the viability of the refining sector presented by the global pandemic now seems a distant memory, with the sector apparently in rude health (in gross margin terms). However, the picture is not quite as rosy as it seems, as the surge in profitability has not been shared by all. European refiners are dealing with very high costs for natural gas and carbon emissions, and are operating at lower crude throughputs than expected for the prevailing gross margins as a result. In addition to this, China’s exports are being constrained by lower quotas, and the oil market is concerned about the potential future loss of supply of Russian crude and diesel to international markets because of the Russia/Ukraine conflict.

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June 2022

Russia/Ukraine conflict represents a geopolitical crisis

for the price shock that was – and continues to be – experienced in 1Q22 – 2Q22. Crude oil prices rose further from late Russia’s invasion of Ukraine reminds us that the refining February 2022, when Russia invaded Ukraine, as the oil sector must adapt to changes in primary energy market focused on the potential loss of supply from sources such as oil and natural gas. Global oil and the world’s second largest producer of crude and European natural gas prices were already rising prior to condensate. Several companies announced their exit the conflict, and European refiners had to adapt to from Russia and ‘self-sanctioned’ against the future natural gas feedstock being more costly than many of purchase of Russian energy, in addition to import bans its products on an energy equivalent basis. This from a few advanced economy countries. This has resulted in constrained European crude processing and resulted in ‘crude swapping’, as shown in Figure 2, as a shift to lighter, sweeter crudes, such as Urals needs to clear to Asia to find buyers at a price West Texas Intermediate (WTI). Global distillate that is highly attractive, as many logistical, financial and inventories continued to fall, setting up the conditions political challenges remain. At the onset of the conflict, refining margins fell as product prices did not rise as quickly as crude. However, margins then strengthened as the oil market focus shifted to fears of a European diesel shortage, strengthening distillate crack spreads to record levels. Crack spreads for products not in tight supply eased. This highlights that refining is secondary to global crude oil market events – only refined products in tight supply can quickly pass on crude price increases along the value chain. Refiners need to continuously adapt to changes in the landscape of primary energy supply and use. The lesson emerging from the conflict for many regulators is to accelerate the energy transition by the faster adoption of locally-sourced Figure 1. Wood Mackenzie global refining composite margin (US$/bbl) renewables, in order to improve (source: Wood Mackenzie). resilience and security of supply.

Figure 2. Russian crude trade flow changes between advanced and developing economies for 2022 (source: Wood Mackenzie).

June 2022 10 HYDROCARBON ENGINEERING

POWERING SMARTER WAYS

In a fast changing world shaped by increasing complexity and connectivity, Axens Group, building on the commitment and the diversity of its teams, fosters innovation and collaboration to creFind out more ate added value for its clients. www.axens.net

Resilience in the face of the energy transition The energy transition is the critical mega-trend for the refining sector, as it involves decoupling the growing need for energy and mobility from the demand for fossil-based hydrocarbons. The energy transition is establishing how we achieve a pathway to net zero greenhouse gas emissions to avoid potentially catastrophic climate change. For the refining sector, the key pillars of the energy transition are: n n Electrification of demand, enabling the use of electricity generated from renewable sources.

n n Lowering the carbon intensity of liquids used in ‘hard to electrify’ sectors. n n Reduction of refinery emissions associated with the transformation of feedstocks into products.

Wood Mackenzie’s ‘Energy Transition Outlook’ is its base case view across all commodity and technology business units, so incorporates the evolution of current policies and technology advancement playing out in the future to 2050. It is broadly consistent with a 2.5˚C global warming view. Led by the electrification of the passenger car segment and fuel efficiency gains, global oil demand for energy use peaks within this decade, whilst non-energy use (primarily petrochemicals) continues to grow, as shown in Figure 3. The key future opportunities for the refining sector are petrochemicals and liquid renewables, with a future pathway to synthetic/e-fuels, and low-carbon petrochemicals. 2020 has demonstrated the commercial significance of petrochemicals, as only one ‘fuels only’ refinery in Europe achieved a positive net cash margin (NCM – defined as gross margin minus fixed and variable costs), compared to 17 integrated refinery/petrochemical sites (leaving almost three-quarters of European operational sites at a negative NCM). The added value from petrochemicals depends upon the site’s location, petrochemical yield (as a percentage of overall Figure 3. Energy use of fossil-based oil reaches a peak by 2027 products), and the value chain of (source: Wood Mackenzie). the chemical, as shown in Figure 4.

Figure 4. Global NCM Uplift (US$/bbl) vs wt% petrochemicals, split by region (source: Wood Mackenzie).

June 2022 12 HYDROCARBON ENGINEERING

Figure 5. Carbon mitigation techniques for refiners (source: Wood Mackenzie). Clearly, higher values are achieved through greater petrochemical yields. Unless FCC refiners can shift to materially-higher olefin yield, hydrocracking configurations are better placed to adapt to an energy transition that is led by the passenger car segment. These integrated sites benefit from attractive commercial performance and are competitively strong as a result. They are also well-positioned for the future growth in the significance of petrochemicals as a source of oil demand, with their positive cash flow enabling them to invest in the growing circularity of petrochemicals and the decarbonisation of their other liquid products. The production of low-carbon liquids is a major opportunity for the refining sector, as such liquid biofuels can address the ‘hard to electrify’ sectors of aviation and heavy-duty commercial trucking. There are product quality specifications that limit the use of ethanol in gasoline, and FAME (biodiesel) in diesel/gas oil. This has led to the greater need for hydrogenated vegetable oils (HVO), or renewable diesels, to comply with the requirements to increase the renewable content of transport fuels (primarily in Europe and the US – particularly in California, with its low-carbon fuels standard). Existing refineries are well-positioned to produce such renewable diesels from vegetable oils as these feedstocks can be co-processed within existing hydrotreaters after initial pre-treatment. Sustainable aviation fuels (SAFs) is an increasing area of focus for both regulators and airlines, to support the decarbonisation of air travel. The production process is, again, very similar to the production of jet fuel via hydroprocessing, so offers an exciting growth opportunity for refiners. SAF production typically produces some bio-naphtha as a byproduct, which can be an attractive feedstock to support the

decarbonisation of the petrochemical sector. These low-carbon liquid fuels require the availability of both low-carbon hydrogen and appropriate feedstocks. With declining costs for green hydrogen, the availability of low-carbon feedstocks becomes increasingly critical. Here, the refining industry needs to be innovative and collaborative to both secure access to sustainable agricultural residues and waste streams (municipal, petrochemicals, etc), and then develop and deploy the technology to convert these feedstocks into liquids. Refiners will remain in the business of transformation, but the feedstocks to be transformed must be increasingly part of the circular economy. Refiners also need to address their own emissions, as they represent around 3% of the global total. Asia is the dominant source of these refinery Scope 1 and 2 emissions, as it is the region with the largest refining capacity, and tends to use more heavy liquids and coal for its internal fuel. Around 80% of the emissions are associated with the key refinery processes of combustion for chemical transformation and separation, with less than 5% associated with the production of hydrogen by steam reforming. There are a variety of carbon mitigation techniques, as shown in Figure 5. For deep decarbonisation, refiners will have to adopt new technologies such as carbon sequestration, utilisation and storage (CCUS), green hydrogen, and renewable power, the commercial viability of which is highly dependent upon government policies, costs of carbon emissions, and technology development. Refiners need to have a clear understanding of the emissions profile of an operational site and be prepared to partner with others to successfully develop and deliver the necessary reductions. Regulations and the establishment of a price for carbon emissions can play a

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role in supporting these necessary investments. Refiners, however, must acknowledge that carbon policies are unlikely to provide a level playing field, but they need to adapt to retain their social licence to operate. For regulators, the challenge of an uneven playing field is that it accelerates refinery rationalisation, which has adverse consequences for energy security resilience, as highlighted by the current Russia/Ukraine conflict. Close ties with regulators, governments, and the broader stakeholder community will become increasingly important in order to minimise the risk of unfair competition and subsequent carbon leakage, along with the delivery of a just energy transition.

Key attributes of successful future refineries The energy transition requires refiners to adapt – business as usual is no longer an option. Being a highly-competitive, cash positive site is necessary, but may no longer be sufficient to ensure long-term viability. A cash positive position is advantageous to addressing the potential additional costs of carbon emissions. However, for those sites that are competitively strong, the requirement is to deliver low-carbon operations through: n n Low-cost operations and improved optimisation through digitalisation.

n n Fuel efficiency improvements and process electrification. n n CCS on large emissions sources, such as FCCs, gasifiers, and hydrogen production units, via partnerships with logistics and upstream operators. n n Green hydrogen. These advantaged sites can be a platform to produce lower-carbon-intensity fuels, such as liquid biofuels and ultimately synthetic e-fuels (which combine captured CO 2 and low-carbon hydrogen) that regulators desperately seek. Given the uncertainty around the size, scale and nature of these investments, it is expected that companies will focus their energy transition investments on those sites that have high NCM and low emissions intensity, which are typically highly-integrated refinery/petrochemical sites located in industrial clusters, supported by a broader network of small bio- and pyrolysis sites (as the economies of scale of moving and processing agricultural residues and wastes are very different from crude oil). The refining business is about to embark on another major transformation – this time, it is to transform itself to supply low-carbon fuels in a circular economy, where both site and fuel emissions will join a site’s competitive position as critical determinants of its future success.

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Michael Gaura, AMETEK Process Instruments, USA, details the importance of an air demand analyser (ADA) in the quest to manage sulfur recovery units (SRUs) more tightly.

ith the global economy recovering from the devastating impact of COVID-19 and the restrictions that were put into effect to reduce its spread, energy suppliers are aggressively working to meet deliverable volumes that have not been seen in the past two years. Coupled with the significant change in workforce that many hydrocarbon suppliers and processors have also experienced, as well as the continued push to decrease the amount of sulfur emitted at the plant or end product level, there has been a renewed effort to automate and optimise sulfur recovery unit (SRU) operations. One point within SRU operations that has specifically been receiving more focus is the inlet or feed point. Engineers and consultants are targeting the most efficient and proven method of obtaining detailed and real-time compositional data from the sour water stripper and acid gas as it enters the SRU. It is worth recalling that the purpose of the SRU is to remove as much sulfur from incoming gas streams (feed gas) as

possible, as environmental agencies want to limit the amount of sulfur emitted locally (plant level) and globally (at the point of fuel combustion). Typically, the sulfur entering the SRU is present as hydrogen sulfide (H2S) – a compound that is lethal to human life at very low concentrations (500 ppm). The H2S is present in the sour water stripper (refinery) or acid gas (refineries and natural gas processing plants), as it has been previously scrubbed or removed from the more financially-valuable or desired hydrocarbon streams. The H2S, or any other sulfur compounds that enter the SRU, are converted and removed through reactions in the SRU plant. The most common method of removing > 90% of the sulfur is through the modified Claus process. The most common modified Claus processes currently utilised in the recovery of elemental sulfur (Sx) are based on systems that were described in detail 75 – 140 years ago. Many improvements and modifications have been integrated over this time, but the sulfur removal process HYDROCARBON 15

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essentially follows the formula detailed below, as illustrated in Figure 1 (note: the number of converters and condensers can vary by plant and licensor). 3H2S + 3/2O2 –> SO2 + 2H2S + H2O SO2 + 2H2S –> 3/x Sx + 2H2O

Heat Catalyst

The feed gas enters the SRU containing a high level of H2S and moves through the reaction furnace where fuel and either ‘air’ or oxygen are designed to react at a temperature of at least 925°C. This temperature, and the intentional introduction of sub-stoichiometric oxygen (O2), results in approximately one-third of the incoming H2S being converted to sulfur dioxide (SO2). This conversion sets up a typical 2:1 ratio of H2S:SO2 that is required for desired elemental sulfur removal in the rest of the SRU. Ideally, this ratio is maintained even as the process gas stream moves through the converters and condensers, which are heating and cooling the gas stream, and subjecting the process gas to catalysts that are intended to remove elemental sulfur. The elemental sulfur ultimately ends up in a storage tank or (once very common, now not so much) pit. At this point, it is important to take note of some items that many papers and presentations have addressed in the past: nn After the final condenser, there is an air demand or tail gas analyser (ADA/TGA) installed on almost every SRU. nn If the ratio of H2S to SO2 is not 2:1, the SRU operator or process control system adjusts air flow to the reaction furnace to obtain this ratio. When the ratio is less than 2:1, the amount of O2 or air is often reduced at the reaction furnace. When the ratio is greater than 2:1, the amount of O2 or air is increased at the reaction furnace. nn A 2:1 ratio of H2S:SO2 is not always required or desired. Every plant and licensor is going to find an ideal ratio for optimal recovery efficiency through the Claus process. It is important to keep this in mind when evaluating the overall SRU operation.

Figure 1. A typical SRU Claus system.

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nn The removal and/or conversion of H2S does not typically end at the last condenser in an SRU. The ADA can read ppm to % levels of H2S and SO2, often indicating that recovery efficiencies of sulfur are less than required. This is why tail gas treating units (TGTUs) are added to many SRUs. nn The feed gas is never 100% H2S. The feed gas at the SRU is a combination of many gas streams that have been involved in removing undesirable components from more valuable process or product streams within a process plant or refinery. See Table 1. A typical refinery sour water stripper gas stream will often contain concentrations of > 50% H2S, but ammonia (NH3) levels can also be 30 or 40%. Acid gas streams in natural gas plants can have nearly equal levels of H2S and carbon dioxide (CO2), 40 – 60%, as both are removed in upstream amine plant systems. Hydrocarbons can also be present at elevated and undesired levels when an upstream process upset occurs. Table 1 can be used as an approximate guide for SRU feed gas components and concentrations. To summarise, we know that the purpose of the SRU is to remove as much of the delivered sulfur as possible from the incoming process gas stream (feed gas). We also know that there is a plant specific ratio of H2S and SO2 that should be maintained, for optimal sulfur recovery. Finally, we know that an ADA measures the concentration of H2S and SO2 at the Claus outlet, and can be used to adjust the air/O2 feed at the reaction furnace if the ratio of H2S:SO2 is not as required. However, there remains a need for additional process gas analysers. By only measuring gas composition at the outlet of the Claus unit, users are missing out on the single biggest opportunity to operate their plant more efficiently and with more uptime. Adding a process gas analyser that monitors the concentration of key incoming components in the feed gas should be a priority for all SRU operation and design engineers.

Quicker identification of upsets An ADA is located downstream of the reaction furnace, as well as the converters and condensers. This ADA measurement

Sulfur recovery unit workers have a lot to worry about. Analyzers shouldn’t be one of them. Managing all the processes in a sulfur recovery unit (SRU) is arduous work—demanding skill, concentration, and dedication through every shift. Fortunately, the reliability, accuracy, robust design, and operating ease of AMETEK analyzers can make that tough work a little easier. AMETEK engineers have been designing industry-standard SRU analyzers for decades, and that shows in the products’ accuracy, reliability, and longevity. Because we make analyzers for every part of the process—from acid-feed gas to tail gas to emissions, including the gas treating unit, sulfur storage (pit) gas, and hot/wet stack gas—you get the convenience of one source for unparalleled engineering and support for all your analyzers, while your operators benefit from consistent interfaces and operating procedures. For decades, we’ve been dedicated to making your SRU operation the most efficient it can be for the long term. Learn more at www.ametekpi.com/SRU.

Table 1. Typical feed gas stream

Operational efficiency

Component

Concentration (%)

H2S

30 – 100

CO2

0 – 80

NH3

0 – 70

H2O

0 – 10

Total hydrocarbons

0–2

In addition to sulfur recovery efficiency, SRU operational teams are also looking to maximise uptime and reduce operating costs. In lean feed applications, turndown applications, or situations where aromatic hydrocarbons or ammonia are not present, being able to run the reaction furnace at lower temperatures represents an opportunity to reduce fuel costs and minimise fossil fuel consumption – an operational ‘win-win’. At a minimum, most reaction furnaces are operating at or above 925°C. This represents an ideal set point temperature, but in reality furnaces are running hotter (they have to in order to completely destroy impurities that are present in the feed gas, such as some aromatic hydrocarbons and NH3). If these components are not properly destroyed in the reaction furnace, they can lead to the contamination of catalyst in the Claus unit (soot), or ammonia salt formation. Both of these contaminants can lead to reduced sulfur recovery efficiency and/or SRU downtime in worst case scenarios. As such, reaction furnaces need to be run at temperatures above 1050°C or 1250°C, but ideally never above 1500°C, as this could lead to refractory damage. Measuring the concentrations of hydrocarbons and NH3 at the feed gas can allow for proper temperature management of the reaction furnace, to reduce excess fuel consumption without running the risk of damaging catalyst or other downstream hardware. For both upset identification and operational efficiency improvements, an existing analytical system exists that is capable of measuring multiple feed gas components safely and quickly. H2S is extremely dangerous and always at % compositional levels in feed gas streams. AMETEK has designed a sample probe, sample handling system, and analyser designed to minimise the risk of H2S exposure to maintenance and operational teams. This is referred to as the AMETEK feed forward IPS-4 solution, adding additional measurements and safety considerations to those already using an AMETEK 9xx analyser to measure the feed gas component concentrations. The measurement needs to be continuous, with minimal lag and sampling times. Ultraviolet (UV) and infrared (IR) technologies integrated in the AMETEK IPS-4 allow for the continuous measurement of H2S, NH3, CO2 and hydrocarbons, with minimal maintenance and no consumable components.

Table 2. Oxygen consumption Compound

Moles O2 per mole hydrocarbon

Ratio of O2 needed per mole hydrocarbon compared to per mole H2S

Methane

Ethane

3.5

Propane

Butane

6.5

Pentane

Hexane

9.5

reliably identifies changes in the ratio and/or H2S and SO2 concentrations, but not until after a considerable amount of feed gas has already entered the Claus unit. By themselves, ADAs are not fast enough for ideal process control in an SRU. At the time of feed gas introduction to the SRU, identifying process gas component concentration changes (upsets) can more accurately identify the source of the changes seen at the Claus outlet, and better protect downstream systems such as an amine-based TGTU or thermal oxidiser. When process upsets occur upstream of an SRU, they usually involve elevated levels of hydrocarbons in the SRU feed gas. Unexpected scrubber media failure or improper amine management may result in hydrocarbons being stripped out of process streams and sent on to the SRU. As has been documented in many papers, hydrocarbons can selectively bind with the available O2, reducing the O2 available for H2S to SO2 conversion (see Table 2). When the hydrocarbons are ‘stealing’ the available O2, and the ratio of H2S:SO2 is elevated, recovery efficiency falls in the SRU. Since correct management of sulfur recovery efficiency is critical in an SRU, automated systems and operators will adjust accordingly and increase the amount of air or O2 at the reaction furnace. This is a proper response and does frequently return the system to a desired H2S:SO2 ratio at the Claus outlet. However, this introduction of elevated levels of O2 at the reaction furnace can have an undesirable consequence. When the upstream upset condition is corrected, and the amount of hydrocarbons suddenly returns to expected levels (or lower), the excess O2 being introduced at the reaction furnace results in the creation of too much SO2. The H2S:SO2 ratio is then lower than expected, and sulfur recovery efficiency is again negatively impacted. Even more concerningly, excess SO2 levels proceed to TGTU units and can cause issues with the scrubbing media. If enough SO2 migrates to the scrubber, replacement of all of the media may be required. Not only is this very expensive, but it may also result in the SRU operating in bypass mode and/or out of compliance. This could also lead to significant fines (more undesired costs). June 2022 18 HYDROCARBON ENGINEERING

Conclusion If you interview a good chef, they will always tell you that the best way to ensure satisfied diners is to choose the best ingredients possible, monitor the cooking process as much as possible, and constantly solicit feedback from the consumers. Many SRU professionals will struggle to compare their SRU operations to a restaurant – and justifiably so – but AMETEK believes that the time has come for SRUs to be managed more tightly, in order to ensure greater end user satisfaction (end users being environmental compliance teams and regulatory agencies, and operational engineers). The ADA provides insights on the concentration of H2S and SO2 leaving the Claus plant, and is already present in SRUs. Adding an AMETEK IPS-4 feed forward analyser system provides more insights into what is entering the SRU (the ‘ingredients’), allowing greater process control throughout the Claus unit and SRU.

Philippe Herve, SparkCognition, USA, presents various artificial intelligence applications in the downstream oil and gas sector.

he refining industry has, for its entire existence, been extremely demanding from both operational and financial standpoints. Additionally, the industry has faced a series of unprecedented challenges that have resulted in enormous pricing and profit volatility in recent years. Some of these challenges (e.g. technological evolution, an ageing workforce, and environmental sustainability demands) are at least somewhat within the industry’s control, whereas others (e.g. supply chain disruptions, geopolitical shifts, feedstock and/or commodity price swings, and the impacts of COVID-19) are decidedly not. The downstream/refining industry has long been characterised by its immense capital requirements, high risk of failing to earn acceptable rates of return, and an organisational culture that leans heavily toward only implementing new technologies that have been proven in long-term operations.

Further, the industry has suffered continuing hits to its environmental reputation due to the significant number of accidents, chemical discharges, and recurring shelter-in-place notifications that are a regular part of life in places such as the Gulf Coast and the Houston Ship Channel in the US. These incidents generate relentless press coverage and publicity. Artificial intelligence (AI) is at an inflection point in its evolution, shifting rapidly from experimental/pilot status to mainstream operational application – at least with firms that aspire to be leaders in their industries. While AI has reached the point of demonstrating its value in multiple use cases, its primary value derives from processing the sensor data generated by complex technological assets and then applying machine learning (ML) to predict when these assets require maintenance, when failures are imminent, or even cases in which sub-optimal performance is putting decarbonisation and

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sustainability goals at risk. Such insights provide asset managers with the advance notice that they need to avert expensive equipment failures. In many cases, the raw ingredient of successful AI implementation – historical and real-time performance data – already exists in abundance, with some refinery operators making more effective use of it than others. Modern distillation, cracking, and other refining systems produce vast quantities of second-by-second data on pump pressures, temperatures, flow rates, emissions, and a host of other performance indicators. AI systems aggregate all of this data, apply ML algorithms, and render predictive warnings about equipment that is in need of maintenance or perhaps on the verge of outright failure. On the other hand, data on complete system outages can be scarce as refiners do not, as a rule, allow expensive assets to operate to the point of catastrophic failure. Despite this limitation, ML capabilities have proven their ability to predict failures and optimise system operations far more effectively than traditional legacy systems. The principle challenge is therefore to maximise the competitive advantage that can be gained by leveraging all of this data to the greatest possible extent. Because ML systems learn more about normal equipment operation with each passing day, AI algorithms can not only predict expensive failures, but can also save additional operational expense by reducing the performance of pre-scheduled – but possibly unnecessary – maintenance activities.

The solution Predictive maintenance

By making rigorous AI-enabled use of operational data, refinery operators can adopt a predictive maintenance approach that allows for the identification and prevention of asset failures before they occur. Predictive maintenance uses ML algorithms to ingest historical and real-time sensor data from a plant’s operations. This data is used to build and test models that serve as profiles of what normal operations look like. The normal behaviour model can then analyse equipment sensor data in real time, and identify and flag values that deviate from this established norm. Using historical sensor data, as well as knowledge from subject matter experts (SMEs), this model can pinpoint exactly when and how a failure will take place, rather than simply warning that a component is at risk. Refinery operators are then able to plan timely maintenance and avoid excess downtime or expensive, potentially-catastrophic failures. Addressing speed and scale challenges simultaneously, predictive maintenance algorithms ingest and analyse data to deliver predictions and recommendations by finding patterns at a scale much greater than humans are capable of handling. ML can unlock the insights in this data quickly, efficiently and accurately, identifying anomalous behaviour and understanding causal relationships using advanced, unsupervised learning techniques. Such a system provides operators with faster insights into asset failure prevention for any size of operation. However, not all refinery systems or subsystems have the sensors to provide the amounts of data that predictive maintenance requires. ML alone cannot solve this dilemma, but ML-powered natural language processing (NLP) can. Most software is only able to analyse structured data, or data June 2022 20 HYDROCARBON ENGINEERING

containing numbers or categories. On the other hand, AI-powered NLP platforms can decipher and use unstructured data as well, be it operations logs, safety reports, service manuals, PDFs, books, journals, or any other source imaginable. This capability is valuable for refinery operators because with NLP, predictive maintenance models can use sources of data beyond sensors. By extracting facts, figures and contextual data from an asset’s maintenance history, predictive maintenance solutions outfitted with NLP find causal patterns that indicate potential failures, even in so-called dark subsystems that lack sensors.

Worker safety and health

The performance benefits of AI and ML are not limited to the operations and maintenance of systems and equipment. Effective health, safety and environmental (HSE) management programmes are critical for the physical wellbeing of employees, as well as ensuring productivity and overall performance. However, with each new project, process and piece of equipment comes a wide variety of safety risks, leading to an increased demand for safety supervisors and processes. Health and safety records are routinely collected and analysed for regulatory reasons, typically by using typed or handwritten data entry forms. Safety supervisors then manually analyse the records to identify risks and create new regulations, best practices guidelines, and safety training programmes. Industry-leading operators and safety supervisors are beginning to implement AI-based solutions that enable them to proactively address HSE concerns. Specifically, there is a shift to explore and implement solutions that: nn Quickly and efficiently extract actionable insights from the unstructured data found in incident reports, observation cards, etc. nn Reduce incident rates associated with previously-identified hazards. nn Provide assurance that critical risks are being managed effectively. nn Forecast and mitigate future incidents before they happen by identifying previously unknown hazards. NLP provides significant value to health and safety managers by automating the process of gleaning insights from the copious manual data available on incidents and hazards. This technology not only helps safety supervisors to better understand the incidents that have already taken place, but it can also identify leading indicators of developing hazardous conditions – indicators that would not be apparent from manual report analysis – enabling safety supervisors to anticipate and avoid incidents before they happen. Over time, safety supervisors collect thousands of observations that include data on hazard locations, observation dates, and specific details, but all in unstructured formats. While it would take safety supervisors an enormous amount of time and effort to evaluate all of this data and extract meaningful insights, AI-based NLP algorithms can analyse such unstructured data, extract critical insights, provide summaries of hazard and risk areas, and mitigate the likelihood of an event occurring in the future. Therefore, NLP techniques provide a platform for creating, assigning, and closing out action

n T e e v

ogy nol ch

AI-powered predictive maintenance, while invaluable, is only part of the value that ML can deliver to refinery operations. After all, predictive maintenance does not absolve operators from the need to perform equipment maintenance and repairs. By augmenting data-driven predictive maintenance with NLP technology, AI-based maintenance solutions are able to ingest historical records and service manuals, as well as past courses of action taken by SMEs. Using this information, both structured and unstructured, the solution can both speed up maintenance processes, and make them safer for staff by listing possible next steps, suggesting corrective measures, and identifying potential hazards and environmental risks. In past deployments in oil and gas refining, AI/ML programmes have increased the ability to identify unexpected subsystem failures by 75%, and more than doubled previous lead times to an average of nine days advance warning, whereas it was previously only a matter of hours, if there was any advance notice at all. Industrial operations are often full of uncertainty, but they do not have to be. ML technologies are already allowing leaders in oil and gas refining to truly leverage the potential of their data, enabling safer, more sustainable, and more profitable operations.

Process Simulation

Pro

The outcomes

OGT | ProTreat®

Same

items related to potential hazards, enabling safety supervisors to take an even more proactive role in identifying and resolving workplace health and safety issues.

Conclusion

nts

olve

y b ri

it h

w it

lven t

N ow

H y ri b

N ow w

The challenges of efficiently, safely, and sustainably operating refining and petrochemical plants have been the sole purview of long-tenured engineers and technicians for decades. With the recent onslaught of system performance data and reductions in the number of experienced staff members, an alternative approach is required. That approach is AI technologies such as ML, natural language processing, and knowledge graphs that are now delivering significant business value to industry leaders who aspire to retain their leadership position. It is important to note that regardless of specific equipment or process type, several key corporate-level challenges will also be key drivers of the success of AI-based programmes. These include executive focus and leadership, availability of suitably skilled staff members and external partners, the ability to identify quick-win processes to generate and maintain organisational momentum, and the realisation that applying AI technologies to a fundamentally bad process is not a cure-all for that process. It is, therefore, important to enter into an AI programme with eyes open not only to the immense operational and sustainability improvement opportunities, but also to the challenges of the undertaking. Becoming proficient at AI implementation is fast becoming important for industry leaders, particularly in a field as technologically and financially demanding as refining.

Bibliography • • •

‘The oil industry: The new great game’, The Economist, (January 2022). WELSH, T., ‘How AI and machine learning benefit refineries and petrochemical plants’, Hydrocarbon Processing, (January 2019). PIETRI, A., ‘How industrial AI will power the refining industry of the future’, Information Age, (September 2020).

Optimized Gas Treating, Inc 212 Cimarron Park Loop, Buda, TX 78610 www.ogtrt.com +1 512 312 9424

June 2022 22 HYDROCARBON ENGINEERING

Kjell Wold, John Bromley-Barratt and Gaya Somasundaram, Emerson, explain how to identify pipe replacement needs using digital remote corrosion monitoring.

orrosion poses a significant challenge to operational safety, plant uptime and maintenance costs. With corrosion costing approximately US$2.5 trillion – equal to 3.4% of the global GDP – control practices are estimated to reduce this astronomical amount by US$375 – 875 billion/yr on a global basis.1 Corrosion is not just a maintenance issue; the cost should also factor in that many of the chemical industry processes, for example, have aggressive and potentially dangerous fluids and gases, which can have a significant impact on people, assets and the environment if they leak or spill. Employing a comprehensive programme for integrity management, including inspection and corrosion monitoring, is part of standard operating procedures at plants. Inspection offers an extensive overview of the

overall state of the plant, and corrosion monitoring provides up-to-date information on select, targeted locations. Understanding the root causes of corrosion by correlating continuous monitoring with other process data ensures greater safety. Typically, corrosion control strategies that are based on collecting monitoring data are part of process optimisation or corrosion inhibitor programmes. Therefore, information from a well-designed corrosion monitoring system initiates actions before corrosion damage can cause problems.

The debate over corrosion monitoring Within industries that are impacted by corrosion, the value of monitoring has been continuously debated. Whilst there is consensus that monitoring is required, best practices have been discussed. Until recently, sensor technologies have been limited, and it has been difficult to

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choose a reliable monitoring solution that presents an accurate representation of the true form of corrosion. Delivering required information to the user is essential, and if the information is not reliable, then the value of the system is also limited. In addition to this, corrosion monitoring is generally not part of most operators’ core competencies. A lack of internal resources, skill and ownership for using and maintaining a corrosion monitoring system, including presenting the information to facility management to prove the value of the system, can hamper the implementation and use of the system. What is needed is a system that does not require in-person inspection or data collection at each monitoring point.

New technological developments Fortunately, technology continues to develop, and new solutions to overcome challenges have become available. Fast response sensors and non-intrusive wall thickness monitors have been developed in recent years, which add flexibility when selecting the best combination of monitoring solution(s) related to the actual form of corrosion and use of the data collected. An added benefit to being able to measure pipe corrosion directly is that

non-intrusive sensors do not introduce any safety risks or inconveniences to the plant operations. Acceptance and standardisation of wireless communication, such as WirelessHART®, makes continuous and online monitoring simpler across devices and more straightforward to work with. Continuous monitoring produces better trending data and can show correlation with other production events, helping to determine the root cause of corrosion problems. Online communication ensures that data is available in real time, with a greatly reduced need for personnel to perform manual rounds to collect data.

Monitoring data digitally Another effect of online communication is that data is available in digital format and can be easily shared. Access to digital ‘housekeeping’ data allows for remote diagnostics and maintenance planning – reducing the need for expensive site visits – and enables proactive maintenance (e.g. spare parts, field service plans, etc) for reliable system performance. See Figure 1 for a visual representation of a comprehensive monitoring system. As mentioned, the understanding and interpretation of data can be a challenge, particularly if teams are reduced and personnel have several tasks to handle. With access to digital data, corrosion and erosion reports can be easily pulled together remotely by subject matter experts (SMEs) who are trained in data assessment and drawing key conclusions from the data.

Connected services Figure 1. A selection of in-line and non-intrusive monitoring technologies, online wireless communication, and digital data handling enhances the efficiency and reliability of corrosion monitoring.

Figure 2. An example plot of corrosion rates over a three-month period for different sections of a plant. As seen in the first area, one sensor shows severe corrosion, 10 sensors show high corrosion, and the remaining locations show low or no significant corrosion. The focus should be on locations showing high or severe corrosion.

June 2022 24 HYDROCARBON ENGINEERING

A clear trend is emerging towards adding data analysis and reporting to the scope of supplying monitoring systems in what some companies call connected services. The result is that the client receives timely reports based on the correct interpretation of data, highlighting the most critical information – such as which locations are showing high corrosion, where corrosion is increasing, or at what time the corrosion rates changed. At the same time, operators can free up resources for core business, assured that the

We see

cutting-edge corrosion management maximizing operational output. Emerson transforms refinery throughput and safety with actionable, real-time corrosion and erosion data. Nonintrusive Rosemount wireless monitoring systems drive more efficient operations for an increase in production and decrease in potential shutdowns.

Rosemount Corrosion and Erosion Monitoring System

Download the whitepaper at Emerson.com/WeSeeCorrosion

Figure 3. Metal loss vs time plot (left), with the bottom line indicating internal roughness of the pipe, and predicted corrosion (right) estimating the time when retirement thickness of the pipe will be reached. monitoring programme is functional and the integrity information is captured for qualified actions. In connected service reporting, the aim is to combine an efficient overview of the plant’s monitoring locations while providing a more detailed analysis of findings of particular importance. Figure 2 shows an example where ultrasonic thickness (UT) monitors are divided into areas in a plant, categorised with corrosion rates according to the National Association of Corrosion Engineers (NACE) classification.

Case study: a petrochemical plant One example from a petrochemical plant illustrates the use and value of online corrosion monitoring and digital services. The plant experienced corrosion problems and replaced some of its process piping. It opted for an extensive amount of Emerson’s RosemountTM Wireless Permasense Corrosion and Erosion Monitoring Systems to be installed to monitor the corrosion rates after the plant upgrade. Whilst analysing the data, it was discovered that 95% of the sensors showed corrosion activity over a four-month period, and in some locations to such an extent that the remaining pipe life was estimated to be less than one year. Figure 3 shows the use of metal loss data vs time plots. The left-hand side shows metal loss vs time; the slope of the curve represents the corresponding corrosion rates. As can be seen, corrosion rates in a period from around August 2020 were high (2 mm/yr), however they decreased to a level of around 0.5 mm/yr from September onwards. The change in corrosion rates may reflect process changes or the effect of corrosion mitigation. The bottom line indicates internal roughness of pipe, which helps better understand corrosion conditions. On the right-hand side, corrosion rates are used to predict the remaining life of the pipeline, comparing corrosion rates with defined retirement thickness of the pipe. The circle around November 2021 indicates time when corrosion allowance of the pipe will be consumed. Such prediction allows for timely integrity planning, which June 2022 26 HYDROCARBON ENGINEERING

increases safety and reduces the need for unplanned maintenance/repairs and plant downtime. Plots for different sensors can be combined and used to identify general trends and locations where corrosion problems are particularly severe. To verify that the measured corrosion rates are reliable, raw data is checked against temperature variations and ultrasonic waveforms, confirming the validity of the data. When compared with pipe wall thickness/corrosion allowance, it was found that for the actual plant, some pipes had a remaining life of less than one year, many between one and five years, and a few with a life expectancy of more than 10 – 15 years. Based on the monitoring results, replacement of heavily-corroding piping will be carried out earlier than originally planned.

Conclusion In summary, online monitoring identified high corrosion rates that would have posed a risk to plant uptime and safety if undiscovered. Through remote data analysis and reporting, the following was achieved: nn Raw data was checked to validate that measured wall thickness and calculated corrosion rates were correct. nn Critical findings were highlighted with corrosion rates, and the remaining life of piping for critical location was calculated. nn Corrective actions (replacement of pipes) were planned and implemented before damage or accidents occured. Corrosion is at the root of many maintenance, integrity, and safety challenges facing operators today. Real-time corrosion monitoring of equipment and associated piping can provide valuable insight into the corrosion status and provide an up-to-date picture of how infrastructure is coping with the ever-changing demands placed upon it.

Reference 1.

‘Economic Impact’, NACE International, http://impact.nace.org/ economic-impact.aspx

of the pipe, which will result in a continuous thinning, or wall loss, of the solid structure. Pitting corrosion is the local deterioration of a more limited surface area that leads to cavities or ‘pits’ that may puncture the pipe and cause leakage. Some forms of deterioration, such as erosion corrosion, which results from the movement of fluid and its interaction with the inner surface of a pipe, are not visible with just an exterior visual inspection. While there are several ways to hinder the corrosion of critical assets, such as cathodic protection or sacrificial anodes, there is no substitute for regular monitoring along the pipeline. In most cases, a company will perform a corrosion risk assessment. This involves an identification of the facilities that are at risk, ranking their proneness to corrosion, and identifying options to remove or mitigate the risks. In order to combat this ongoing process of corrosion, inspection, assessment,

Figure 1. Ultra-high-temperature microPIMS attached with a band clamp.

Figure 2. Three networked system types all feed into the cloud, or a private server, with one common, back-end web portal for data management.

June 2022 28 HYDROCARBON ENGINEERING

replacement, and the regular monitoring of assets should be viewed as a strict necessity. Monitoring asset integrity in the critical energy segment has typically been carried out by manual and visual inspection or invasive technologies such as coupons focused on likely-affected locations across given time intervals. Allocating manpower to physical locations for inspections is not only costly in terms of financial compensation, but there is also an element of physical danger involved in the examination of pipelines that are located in adverse environments.

A history of monitoring While periodic monitoring for corrosion can decidedly decrease incidents of failure of critical assets, a more permanent solution was needed in order to accurately ascertain continued asset viability. In February 2014, two ex-GE employees, Dr. James Barshinger and Bruce Pellegrino, saw the need for a more efficient and comprehensive alternative to these traditional monitoring techniques. Their solution was the use of wireless sensor networks (WSNs). As a result, asset owners could install wireless, battery-operated ultrasonic (UT) sensors at strategic locations, virtually eliminating the necessity for costly and unnecessarily-dangerous manual inspections. These UT sensors continuously monitor asset integrity without the need for onsite, physical examination and assessment. The spring of 2015 saw the debut of a hardwired version of a permanently-installed monitoring system. This non-intrusive UT monitoring system connects directly to a PC or laptop and is geared more towards infrequent data collection. Over the next few years, the duo worked steadily on creating and improving UT transducers and various other product lines that included cellular-connected systems, WiHART, and LORA-WAN wireless protocols. In 2016, the company formed by Barshinger and Pellegrino, Sensor Networks Inc., decided to build a UT division from the ground up, providing the industry with an assortment of transducers ranging from phased-array to angle-beam and immersion transducers. In addition to transducers, a vast line of asset maintenance apparatus, including remote visual inspection tools and remote retrieval solutions, were designed for an array of industrial applications. Today, due to the inclusion of UT transducers, oil and gas pipeline integrity can be closely monitored without costly and often dangerous manual inspection of assets in the field. By October 2021, advancements in technology allowed for the development of a third-generation, permanently-installed monitoring system (microPIMS® Intrinsically Safe). This star-network topology system operates using long range sub-gigahertz LoRaWan® wireless connectivity. Each microPIMS sensor can be programmed to record thickness readings at any user-defined time interval. Data is automatically sent to a private webPIMSTM, cloud-based or on-premises LoRaWAN system, and software with back-end data analysis, trending and more. These units can be easily installed either temporarily or permanently, with either a band clamp or a magnetic base for tanks and vessels. Two D-sized batteries provide each unit with 15 years of life atone reading per day. The microPIMS can also help to lower costs by reducing scaffolding and insulation removal/refitting for internal corrosion monitoring.

Case study The problem

One of the more critical areas for refineries to be able to manage and maintain from an Environmental Compliance and Safety perspective is the amine treating unit, often part of sulfur recovery and tail gas teating units (SRU and TGTU). The TGTU converts any remaining sulfur compounds into hydrogen sulfide (H2S), which is then reprocessed by the SRU. The SRU tail gas is heated and sent to a catalytic reactor where it is cooled and sent to the absorber column in the amine treating unit (ATU). It is during both this and the succeeding processes that many experience corrosion/erosion events, which can cause setbacks in asset integrity planning. In this case, it was determined that the design of a nozzle in the horizontal position in one of the exchangers was a poor industry design that caused turbulence (eddies) and increased the corrosion rate in specific areas.

The solution

Due to the intermittent nature of this erosion-corrosion damage mechanism, achieving a reliable corrosion rate and focusing in on the most likely affected locations was challenging. After years of repeated manual UT thickness inspection at different intervals, with limited success, the asset owner decided that instead of a periodic manual inspection, they would monitor continuously.

Along with personnel from Sensor Networks Inc., the owner mapped out the areas that would most likely be of concern and performed some baseline screening and inspection to identify where to monitor. Then, automated, wireless, battery-operated UT sensors were temporarily installed at strategic locations on the asset. The asset owner was able to programme reading intervals for the sensors to take daily wall thickness measurements which were then plotted over time. The installation process only took one day, and each sensor was installed in less than 20 minutes per monitoring location by their own site personnel.

The outcome

Using the monitoring approach via the installation of SNI wireless UT sensors, the asset owner was able to quickly and accurately (to within 0.001 in./0.025 mm) trend the corrosion rate at each point where the sensors were located. Furthermore, with the help of the operations and corrosion teams, the asset owner was able to remediate or reduce the corrosion at this location of the unit.

Financial impact

Since the unit was built, there have been > 6 unplanned outages over a 15-year period which have been traced back to this issue, at an estimated US$12 million in maintenance cost and US$200 million in downtime. The ability to trend and, in this case, remediate the corrosion rate for the tail gas unit (TGU), allowed the asset owner to safely operate the unit for an estimated 4.6 additional years, saving maintenance activities and US$4.8 million. A US$40 000 investment in an SNI microPIMS starter kit yielded a return on investment (ROI) of 98% and payback period of less than three months. The rest of the site will also benefit from the long-range wireless infrastructure investment and place sensors across the entire facility to monitor other critical assets. By scaling this strategy across its facility, this refiner expects to expand its digital asset integrity and monitoring programme to identify many other locations, with the potential of safely extending the life of its assets, and saving millions of maintenance dollars annually. While asset monitoring will always be a necessity for the oil, gas and petrochemical industries, the manner in which these assets are inspected does not always need to be a financial or operational burden. The implementation and use of these remotely-accessible UT monitors has proven to be a recognisable resource industry-wide, and as more critical energy companies avail themselves of this technology, the incidence of pipeline failure could become less of a catastrophe and more of a minor nuisance.

Conclusion

Figure 3. A dual element microPIMS attached with a band clamp and magnetic base.

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Metal loss, due to corrosion or erosion, can manifest itself in numerous ways: random, general, highly-localised, episodic, unit and site specific. The tools discussed in this article have evolved over the past decade to accommodate the wide range of issues facing corrosion, life extension and facility managers at upstream, midstream, downstream and petrochemical facilities. Sensors and software that are accurate, reliable, reasonable in cost, and easy to attach, manage and deploy as needs change, are increasingly becoming the norm and recommended best practice.

Zacc Dukowitz, Flyability, USA, details how drones are helping to improve safety at oil refineries.

rone technology has rapidly improved over the last few years, and with these improvements have come its rapid adoption in the oil and gas industry. Inspections present one of the most common uses for drones in oil and gas. During planned outages, inspectors use high-quality inspection drones to collect visual data remotely, allowing for data to be collected more quickly and more safely than would be possible using a manual approach. The use of drones as a remote visual inspection (RVI) tool does not present any sacrifice in data quality. In fact, in many cases the drone’s visual data will be of the same – or better – quality than the data an inspector could collect in person. The data will also typically be more comprehensive, since drones can capture video during an entire flight, from which still images can be extracted for further analysis.

How drones improve plant safety during inspections The five controls that guide safety considerations for industrial work are as follows (in order from most to least effective):1 n Elimination: physically removing a hazard. n Substitution: replacing a hazard with a lower-risk alternative. n Engineering controls: separating workers from a hazard. n Administrative controls: changing the way people work. n Personal protective equipment: providing protective equipment such as helmets, boots or gloves. For most visual inspections at oil refineries, drones can allow maintenance managers to implement the highest HYDROCARBON 31

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control: elimination. By taking the place of the inspector for data collection, a professional drone can completely eliminate any potential hazard the inspector would have faced, thus radically improving safety during the inspection. During internal visual inspections, such as those carried out inside tanks or pressure vessels, inspectors often face the hazards of confined space entry, work at height, and exposure to noxious gases. During external visual inspections, such as those completed outside stacks, inspectors also face the hazard of working at height. These hazards are all eliminated by using a drone to fly into an asset or along the outside of an asset, collecting visual inspection data that shows its condition. It is important to note that drones are only a data collection tool, and some exposure to the aforementioned hazards will still be required for maintenance operations conducted during plant downtimes. Although a drone may be able to eliminate the hazards an inspector might face, the maintenance itself must still be performed in person, and this work will require maintenance personnel to encounter the hazards that were eliminated during the inspection process. However, in some sectors, robotics advances are allowing even this part of the maintenance process to be performed remotely. In wastewater infrastructure, for example, a fully-remote maintenance process is now possible by using a drone to conduct an inspection and then using a crawler robot to repair any defects found – all without a person ever having to enter the pipe. That being said, it will still be a long time

Figure 1. Flyability’s Elios 2 indoor drone (source: Flyability).

Figure 2. A cyclone separator.

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before robotics have advanced enough to perform most maintenance operations required at oil refineries, or in most industrial scenarios in which drones can be used for inspections.

What kinds of assets are inspected by drones at oil refineries? At oil refineries, drones are typically used to inspect fluid catalytic cracking (FCC) units, cokers, storage tanks, chimneys, and smokestacks. For the upstream parts of the production process, drones are also being used to inspect ballast and storage tanks in FPSOs, drilling ships, and oil tankers. Internal inspections, such as those carried out inside FCC units or cokers, will typically be completed using a drone made just for flying indoors. Such drones sit within a cage, which both protects the drone and the interior of the asset in case of collision. In addition to the cage, indoor drones typically have other features built into their design that make them collision tolerant, allowing them to collide and to continue flying unharmed (see Figure 1). External inspections, on the other hand, such as those carried out on the exterior of stacks, are typically completed using a professional outdoor drone. This is basically the standard design of a commercial drone, without a cage or any other features that would enable flight in confined spaces.

Case study Fairly recently, the largest oil and gas company in Turkey, Tüpraş, decided to test the use of a caged indoor drone for a visual inspection inside an FCC unit. The FCC unit was located at the Izmit Refinery, which produces 33% of the petroleum products consumed in the country. One of the primary goals of the test was to find a way to improve safety for these types of inspections. A manual inspection of the FCC unit would require an inspector to enter the confined spaces inside the riser and cyclones of the unit by rope access. Tüpraş wanted to see if these hazards could be eliminated by using a drone instead of a person to collect the visual data that the company needed. Over a period of three days, inspectors at the refinery were able to use the indoor drone to successfully collect all of the visual data that was needed inside the FCC unit. There was no need for entry in order for the inspection to be completed. Flyability inspected the following: nn The riser: a 50 m (164 ft) long vertical pipe lined with wear-resistant refractory where the heavy hydrocarbons from crude oil mix with a catalyst and are cracked into smaller hydrocarbons. nn The vapour overhead pipe: the 30 in. pipe that carries hydrocarbon vapours into a fractionating column where they are separated into gas, gasoline, diesel, paraffin, or other marketable petroleum products. nn The cyclones: cyclone separators used to separate hydrocarbon vapours and strip steam from the FCC catalyst (see Figure 2). The test was a success. The drone not only eliminated all of the hazards for the inspectors, but it also significantly

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reduced the amount of downtime needed for the inspection. In total, inspectors saved the equivalent of two and a half days of work, representing 170 manhours. Time was primarily saved by avoiding the need to cut the top cap of the reactor riser open, which is the standard procedure so that a person can enter the riser in order to perform a visual inspection. The reduced downtime resulted in significant savings for the plant, while also improving safety, representing a win-win for the company. In addition to images and videos, Tüpraş inspectors used the visual data collected by the drone to create a 3D model of the riser (see Figure 3).

A third option is to have a drone fleet and some trained in-house drone pilots, as well as hire contractors for specific types of work with drones. This option is the one that Chevron has chosen; as have many other large companies in the sector. This hybrid approach allows for constant data collection support during emergencies via in-house pilots, as well as regular maintenance support for routine planned outages. It also allows for flexibility when it comes to special one-off operations via third parties. These operations would require either too much money or too much complexity to keep full-time staff trained for them.

How to conduct a visual inspection by drone

Data analysis

The following is a typical workflow for a drone inspection performed at an oil refinery:2

Planning

The inspection is planned in advance, as with any inspection, with inspectors working alongside other stakeholders to identify all of the assets that require inspection, and specify the types of data needed. When planning a drone inspection, it is important to question whether the drone will fit and, in the worst case scenario, what would happen should the drone get lost.

Data collection

On the day of the inspection, the inspector may fly the drone themselves or they may work with a trained drone pilot to fly it. Regardless of who flies, it is important that the inspector can see the live visual feed from the drone while it is in flight so that they can identify potential defects and spend more time collecting data in any potentially problematic areas, ensuring that they acquire all of the data that they need. Some large oil and gas companies have developed their own internal drone programmes, with trained drone pilots who are ready to conduct inspections during planned turnarounds or emergency outages. On the other hand, some companies prefer to hire third parties to carry out drone inspections.

Some data may be analysed while the drone is in flight. However, a typical drone inspection will work similarly to a manual inspection, with the inspector carefully reviewing the visual data after its collection.

Reporting

After analysing the data, the inspector will create a detailed report with the findings, in which they detail any defects such as corrosion or cracks found in the assets inspected. This reporting will be supported by the images and video collected by the drone, allowing other stakeholders to see the flaws covered in the report. Another item that is important in reporting from any drone inspection is knowing the location of a defect found in the visual data. When you have a video of an inspection made inside a huge, homogenous structure, such as a diesel storage tank, it can be hard to know exactly where the defect is. However, advances in drone-related software have addressed this problem. New software now allows inspectors to create 3D models of assets, with the capability to add specific ‘points of interest’ inside the model. These models can then be included in the inspection report, allowing other stakeholders to see the specific location of defects found during the inspection.

Choosing drone technology The drone industry is still relatively new, and sometimes it can be difficult to find reliable technology for one’s specific needs. A good rule of thumb for choosing a professional drone is to first consider the data collection needs, before researching drones that can meet these specific requirements. For example, if it is necessary to perform outside stack inspections, a drone with high-quality optical zoom may be required; and if it is necessary to perform internal boiler inspections, a high-quality indoor drone may be required. Another rule of thumb is to look for actual case studies and clients that have gone on record with a company. Any professional drone that is worth purchasing should have a proven track record, with case studies covering specific use case(s) and a list of companies that are using the technology.

References 1.

Figure 3. A 3D model of the riser.

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‘What is the hierarchy of control?’, https://www.flyability.com/ articles-and-media/hierarchy-of-control ‘A guide to how drones are used for inspections’, https://www. flyability.com/drone-inspections

Kieran Boyd, Avestec, Canada, discusses the use of a non-destructive testing inspection method to monitor equipment at a refinery.

ne of the significant onshore refineries in North America processes crude oil from the Pacific Northwest into mainly gasoline, diesel or jet fuel. The refinery, covering 3300 acres, can process approximately 250 000 bpd of crude oil.1 In recent years, the multinational oil and gas company that owns the refinery has prioritised reducing its carbon footprint. It completed a 22-month modernisation project to help reduce source emissions. After completion, the oil producer planned a multi-hundred-million-dollar investment to improve the refinery’s efficiency, reduce its carbon dioxide (CO2) emissions, and increase its renewable diesel production capability.2 During the company’s pursuit to reduce its carbon footprint, Avestec inspected the condition of the equipment that was being used. Non-destructive testing inspection, using a flying robot, was an efficient means to do so. The team inspected three assets at the refinery in August 2021, and the testing successfully provided accurate readings and improvements when compared to conventional methods.

Customer needs Oil refinery inspections monitor the condition of assets to avoid unscheduled shutdowns for restoration or replacement. The industrial process plants are responsible for predictive maintenance of their equipment every three to five years. Owning companies require a third-party inspection team to ensure that their equipment meets mandatory operating conditions.

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Predictive maintenance equipment measures the condition of equipment through non-destructive testing. Non-destructive testing in maintenance is carried out by both visual and contact-based inspections. Visual inspection analyses equipment appearance using cameras, the human eye, and artificial intelligence (AI)-sensing technology. Contact-based assessment measures the thickness of assets using ultrasonic (UT) gauges.3 During the inspection of the large refinery, Avestec performed the UT measurements on various pieces of equipment. Skyron, a flying robot, gauged the flare stack, storage tank, and pipe at hundreds of points throughout each asset. Each asset shared the challenge of having elevated measurement points, further emphasising the safety and efficiency of an aerial approach.

Solution Before the Avestec inspection method, this refinery’s predictive maintenance was performed using conventional methods, such as scaffolding and rope access. Modern-day scaffolding is efficient in the amount of material and time needed to set up temporary constructs. Rope access incurs minimal costs, and poses limited risk to inspectors. However, it still requires time and cost, and can put inspectors in dangerous positions. In the inspection industry, asset owners and inspection teams prefer rope access to scaffolding as it takes less time, and costs less. However, scaffolding still plays a large part in its safety and access. For example, inspections with no ability to hang ropes from structures still need to set up scaffolding. Furthermore, scaffolding is safer than rope

access as it provides inspectors with a solid surface at height, instead of a harness.3 Both scaffolding and rope access meet customer needs in providing accurate data from contact-based inspection; however, it is an expensive necessity. Scaffolding is costly due to the need to rent a large amount of equipment, and the time that is taken to build temporary structures. Rope access is faster to set up than scaffolding, but does still require set-up time. Furthermore, both methods put inspectors in potentially hazardous positions at heights, regardless of surface or no surface. The methods are costly, time consuming, and put inspectors in danger next to contact-based inspections with Skyron. The method provides accurate NDT inspection data without the baggage. The robot can fly to the points of contact and perform measurements. The inspection team can operate safely using line of sight or first-person view camera on the Skyron. From flight, the time is a fraction of that required by conventional methods. Time is saved when it comes to set-up, as the robot comes ready from its box as opposed to requiring set-up and deconstruction, as with traditional equipment. Lastly, the method addresses the cost of large inspection teams needing only a pilot and an inspector to conduct inspections. The duo can navigate assets quickly and efficiently while gathering accurate data. The method met the refinery’s needs for non-destructive testing inspection. Furthermore, it provides a shorter timeframe, costs less, and is safer for the inspectors.

Result

Figure 1. The four positions of Skyron on a pipe.

Figure 2. The Avesoft reporting software.

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In July 2021, Avestec performed predictive maintenance on three fundamental assets of the refinery. Skyron successfully inspected the shell/roof of a tank, horizontal/vertical pipes, and a flare stack. The robot demonstrated that it could eliminate human risk and decrease the time and cost of the inspection. Specific to this refinery, it performed UT measurements at any height, on various asset geometries, and on coated or non-coated carbon steel. On the first day, within 45 minutes of flight time, the robot conducted 155 UT measurements on the first carbon steel asset of the tank. It flew up two tank routes and measured one course on the tank’s roof. It also made 23 attachments, with an average of fewer than 2 minutes per attachment. The following day, the robot inspected an assortment of angles on pipes. It demonstrated that it can successfully measure different curved surfaces by attaching to horizontal elbows, vertical elbows, and horizontal pipes. It performed 94 readings within 35 minutes, on 17 attachment points. On the final day, the robot demonstrated its high-temperature rating and its steady performance at heights, and in wind. When flying up 130 ft in winds, it attached to an operation flare stack. It performed 27 UT measurements on two attachment locations in 8 minutes.

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Within three operation days and just 88 minutes of flight time, the robot took 276 UT readings on 42 attachment locations of hard-to-reach assets. The operation time included: nn Onsite permit acquisition. nn Set-up and safety checks. nn Pre-attachment in-flight preparation. nn Real-time data verification and recording. nn User comment. nn Detachment.

Advantages Wide range of use

The flying robot was able to attach to the targeted assets that presented challenges in terms of their shape, angle and positioning. This was best demonstrated in the pipe system with bottom, top, horizontal and vertical elbows, as seen in Figure 1. Skyron’s robotic arm rotated to the best position to attach to the measurement point.

Safety of operation

The inspector and pilot could avoid putting themselves in any dangerous position during operations, even when measuring a flare stack 130 ft above ground, while burning gas. The robot accurately measured the wall thickness of the flare stack, with no impairment from the heat. Using the line of sight and first-person-view video, the inspection team stood safely away from any potential hazards while conducting flight and measurements.

Secure contact to surface

When carrying out aerial robotic inspections, the greatest challenge is making consistent contact with an asset while in flight. The robot overcomes this challenge by using an attachment arm to maintain constant contact with the asset. Once attached, the UT gauge can perform scans in the same spot. Furthermore, from the secured position, its UT gauge can move within 2 in. x 2 in. to scan 25 different points to avoid immovable obstacles. This ability allows inspectors to ensure accurate UT readings from each attachment point.

Surface preparation

To provide accurate UT measurements for the asset owners, inspectors needed to overcome potential obstructions in UT readings. Specifically, these included dirt and corrosion, as well as unevenness of the surface, each of which would hinder accurate UT measurement. To manage these obstacles, the robot carries a surface brush and couplant reservoir. The surface brush removes physical particles, such as dirt and rust. A brushed and clean surface ensures that UT transducers couple properly to the surface and to produce accurate thickness readings. On the prepared surface, couplant gel fills any remaining air pockets and gaps between the transducer and surface, further improving the UT coupling that is required for an accurate measurement.

Unlimited flight time

Each asset to be measured at the refinery had multiple attachment points. The many points required to fly to, attach, and measure demanded that Skyron stay powered for a long time. It remained so for the entire time that it took to inspect the assets, as it was continuously supplied from the ground. Whereas most aerial robots have a limited supply of energy from their onboard battery, Skyron has an unlimited flight time by connecting to the Avestec Smart Tether System. The system generates and distributes power to the robot through a flexible tether cord.

Real-time data verification and recording

The reporting software AvesoftTM (see Figure 2) simplified the inspection process for both inspections and asset owners. The proprietary software performs data analysis and automates report generation simultaneously. A data presentation module has an intuitive interface for everyone involved with the inspection. The software offers asset visualisation and data tagging, images with interactive tags, and labels. Clicking them reveals information about each measurement. The visible and easy-to-understand layout helps inspectors to keep track of process and offers asset owners the optimal representation of data in real life, as seen in Figure 3. Avesoft eliminated the time spent tracking down data and enabled timely, well-informed decision making.

Conclusion The inspection successfully provided the refinery operators with accurate readings while delivering improvements upon conventional methods. In using the Skyron, the inspection duo performed contact-based measurement on a flare stack, tank and pipe. Inspectors were able to overcome a number of obstacles in order to provide accurate and timely inspections.

References 1.

Figure 3. Data visualisation.

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‘Washington: bp’s economic investment’, BP, https://www. bp.com/content/dam/bp/country-sites/en_us/united-states/ home/documents/where-we-operate/states/bp%20in%20 Washington.pdf ‘Refineries’, BP, https://www.bp.com/en_us/united-states/home/ what-we-do/production-and-operations/refineries.html ‘Overview of Maintenance’, Inspectioneering, https://inspectioneering.com/tag/maintenance

o most, passive fire protection (PFP), also referred to as ‘fireproofing’, remains a misunderstood subject. It carries a reputation throughout the hydrocarbon industry, best described as a grudge purchase, simply because it is required in some capacity but should never have to realise its intended use in a perfect world. It should be considered as an insurance policy. However, despite its extensive use to mitigate the thermal effects of fire following accidental releases, knowledge gaps remain regarding hazard analysis, the role of fire risk assessment, and material selection, which habitually feed the grudge narrative. Broadly speaking, PFP represents a passive barrier approach comprising various fire-resistant insulation materials or systems to protect safety and environmentally-critical elements (SECE),

including structural steel support structures (see Figure 1), from credible fire hazards following the initial outbreak. Fundamentally, PFP materials or systems function by limiting heat transfer from the release source, in effect delaying temperature rise in the protected members or separating elements to maintain, for a time equivalent period, stability, integrity and insulation to limit escalation, maintain the functional performance of critical systems, and to facilitate emergency response actions.

Hazard analysis Due to the processing, refining or storage of hydrocarbons, downstream and midstream facilities can produce a complex range of fire and explosion hazards. The extent of the release

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will determine the exposing fire scenario, the possibility for escalation, and the severity of the consequences. A prescriptive approach to defining the extent of coverage for PFP material use has commonly been used to address credible fire scenarios in the onshore process industry. For example, API RP 2218 can generally be considered

a prescriptive approach to addressing PFP requirements. API RP 2218 provides guidance on defining the extent of fire protection zones, the scope of coverage to SECE, the time equivalent durations or period of resistance, and single-member protection thickness determinations based on material response standards such as ANSI/UL 1709 for pool fire (non-pressurised release) scenarios using a defined maximum allowable temperature. In contrast, performance-based or inherent safe design practices employ a quantitative risk assessment approach to defining the exposed fire scenarios based on the nature of the process (pressure and temperature), inventory type, leak release rates, and the total inventory at risk in order to determine design accident loads. A mitigation effort is more wholesome, and takes engineering controls – such as EDP, ESDV, drainage, isolation and plant layout – into consideration when addressing the requirement for PFP to SECE. Implementing performance-based design methods will require early engagement in the FEED stage to realise the potential optimisation benefits of such schemes. Regardless of the approach, failure to adequately define and assess the role of PFP materials in the development of risk assessments may lead to the lack or excessive use of PFP materials on SECE.

Developing PFP performance requirements for structural steelwork Once the requirement for implementing a PFP measure to mitigate a fire hazard has been identified, the performance requirements and specification development can be similarly addressed using either a prescriptive approach or an optimisation approach through engineering analysis. The performance of any PFP material used to protect SECE that has been identified to be protected from credible release scenarios is based on the following considerations: nn Exposing fire type – pressurised, non-pressurised or combination releases. nn Period of resistance – total duration of the exposing fire, or the time equivalent at which failure of a protected member should not occur. nn Critical core temperature – the maximum allowed temperature vs time equivalent to ensure that sufficient strength and stiffness remains in the protected member to its capacity.

Figure 1. Structural steel fire protection (top: epoxy intumescent; bottom: lightweight cementitious).

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Published fire test standards do not represent natural fires. However, they do provide reproducible methods to evaluate PFP performance and the thermal response of the protected substrate over a time equivalent duration. Test standards such as ANSI/UL 1709 are commonly used and specified to evaluate PFP material response to simulated pool fires using the rapid rise time-temperature curve and prescriptive acceptance criteria, including maximum allowable temperature. For jet fires, a common approach is to use ISO 22899-1, as tested in Figure 2. Generally, API RP 2218, which is widely adopted in the downstream and midstream world, has defaulted to a single protection thickness approach based on a member size of a W10x49 for an equivalent time, regardless of utilisation and thermal heat sync of the member to be protected. The single

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protection thickness approach may well be applicable in members with a greater thermal mass than the tested section. Yet it remains important to question whether this qualifies as excessive use of PFP, and if the grudge is being fed without cause. The concept of section factor can be used to determine the protection thickness of a PFP material for a given steel shape vs maximum allowable temperature for a defined period of resistance. Section factor is a measure of the rate at which a steel section will heat up with energy. A steel section with a large surface area will receive more heat than a smaller surface area. Additionally, the greater the volume of the section, the greater the heat sink. What this means is that a small thick steel section will have a slower rate of temperature increase in a fire when compared to a large, thin one, and as such will require less material to be applied while still achieving the exact performance requirements, as illustrated in Figure 3. This method can be considered in both prescriptive and performance-based approaches. Some of the benefits of reducing PFP protection thickness for project stakeholders – but still mitigating the risk of the identified hazards – include the following: nn Material and labour cost savings. nn Schedule improvements. nn Reduction in applied weight per member surface area. nn Reduction in scaffolding and transportation costs. nn Reducing embodied carbon emissions. Although reducing emissions is not directly related to mitigating fire hazards, applying a protection thickness

method through regression analysis and the section factor concept may result in less material being produced, manufactured and shipped, thus providing a sustainable approach. Additional optimisation efforts that are performance or engineering-based can further help to rationalise the extent and use of PFP to mitigate process hazards above and beyond what has been discussed, including modelling, structural response, and critical temperature assessment based on utilisation to capacity redundancy analysis, etc. There is still room for entertaining both approaches when evaluating prescriptive and performance-based design. For example, depending on the process and equipment involvement, an asset owner may find it reasonable to assign a prescriptive approach to one portion of the process while focusing on regression analysis for a part of the project. This would deliver some benefits that would be meaningful if to address current commercial and economic circumstances. What is needed is the technical justification for such an approach. Additionally, when large global projects started moving significant modules and equipment overseas and far away from operating sites, a complete commercial evaluation had to take place for consideration well outside of just the material itself. The assessment included the total weight of coated steel, transport cost, site considerations – including access – and other things related to material selection. Other items to consider are how materials would survive in the long-term operating environment. For example, when considering a low-probability event, how would materials perform in these environments and continue to provide fire and thermal protection?

Conclusion

Figure 2. ISO 22899-1 PFP material testing.

The shift from grudge to gratification for PFP materials can be realised. It takes time, effort and early engagement with subject matter experts and material manufacturers to develop fit-for-purpose solutions to meet the hazards’ performance requirements optimised to benefit all stakeholders for a life in service. The gratification is that the most optimised approach is taken, achieving optimum efficiency. The commercial impacts of this are measured not only in the material itself but in all the related items that accompany it. So, where else can we take this approach? Can other elements in projects be optimised and made more efficient? Perhaps optimisation provides a starting point, but we should challenge ourselves and consider other areas where these efficiencies can be achieved. Time will tell, but we certainly have a way forward that results in some real solutions for now.

Bibliography • • •

Figure 3. Epoxy intumescent paint – protection thickness vs MAT of 538°C for 120 minutes of resistance.

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• •

API Recommend Practice 2218, Third Edition, Reaffirmed, ‘Fireproofing Practices in Petroleum and Petrochemical Processing Plants’, (March 2020). ANSI/UL 1709, Fifth Edition, ‘Standard for Safety for Rapid Rise Fire Tests of Protection Materials for Structural Steel’, (24 February 2017). FABIG Technical Note 13, ‘Design Guidance for Hydrocarbon Fires’, (September 2014). Energy Institute, First Edition, ‘Guidance on Passive Fire Protection for Process and Storage Plant and Equipment’, (March 2017). PFPNet, Issue 01, ‘A Guide to Developing a PFP Scheme for a Hydrocarbon Facility’, (January 2020).

Michael Jones, Watlow, USA, explains the value of arc flash management of large electric process heaters in order to minimise the risks of fire and/or injury.

hile larger medium-voltage process heaters are relatively new to hydrocarbon processing, the safety issues surrounding medium-voltage equipment are well known. Arc flash events are a prime example of a rare but potentially-deadly situation that can be mitigated with the right technology. As electric process heaters become a popular alternative for larger applications that have historically utilised gas-fired heaters, it is important to look at the ways in which they incorporate arc flash mitigation features. There are certain risks associated with the use of medium- or high-voltage equipment for industrial applications. Arc flash is an example of a well-known electrical risk that requires certain best practices to be followed in order to minimise damage and injury. When a new piece of medium-voltage equipment is developed, special attention should be given to such risks. This is certainly the case for large electric process heaters, which are becoming more popular in hydrocarbon processing applications.

The risk posed by arc flash An arc flash occurs when there is a short circuit in a system (due to, for example, a dropped tool, build-up of corrosion or conductive dust, or the presence of pests). If the voltage is high enough, and if there is a HYDROCARBON 43

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path to ground or a lower voltage, the insulative properties of the air are overcome, resulting in the formation of an arc. Arc flash events can lead to significant damage. As the energy release increases, it can cause fire and injury. If the energy release is high enough, molten conductor metal and high-pressure plasma energy can escape from the cabinet, posing a risk to personnel. The potential arc flash energy is determined by several factors: equipment voltage, available current, and the duration of the event. As the equipment voltage increases, the potential for arc flash hazards also increases. Low-voltage systems operating below 400 V do not have the energy to cause a significant arc flash hazard. Equipment operating at voltages between 400 – 600 V can cause arc flash hazards, but their capacity to cause massive energy release is limited. Equipment operating at medium voltage (above 600 V) has a high capacity for energy release. The available current is determined by the capacity of feed equipment upstream. While it may be practical in some cases to reduce the potential arc flash energy by limiting voltage or current, overall project cost can make this difficult. This makes limiting the duration of the event the most practical approach for reducing energy release.

Figure 1. Arc-resistant cabinets do not reduce the

amount of energy released during an arc. Instead, the heat and blast are routed to a safe area.

Decreasing the duration of the arc event also minimises the area of damage. The area of impact is not limited to the explosive blasts. The arc flash produces intense heat and light energy. People in the vicinity of the blast can be injured from these effects, even if they are not directly exposed to the explosion. Equipment surfaces can absorb the energy and experience high temperatures from the radiant energy, causing damage and requiring repair. Although arc flash incidents are relatively rare, their potential for damage, injury and death make them a major concern. Some estimates put the incidence of arc flash events roughly between 5 – 10 per day worldwide, or 3500 per year. According to a 2021 article in the journal Safety, there were over 2000 recorded hospitalisations in the US due to electrical injuries, including arc flashes. Of these, 1900 were non-fatal and 166 were fatal.1 Although the article did not qualify fatalities in terms of whether they were due to arc flashes or other events, it is clear that arc flashes are on the more lethal end of the spectrum.

Are there special risks with regard to arc flashes when it comes to process heating? The answer to this is both ‘yes’ and ‘no’. On one hand, concerns about decarbonisation, automation and safety have driven many to replace gas-fired heaters with larger electrical heaters (> 1 MW).2 Medium-voltage process heaters are relatively new to some of these applications, thus represent a potential new source of risk, and manufacturers of these heaters must be aware of that risk. On top of that, many applications use arrays of large megawatt heaters, connected to multiple panels. This drives the need for a solution that can isolate the specific panel(s) where arc flash occurs, isolating the shut down from the main breaker/feeder and other equipment where possible. On the other hand, arc flash events are well understood, as are the strategies for reducing their effects. An understanding of these strategies should be ‘built in’ to any technology for process heating.

Reducing the effects of an arc flash event Generally speaking, there are three main strategies for reducing the effects of any potential arc flashes that could occur with a piece of equipment: n Increasing the distance from the potential source of an event. n Reducing the available fault current. n Decreasing the duration of the event (i.e. how long the arc itself exists).

Figure 2. Arc-resistant cabinets are heavily reinforced and route the heat and

blast out of the cabinet. Arc mitigation technology reduces the duration of an event, and thus a smaller blast is generated.

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Ideally, all of this could be used in combination to ensure maximum safety, but this is often not practical when considering

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overall project cost. That said, the duration of the event is the most practical influencer to reduce and has the largest impact on the total amount of energy released. Reducing the overall fault clearing time is often the best, most direct way to reduce arc flash hazards. This point can be illustrated through a comparison between two current approaches to limiting the damage wrought by arc flashes: arc-resistant cabinets, and arc-mitigation technologies. Mitigation technologies make more sense both economically and from a safety perspective, and thus should be incorporated into designs for and around medium-voltage process heaters and similar equipment.

Arc-resistant cabinets The idea behind an arc-resistant cabinet is to reduce exposure to arc events by encasing the system in a metal-clad cabinet with a venting system. Typically, the doors of the cabinet are the point of failure in an arc event: rapidly heated air expands and builds up pressure inside the cabinet, eventually causing the doors to blow open and expose those nearby to heat and blast. With an arc-resistant cabinet, the flash energy (more precisely, the heated gas and pressure) is redirected through a duct near the top of the cabinet. When the doors are closed and all covers are installed correctly, arc-resistant cabinets reduce the energy to which people and other pieces of equipment are exposed. That said, arc resistance does not actually limit the energy from the event itself – it merely redirects it. There can still be substantial damage to the system itself, as well as significant risk. Perhaps the greatest drawback is the fact that the system must be closed for the arc-resistant cabinet to work; it will not work, for example, with the doors open. This is a problem, as many arc events occur during maintenance, precisely when the doors are open. An arc-resistant cabinet will not afford any additional protection in these cases. Of course, there are other issues as well: the size and weight of the cabinet, the certification needed (ANSI C37.20.7) and, naturally, the overall cost.

Arc flash mitigation technologies Arc flash mitigation technologies (hereafter arc mitigation) take a different approach; instead of redirecting the energy from the event, arc mitigation seeks to reduce the energy of the event itself by limiting its duration. This is done by detecting the arc flash early and automatically tripping the appropriate circuit. There are two ways in which this can happen – sensing current (referred to as current arc mitigation), or sensing light (referred to as optical arc mitigation). If an arc event occurs, the light emitted by the arc within the enclosure builds quickly. That light can be detected by a photoelectric receptor or length of fibre optic cable, even in the early stages of the event. When detected, the signal is then sent to a protective relay, which trips the breaker automatically, without the need for human intervention. This approach is optical arc mitigation. June 2022 46 HYDROCARBON ENGINEERING

One of the main advantages of this approach is that it is independent of the actual magnitude of the arcing fault current. This allows the system to detect arcing in an early stage of its development and trigger the break sooner, which in turn limits the duration of the event and hence the total energy produced. Current arc mitigation uses current transducers to sense an increase in current produced by the arc. If the transducers are not sized correctly, they may not shut down the system rapidly, or may be unable to clear the event. Even when current transducers are properly sized, optical arc mitigation offers an advantage in clearing time over current arc mitigation. Optical sensing can reduce clearing time and arc energy release by 50% over current transducers. However, a current arc mitigation is preferred over having no arc mitigation components integrated into the control system. If no arc mitigation is integrated into the control system, upstream equipment with undetermined clearing time will need to be configured to respond to an arc event. Unlike the arc-resistant cabinet, arc mitigation also reduces damage to equipment (instead of simply redirecting the energy that escapes the cabinet). It can function even when the doors are open and maintenance is being performed, and it does not require the heavy metal-clad cabinet with its larger footprint. For example, in the POWERSAFETM system developed at Watlow for medium-voltage process heaters, sensors can be placed within the medium-voltage compartments of the thermal controller, whether using SCR node and/or single contactor control. The panels in the line-up are protected by a feeder/breaker. Up to 12 heater circuits may be run from a single feeder/breaker, with each heater circuit controlled by its own switching circuit. When the sensor senses an arc flash event in any compartment, the feeder/breaker will shut down the line-up to limit damage caused by the arc.

Conclusion Again, arc flashes are well understood, and industries using medium-voltage equipment should already be aware of strategies to increase distance from such events, reduce current, or decrease the duration of the event (as well as the appropriate use of personal protective equipment [PPE]). As medium-voltage process heaters become more popular in hydrocarbon processing, they too must be designed with safety in mind. Arc mitigation represents the best approach to decreasing the energy released by reducing the duration of the arc flash event, minimising the damage and risk involved. Additionally, such technologies can achieve these things with minimum footprint and project cost.

References 1.

CASEY, T. W., MASON, H. M., HUANG, J., and FRANKLIN R. C., ‘Shaping Frontline Practices: A Scoping Review of Human Factors Implicated in Electrical Safety Incidents’, Safety, (2021), https://doi.org/10.3390/safety7040076 LONG, D., and JULIANO, R., ‘Electrification and Medium Voltage Process Heaters Systems’, (2022), https://de.watlow.com/blog/ posts/electrification-and-medium-voltage-process-heatersystems

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Salem Bouhairie and Syed Haq, Heat Transfer Research Inc., discuss how airflow patterns within air-cooled heat exchangers (ACHEs) degrade performance.

ir-cooled heat exchangers (ACHEs) at hydrocarbon processing or power plant facilities occupy large areas. Non-uniform airflow patterns and non-ideal site installation can affect overall plant performance, sometimes significantly reducing output. Industry guidelines addressing these problems are limited, and in-house rules of thumb are not consistently applicable. Heat Transfer Research Inc. (HTRI) conducts research on many ACHE operational challenges, revealing complexities in phenomena on the airside. Some issues of concern include the following:

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n Non-uniform approach of air into the ACHE inlet is the most common cause of deficient fan performance, and is often associated with obstructions from buildings, pipelines, or ground equipment. n Wind can direct the heated exhaust air away from or back into the unit. Some plant sites cannot avoid installing ACHEs in known wind corridors. n Hot air recirculation, a form of airside maldistribution, is difficult to predict. It creates temperature pinches that reduce mean temperature differences and subsequently the heat transfer potential of the tubeside process to reject heat to the air.

This article discusses some of HTRI’s findings from collected field data, thermal plume visualisations, and computational fluid dynamic (CFD) simulations. The analysis helps to explain the impact of these phenomena on ACHE operation, and suggests some solutions. Most ACHEs designed using American Petroleum Institute (API)1 or Heat Exchange Institute (HEI)2 guidelines use fans operating as forced-draft units, pushing air across the tube bank. Units that are more efficient operate in induced-draft (or natural-draft) configuration, where fans pull air across the bundle. Natural-draft ACHEs, which use thermal-buoyancy-driven airflow to cool the process, are

increasingly used. These units cost less to operate since they do not require fans or motor-drive machinery. Additionally, the number of environmental permits authorising the use of natural-draft units to reduce noise has increased. Using air to cool a tubeside process is thermally inefficient since air has a low thermal conductivity. The common solution is to design ACHE tube bundles with enhanced surfaces: high-fin tubes help to overcome airside thermal resistance under ideal air ambient conditions. However, operators face several challenges during off-design air-cooling when trying to meet product demand. Compared to tubular or plate-type exchangers, ACHEs require much HYDROCARBON 49

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larger amounts of site area for the same processing capabilities. A typical bank of ACHEs, as shown in Figure 1 (bottom), is often located in non-optimal arrangements due to plant plot limitations. The non-ideal site installations predispose ACHE banks to non-uniform airflow patterns that can significantly reduce overall performance. Guidelines are very limited in addressing airside problems, leaving industry to use in-house rules of thumb that are not consistently applicable. At the HTRI Research & Technology Center, research conducted on the air-cooled unit (ACU), an API-661 unit

shown in Figure 1 (top), measures ACHE performance and the adverse effects of non-ideal airside phenomena such as: nn The non-uniform approach of air into the ACHE inlet. nn Wind effects. nn Hot air recirculation. Several thermocouples and static pressure sensors measure the temperatures and airflows across the bundle. The ACU’s weather station measures various ambient psychometric properties (wet and dry bulb temperatures, humidity, and outdoor pressures) and wind velocities (magnitude and direction). The ACU provides a unique opportunity to tune CFD models to test the measurement of an API 661-compliant unit.

Non-uniform air approach

Figure 1. Side view of a single ACU bay (top) arranged as a bank of forced-draft air coolers (bottom).

Figure 2. Profile of inlet air velocity with fan 12 m above ground.

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The non-uniform air approach into the ACHE intake is the most common cause of deficient fan performance. API 661 provides airside design recommendations for controlling approach and discharge air by considering fan height ground clearance and air discharge kinetic energies.1 Non-uniformity develops due to a combination of ground resistance on approach air and change from a horizontal approach to a vertical intake, resulting in uneven flow distribution at the fan impeller. Duvenhage and Kröger conducted several experimental and numerical studies on ambient approach air without wind.3 They concluded that assuming uniform air velocity at the inlet side of an ACHE is inadequate when the mass flow rate exceeds a critical value for a specific fan height above ground (see Figure 2). Some solutions to reducing the effect of a non-uniform air approach include draping the ACHE sides with porous windscreens below the plenum. The windscreens help to reduce the vertical gradient of the approach air. Blockages around the ACHE may also cause a non-uniform air approach. These blockages include support structures, header piping, fan motor, or even adjacent fans in an ACHE bank. HTRI investigated the effect of blockages based on the open approach area available for air to enter the ACHE perimeter. As a general trend, when the open approach area around the ACHE reduces, the intake airflow reduces. This useful rule of thumb accounts for blockages around an ACHE. However, it does not present the complete picture. In-depth analysis is required to realise the potential performance reduction caused by the blockages. HTRI’s CFD simulations predict that blockages cause flow maldistribution across the ACHE. Reduced airflow to the fans, which results in its starvation, can have detrimental effects on the life of the fan. In extreme cases of blockages, the local velocities coming into the ACHE are three to four times faster than the unobstructed flow.4 Such variations can place large mechanical stresses on fan blades, which are essentially cantilevers. The damage to the fans can vary, depending on the location of the blockage. Figure 3 shows velocity distribution contours around the HTRI ACU (top) with unobstructed flow with some pipe blockage (bottom left), and with three sides blocked (bottom right). With three sides completely blocked, not only are the velocities much higher, but the minor blockage of the piping also has a much more significant effect. Additionally, Fan 2 near the open (red) side experiences a completely different flow profile compared to the Fan 1 at the

opposite (blue) side. Flow maldistribution between the ACU’s fans can be as high as 30% of the total ACHE airflow.4 Flow maldistribution inevitably leads to temperature maldistribution. A significant temperature difference is observed between fans’ cells, when the flow maldistribution between fans is greater than 20% of the total flow. The maldistribution can lead to tube bundle hot spots and temperature pinches, resulting in underperformance of the ACHE. In the long-term, this can lead to finned tube degradation, and the ACHE may require servicing sooner than anticipated. To reduce non-uniformity due to external blockages, it is advisable to ensure that the surrounding equipment is placed in such a way that flow behaviour between fans is as symmetrical as possible. In the event of existing blockages, periodic inspections of the ACHE need to be conducted to check for possible deterioration of the equipment.

Wind effects For forced-draft units, wind generally has a negative effect on fan performance. High wind speeds increase the velocity pressure of the inlet air stream of the ACHE. This in turn increases the static pressure loading on the fan, causing the fan’s operating point to shift. The result is a higher operating static pressure at a reduced airflow rate. Typically, the fans that are subjected to the greatest degradation in performance are those on the leading face (upwind) of the ACHE.2 For natural-draft units, high crosswinds flatten the plume height, HalfPageBrandAd_Apr2022_final.pdf 1 5/9/22 reducing the airflow through portions of the10:56 heat AM exchanger

Figure 3. Comparison of an ACHE (top) with unobstructed flow (bottom left), and with three sides blocked (bottom right). bundle. Figure 4 shows that an increasing wind speed can hamper ACU duty. Some common solutions to reducing wind effects are to install windwalls above the plenum deck, and windscreens below the deck. Windwalls separate the discharge air stream of

the inlet air stream. Chimneys should be mounted on natural-draft air coolers to increase the buoyant draft and subsequently the duty of the ACHE. If ACHE banks are not yet installed at a plant, it is better to align the long side of the ACHE banks with the wind direction rather than the short side. The air intake at the long end of the bank is farther away, reducing the chance of the bank receiving wind-blown hot air exhaust.

Hot air recirculation The most difficult non-ideal airflow to predict is hot air recirculation. Some of the discharged hot air can travel downward and re-enter the cooler, as shown in Figure 5. In fact, neighbouring ACHEs competing for the air supply, with and without wind, can induce recirculation. Forced-draft ACHEs generally have lower exit velocities than their induced counterparts, and are therefore more prone to hot air recirculation. Airside recirculation is aggravated by several factors:5 nn Poor inlet aerodynamics. nn Weak outlet plume velocity. nn Strong multidirectional crosswinds. nn Alternate fan on/off operation. nn Proximity to other air coolers, equipment, piping, or buildings. nn Low ground clearance.

and airside kinetic energy that can help minimise airside maldistribution.1 However, following these guidelines without understanding the physics behind their intent does not always prevent hot air recirculation. Detailed information on the local flow and thermal maldistribution throughout the air-cooler tube bundles is often unavailable. In the HTRI ACU, thermocouples installed at the fan inlet help detect whether temperatures are greater than ambient, and confirm hot air recirculation. HTRI also performed CFD simulations of hot air recirculation, which revealed that recirculation increases with greater heat exchanger length and wind speed.5 Some solutions to the recirculation problem include using induced-draft ACHEs where their fan ring discharges exhaust higher and farther away from the inlet, positioning banks of ACHEs far apart, and having high ground clearance. It should be noted that some ACHEs deliberately induce ‘warm air’ recirculation through louver controls to deliberately warm tubes and prevent bundle freeze-up (warm air recirculation) in cold climates. HTRI will use future experimental measurements in conjunction with these CFD simulations to improve the prediction of hot air recirculation and improve ACHE design and operation.

Conclusion

ACHE designs should consider ambient air non-idealities to help ensure reasonable and cost-effective unit performance. API 661 provides recommendations for fan coverage, HTRI has studied many of these problems through plenum depth, fan-cell partitions, approach and exit velocities, experimental testing and numerical simulations, with the aim of improving ACHE performance. Non-uniform air approach with and without blockages can result in intake flow maldistribution, which can be resolved with windscreens or symmetrical placement of surrounding equipment. Wind effects can increase fan static pressure and reduce natural-draft airflow, but windwalls, chimneys, and ACHE bank alignment with the plant-site wind corridors can alleviate these problems. Several factors can aggravate hot air recirculation, making it most difficult to predict. However, some Figure 4. Wind speed effects on duty for ACU with a 1.2 m (4 ft) solutions include using induced-draft ACHEs, adding chimney. sufficient inter-bank ACHE spacing, and ensuring good ground clearance. In addition to this, ‘warm air’ recirculation can be used to improve ACHE operation in cold climates. Overall, understanding irregular ACHE airflow patterns helps engineers to make informed decisions when modifying designs, by adding devices or adjusting operational approaches to improve air cooler performance.

References 1. 2. 3. 4.

Figure 5. Discharged hot air recirculating over the ACHE

perimeter and raising local inlet temperatures of outer bank fans.

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API STD 661: Petroleum, Petrochemical, and Natural Gas Industries – Air-cooled Heat Exchangers, 7th ed., American Petroleum Institute, (2013). Standards for Air Cooled Condensers, HEI-3087, 1st ed., Heat Exchange Institute Inc., (2011). DUVENHAGE, K., and KRÖGER, D. G., ’Plume recirculation in mechanical-draft air-cooled heat exchangers’, Heat Transfer Engineering, Vol. 16, No. 4, (1995), pp. 42 – 49. GANGULI, A., MARNER, W. J., WEIERMAN, C., and CHENOWETH, J. M., ‘AC-5 Airflow problems in forced draft air-cooled heat exchangers’, Heat Transfer Research Inc., (1986). BOUHAIRIE, S. A., ‘AC-17 CFD simulations of airside maldistribution around API air cooler’, Heat Transfer Research Inc., (2016).

Ilan Toledano, Wattco, Canada, outlines how batteries are fuelling the evolution of industrial heat technology.

early a century before the term ‘global warming’ was coined, heater technology was already moving towards electricity. Thomas Edison’s first electric heater was released in the 1880s. At that point, it was more of a stepping stone. The technology essentially used lightbulb elements, a then-recent invention, to generate heat. It was not particularly efficient, and coal was generally used to create the electricity that powered it. This was not very green nor practical. By the early 1900s, Albert Marsh had expanded on this idea to create infrared heating elements. This formed the basis for modern electric heaters for residential and industrial use. The first evolution of electric heaters left a lot to be desired. However, it was an important stepping stone in the process of delivering the efficient, reliable, and low-emission technology that is now seen in heat technology. Even before government and social pressure started moving industries towards electric heating for environmental reasons, there was already a transition towards electric heaters. They offered greater performance and longevity, consistent quality, and lower operating costs. With a

renewed emphasis on carbon emission reduction, this transition to electricity is growing even stronger. Batteries are the next stepping stone on the route to greener and more efficient power for industrial heating.

The evolution of industrial heat technology The energy industry is in a state of flux. Old sources of energy, such as oil and coal, are becoming more expensive, less available, and are having a measurable impact on the environment globally. These non-renewable power sources have been the go-to solution for decades. While new solutions are emerging, the transition to renewable and lower-impact energies presents a big challenge. Batteries are becoming an important part of the solution.

Compatibility with electric heaters One of the valuable capabilities of batteries in transitioning energy sources for electric heat technology is their compatibility. HYDROCARBON 53

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Modern electric heaters are easily set up to receive power from batteries. Perhaps the most recognisable example of this comes from Tesla’s recent foray into heating, ventilation, and air conditioning (HVAC). Elon Musk’s work on producing high-efficiency heat pumps is targeted to transform residential heating systems. Battery-powered HVAC systems reduce carbon emissions and increase efficiency for savings in the home. The heat pump technology relies on Tesla’s battery advancements and their compatibility with electric heating systems. While the focus is on residential use in this early stage, the future aim is to scale into the industrial sector.

Remote power access Electric heat was not a viable option in remote areas with limited or no access to a power grid. Heat technology either relied on inefficient combustion heaters or had electricity generated through emission-producing fossil fuels, neither of which favours the direction in which this technology should be heading. Batteries provide a solution for remote locations and areas with unstable power grids. No longer are generators or other fossil fuel alternatives a necessity; battery technology has advanced to hold a charge longer, and deliver more power. This makes it reliable for delivering power when there is an outage or lack of reliable access. Because batteries are already compatible with electric heaters, they offer a good jumping-off point for transitioning to greener power, even in remote locations.

Renewable energy Renewable energy sources such as wind and solar have been a target for decades. Recent years have witnessed their technology finally evolving to meet the intensive energy demands of modern industry. In some locations where wind or solar is consistent enough over long periods of time, these alternative energy sources can even outperform traditional options. Batteries play two important roles in transitioning heat technology to these energy sources. The first role falls back on their compatibility. Batteries use power generated from solar and wind sources and deliver them to electric heating systems. This reduces the need for purchasing new heating equipment, so long as electric heaters are already in place. The second is that batteries actually help to improve renewable energy generation. A longstanding challenge with sources such as solar was that they did not have a good storage option. Solar panels could generate power all day long, but could not use that power in the evening or on cloudy days. Any unused energy had to be sold back to the grid, or was lost. Advances in battery technology have helped to make renewable energy storage a reality. Working in conjunction with heaters, batteries could store energy and keep it usable for longer. This reduced the need for other energy sources during off-peak times, and limited lost energy. Altogether this is helping to make renewables a viable option for many industries.

Carbon capture Even if all industries switched to renewable energy overnight, a carbon emission problem would still exist (albeit a significantly June 2022 54 HYDROCARBON ENGINEERING

reduced one). Billions of tons of carbon dioxide (CO2) have been pumped into the air, at an increasing pace. Whilst this is happening, the transition to green energy is still moving fairly slowly. A solution is required to reduce these emissions while the move to renewable energy is underway. One of the biggest focuses for tackling climate change in this transitory phase is carbon capture. Carbon capture aims to pull carbon out of the air, store it, and reuse it. This has a double effect. It reduces the amount of carbon that has already been released through capture and storage. Then, when it is reused, new carbon is not generated. This should help to reduce overall output during a multi-decade transition phase. Electroswing batteries are used with heat technology to capture and reuse carbon emissions. They function using a mixture of thermal and electrical energy; offer cheaper sequestration when pulling carbon from the air; and even have favourable comparisons to the cost and effectiveness of capturing carbon directly at the production site, which is generally the most affordable and effective option.

Battery advances The adoption of lithium-ion (Li-ion) batteries transformed the understanding of what a battery could be. Again, Tesla is the most recognisable example of its use. The Tesla Roadster, a space-bound electric car, ran on Li-ion batteries. These batteries’ sheer power and storage capabilities made the electric car a practical option, as they overcame issues such as long charge times, short ranges, and low power. In just a few years after the Roadster’s release, it seemed as though every car manufacturer had their own electric options underway. Li-ion batteries come with challenges, though. They have their own issues with regards to environmental impact, especially when it comes to mining the materials. In addition to this, the materials are expensive, raising the price of products. Additionally, when operating at high temperatures, they are more volatile and flammable, with the possibility of chemical leakages. An alternative is Lithium-Ion-Phosphate (LFP) batteries, which still offer a good range but have significantly lower costs and greater stability. This helps to make them more affordable and safer. Improving Li-ion technology is just one example of the important work that is taking place in the battery world today. As batteries have proven their value in industrial heating, far more work is being done to find new battery-based solutions. One of the more recently adopted innovations is the iron flow battery, which can go through thousands of cycles with no degradation. This means greatly-improved battery life and reliability. Even with currently higher initial costs, they offer greater long-term value with a clean and reliable output. Iron flow batteries have lifespans exceeding double that of Li-ion. As such, they are poised to take over the number one spot soon.

Conclusion Battery improvement and innovations are occurring at an exponential rate. These improvements are already making them an ideal solution during the transitory period of switching from fossil fuel reliance to green and renewable energy sources. If these advances maintain their current pace, batteries may not just be a stepping stone for green heat technology, but rather its foundation.

Salim Akçaoğlu, Gökhan Özkan and Yavuz Bingöl, Tüpraş, Turkey, discuss how the company managed a battery shutdown under the challenging circumstances of the COVID-19 pandemic.

attery shutdown management is an important process behind the closure of all units in a refinery. Tüpraş recently carried out a battery shutdown at its Izmir Refinery, the purpose of which was to ensure maximum availability of the refinery at minimum costs, by maintaining sustainable performance and reliability with the principles of ‘doing the right things’ and ‘doing the right jobs’. Under normal circumstances, preparations for a battery shutdown of this capacity should start approximately 18 months in advance of the works to ensure excellent shutdown management. This process consists of six main steps, each of which includes specific tasks, outputs, and approval stages: n Determining the battery shutdown strategy. n Establishing the work scope. n Detailed planning and programming. n Carrying out the pre-planned works. n Execution of battery shutdown. n Carrying out post-planned works.

Milestones should be established to allow sufficient time for the planning and preparation of complex and long-term materials, specific resources, and technical constraints. Sufficient time should be allocated to the preparation phase. It is necessary to follow the turnaround management process for efficient and successful shutdown management. During the shutdown period, there are four important considerations: health, safety and environment (HSE), work scope, resources, and downtime. Normally, HSE, work scope and downtime are constant, while resources are variable. The aim of this article is to express how these four topics change and how they were managed under the unique circumstances of the COVID-19 pandemic. Turnaround methodologies, methods and practices are generally predictive and plan-driven. In a traditional approach, the needs, requirements and constraints of a turnaround are understood, and the plans are developed accordingly. Turnaround methodologies, especially for the HYDROCARBON 55

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battery shutdown period, have to be agile and flexible in order to cover all possibilities. The approaches used must change according to specific necessities, updated evaluations, changing work requirements, bottlenecks, and the circumstances of the pandemic. In these situations, agility is the main key benefit felt by teams who work collaboratively to determine and execute a shutdown’s need. At Tüpraş’ Izmir Refinery, modern approaches were implemented in certain steps. In summary, a hybrid approach was used to handle the specific needs of the project.

Strategic planning Strategy meetings, which would normally last for three months, were completed in a short period of two to three days. With the establishment of the battery shutdown preparation and execution team, steering committee approval of the teams was obtained. Normally, the periods for establishing the turnaround preparation

and execution team are different from each other. Since the period was too close to the battery shutdown, the formation of these two teams was adapted as one step, and coordinated in parallel. Under the confines of the pandemic, online meetings were held by organising remote-access, rotative groups. Based on the strategy, a kick-off meeting was held with the shutdown preparation/execution team and the strategy was explained. Battery shutdown commitments were formatted in a very short time, taking into account the collected data of a previous battery shutdown, which was reported nearly 20 years ago. As it was not clear how long the downtime would last for, due to both the pandemic and for economic reasons, the main strategic focus of the shutdown teams was to prioritise the work. The company chose to carry out works that required a full refinery shutdown as opposed to works that demanded the shutdown of individual units. Due to this uncertainty, an early start-up was a possibility as a result of the support from positive changes in economics and global demand.

Preparation of battery shutdown

Figure 1. Steps of excellent shutdown management.

Figure 2. Turnaround management process.

Figure 3. J factor matrix.

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The preparation of the work lists, in relation to the strategy of freezing of the scope according to the J factor, were completed in approximately one month. In addition to this, works within this scope were divided into four different categories and placed in order of priority. On the other hand, the daily report of work that was frozen during the work scope challenge was submitted to the planning/programming team. Subsequently, a detailed plan and programme was completed in one and a half months. While the work scope challenge continued, a shutdown and start-up calendar was created. Since the last battery shutdown had been 20 years prior, and there had been new additions to the units in that time, a number of meetings were held to determine the optimum shutdown and start-up calendar according to the new order. A work orders and shutdown programme was prepared and checked approximately one week before the start of the battery shutdown. In parallel to the preparation, the following steps were taken in the aforementioned one and half month period: n HSE strategy. n Budget preparation and approval. n Preparation of integrated project work packages and publication process for projects. n Contract strategy. n Preparation of temporary facilities (WC, scaffolding area, parking, work permit office, toolbox area, etc.) on the plot plan. n Preparation of risk assessments and method of statements. n Preparation of quality plan. n Deployment of contractors and PCR tests.

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n Training of contractors. nn Mechanical, energy, battery limits isolation and risk assessment (6000 flanges). nn Procurement (detailed materials and equipment studies for refinery shutdowns planned for the next years have helped long-term material supply for this battery shutdown). nn Risk assessment of additional work (identification of two focal supervisors, namely utilities and process units). nn Publication of eliminated works. nn Scaffolding and civil works. nn Installation of temporary lighting and power units. nn Mobilisation. As mentioned, the preparations for the battery shutdown were completed in one and a half months, despite the difficulties of the COVID-19 pandemic. Downtime and resources were constantly relevant to this battery shutdown. The work scope was variable. The key factor in keeping the human resources constant or limited in this context was the COVID-19 pandemic. Many precautions were taken in order to eliminate or minimise the contamination of illness. For instance, the areas where personnel had to be – for specific purposes – were expanded or split into more areas, such as permit to work rooms, and multi-purpose field points. Although all personnel completed periodic PCR tests, there was still some risk of contamination due to many

Table 1. Priority and category matrix Category Status 1

Certain tasks (legal requirements and HSE) and jobs with a financial return of more than US$100 000 in risk reduction costs

Jobs with a financial return of US$50 000 – 100 000 in risk reduction costs

Jobs with a financial return or risk reduction cost of US$10 000 – 50 000

Jobs with a financial return or risk reduction cost of less than US$10 000

Figure 4. Steps of battery shutdown management.

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different disturbances from daily life. As such, the optimum number of personnel worked during these challenging periods at the refinery. In addition, social distancing and other precautions had to be taken. The estimated number of personnel selected according to the downtime, scope freeze and the pandemic was periodically managed and revised according to the programme.

Execution of battery shutdown When the battery shutdown process commenced at the Izmir Refinery, the capacity of the programme was 385 253 manhours. When it came to the end of the battery shutdown, the capacity of the programme had reached 432 132 manhours. 59% of the actual programme belonged to the projects, and 41% to the maintenance works. During the procedure, 6000 flanges were opened and closed; 29 264 certified and non-certified work permits were organised; and 993 HSE reports were written on the system. Every morning, toolbox meetings were held in the field and the progress of each day was followed up with a detailed report via an online meeting at the end of the day. The detailed report included the following: HSE report, current shutdown and start-up calendar, progress graphs, project progress, lost time, critical paths progress, flange quality reports, additional works report, cleaning site report, inspection reports, meeting notes, etc. Additional work was managed by two focus supervisors, a turnaround (T/A) leader, and a steering committee. At this point, the comparison of the works in the current category with the additional works was made by this team for two months. The work prioritisation list was revised 28 times in total during the downtime, which lasted for approximately two months. The goal was to cover and complete all scope and inevitable additions that came up during the battery shutdown period until the start-up date, as scheduled. Planning, execution and field teams kept up with this, and the ‘to-do’ list was revised 28 times. If additional work was not affecting the shutdown in terms of budget and downtime, these demands were evaluated between the focus supervisor and the T/A leader. There were two groups for examining the additional works. One was the maintenance department; the other was the steering committee. The maintenance group management department was responsible for budget and downtime, while a steering committee was responsible for high-priority cases. During the battery shutdown, Tüpraş successfully managed to implement the HSE precautions taken during the COVID-19 pandemic period. These precautions were as follows: preparation of contractor pandemic documents and training, PCR tests, daily health surveys,

building additional entrance-exit gates, and organising shuttles according to pandemic conditions. In addition to this, many multi-purpose rooms and points, including places to eat and drink, were created to ensure that social distancing was in place. The COVID-19 pandemic has initiated changes in business and habits, and companies have taken new actions to create opportunities for maintenance and investment needs. In keeping with this, during this battery shutdown, Tüpraş completed its scheduled maintenance activities and laid the foundations for new investments. The company also carried out critical paths with an engineering approach: the modernisation of a combined heat exchanger (100 t), sulfur waste heat boiler (80 t), and reactor effluent-hot feed exchangers (100 t) with jacking-skidding, gantry and hydraulic jacks. Further modifications were changing flare header pipelines; re-tubing a waste heat boiler; changing cooling water pipelines; civil works of the sulfur area; underground pipeline works; maintenance of flare tips; revamp of catalytic cracking units; changing the stand-pipe in fluid catalytic cracking units, etc. As mentioned, preparations for a battery shutdown of this capacity should start approximately 18 months in advance. The methodology shifted during the period and was managed by agile approaches. One of the hardest challenges experienced was ensuring that personnel were able to work effectively, as protection methods were not clear and defined.

Conclusion At the end of the Izmir Refinery project, the report and presentation of the shutdown was prepared and shared with the execution team during an online meeting. In addition to this, video content was specially prepared to record the challenges and some experiences. Another final meeting was conducted with all refinery and contractors’ personnel to openly evaluate the battery shutdown period. The key performance indicators (KPIs), critical paths, best practices, and improvement areas were shared and discussed by examining each department and the team as a whole. The main goal of this meeting was to benefit and record the experiences for the next shutdowns, whether it was a success or not. As such, the company’s organisation and standards continue to improve. As a team, battery shutdown was managed under the special circumstances of the COVID-19 pandemic. Work was successfully carried out in a total of 432 132 manhours, with an average of 1700 employees and 50 contactors per day. The pandemic has led to many transformations. With its onset, Tüpraş effectively implemented precautions to establish a safe working environment. During this period, the Izmir Refinery benefitted from this newfound flexible structure and agile approach. Considering the unknown conditions brought by the pandemic, the company broke new ground by executing a battery shutdown, which was an important experience.

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Brad Cook, Sabin Metal, USA, examines what is happening within the world of platinum group metals (PGMs), and explains the importance of responsible recycling.

re you reading through contact lenses or have you had LASIK surgery? Have you shaved any part of your body this week? Do you ever make use of a cell phone, tablet or computer? Is your home insulated with fibreglass? Have you travelled by plane, car or boat recently? Have you ever taken ibuprofen? Do you know anyone who has a pacemaker? Ever fertilize your garden? Ever use a sticky note? If you answered ‘yes’ to any of the above, you have platinum group metals (PGMs) to thank, and at least a few creative minds somewhere in history. As of 2020, nearly 25% of all consumer products either contain PGMs or are made using PGMs. To get an idea of its rarity, consider that all of the platinum mined in human history would fit inside a four-bedroom house. That may sound impossible, but 1 m3 of platinum weighs over 21 t. A 20 l bucket of pure platinum would weigh approximately 430 kg. This article will discuss the supply, demand and recycling of PGMs; examine what is happening within the world of PGMs and the related effects on the market; and review how precious metal users and suppliers can best coordinate for mutual success.

PGM demand Figure 1 illustrates platinum demand by application over the last century. Demand for all PGMs has been growing steadily for decades. The 1970s saw the introduction of automotive catalysts, and at that time they all used platinum. In the mid-1990s, combustion engine manufacturers switched their convertor catalyst from platinum to palladium-based, then in 2001 they switched back. In a nutshell, roughly one-third of the platinum mined today is used for catalytic convertors, another third for industry (petroleum and petrochemical refining, chemical production, fibreglass, etc), and the rest falls under jewellery and investment.

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Figure 2 shows palladium demand by application over the last 100 years. Approximately 90% of all palladium that is above ground is riding around in the catalytic convertors of automobiles. Therefore, since the 1970s, the main ‘driver’ of both platinum and palladium has been the automobile market – initially in the West and more recently with the expansion of the automotive catalytic convertor in the emerging world. According to ScotiaBank, 2020 auto sales were off by over 15%, and totalled just under 64 million units worldwide.1 In 2021, there was a slight recovery to 67 million, which is still 8 million units short of 2019 levels.

PGM supply In terms of supply, South Africa produces over 70% of the platinum and almost 40% of the palladium annually, and these mines continue to get deeper and deeper every year, while the ore quality deteriorates simultaneously (see Figure 3). In addition to this, the challenges of labour issues, water supply, and power shortages persist in this region.

Jewellery Investment Autocat Industrial

Figure 1. Platinum demand by application.

Jewellery Investment Autocat Industrial

Figure 2. Palladium demand by application.

Palladium

Platinum

Figure 3. Mined supply (million ounces troy).

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Russia accounts for approximately 15% of platinum production and roughly 50% of palladium production annually. On 8 April 2022, the London Platinum and Palladium Market (LPPM) announced that it has suspended the two Russian refiners on its ‘Good Delivery’ list. This means that, as of that date, most of the fine precious metals from Russia will no longer be considered ‘Good Delivery’. The New York Mercantile Exchange (NYMEX) has followed suit, and the Osaka Exchange is considering similar measures. ‘Good Delivery’, as defined by the LPPM website, is “the list of acceptable refiners of platinum and palladium plates and ingots in the London market, the ‘LPPM London/Zurich Good Delivery List’, has been developed and is maintained by the London Platinum and Palladium Market (‘the LPPM’) in order to facilitate the international distribution and acceptability on technical grounds of standard plates and ingots produced by those refiners who meet the criteria for inclusion in the list; and whose plates or ingots have passed the testing procedures laid down by the LPPM.”2 These suspension announcements are expected to cause a severe tightening of the physical availability of PGMs, and potentially some disruption for automotive and industrial users. Even tougher sanctions against Russia are possible in the future.

Recycling The recycling picture is mixed (see Figure 4). While the industry deserves praise for the improvement in ounces recycled (recycling met only 19% of the demand in 2010, but reached 28% in 2020), this is almost entirely due to autocatalysts being recaptured in emerging markets. The hidden concern is that more PGMs now end up in the hands of consumers than in the hands of industry, and the difference in recovery from these two groups is substantial. In short, there are various market forces pulling in all directions at once: the COVID-19 pandemic, the chip shortage, the logistics mess around the globe, labour shortages, Brexit, and now Russia’s invasion of Ukraine. Figure 5 illustrates what happens when supply, recycling and demand are overlayed. Total platinum supply is in surplus of demand by about 200 000 ounces troy, and this is expected to continue for several years. Palladium, on the other hand, is in deficit by over 1 million ounces troy. It should be noted that these numbers do not take into account the last few months of world events. Expectations within the precious metals industry are that palladium prices will experience sustained volatility, lease rates will remain elevated for the short-term, and the aforementioned restrictions will continue in regard to the availability of physical metal. The sheer amount of PGMs that the world demands every year makes mining crucial, and the industry is focused upon improving existing methods and controls. There is not much that can be done about political hot spots or the deteriorating ore quality, but workers can be protected as the mines get deeper, carbon footprint can be examined and minimised, and the cost of refining can be reduced. Thankfully, there are a number of intelligent individuals working on just that.

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Now, and for the foreseeable future, PGMs will remain at the cutting edge of providing answers to some of humanity’s most pressing needs, such as the following: nn Conservation: automotive catalysts and the industrial filtration units that reduce emissions. nn Energy: fuel cells, gasoline, jet fuels. nn World health: treatments, medical devices, and pharmaceutical products that contain PGM or are made using PGM; man-made gems in precision lasers for surgery.

Palladium Platinum

Figure 4. Recycled PGMs (million ounces troy).

Palladium Platinum

Figure 5. Movement of stocks (million ounces troy).

Clearly, however, we need to get better at recycling. We can say with confidence that the reuse of a PGM ounce will mitigate energy use and lower emissions vs mining a PGM ounce. A beautiful aspect of precious metal sustainability is that they can be refined and reused indefinitely (see Figure 6). The goal should therefore be to gather them as thoroughly as possible after each of their incarnations, and continue to maximise the number of refine/reuse cycles.

Considering costs In order to further perfect the refine/reuse cycle, precious metal owners must clearly understand the old adage that ‘cheaper is not better’. Losing out on a contract because a competitor bids less is always frustrating for sales and management, in any industry. However in the precious metals industry it is puzzling, because the important thing in the equation is not the processing fee or freight costs; it is proper weighing and sampling, and accurate analysis to correctly and honestly determine the precious metals content. This sort of quality in design and execution cannot – and does not – come cheap. To put it bluntly, one must divine the equilibrium between quality of service and the cost. An insufficient or unethical service that saves money is far worse than an honest and complete service that costs a bit more. With regard to the precious metals industry, those insufficiencies come in the form of incorrect sampling, illegal disposal of wastes, and other improper behaviour. A ‘lowest-bidder’ mentality leaves companies exposed to a host of risks. All precious metals refiners are not the same – technically or ethically. Professional witnessing, compliance with anti-money laundering legislation, and the knowledge gained by the catalyst users have helped reduce actual robbery dramatically; however, the buyer must still beware.

Conclusion The metals we call ‘precious’ were originally given that title based on their beauty. They were shiny – and people have always liked shiny. This made these metals highly sought after, which in turn made them valuable. They are still considered very valuable for their appearance, but the more we learn about these incredible elements, the more value they will continue to gain for even greater reasons. It is important to ensure that PGMs end up with a responsible recycler. Root out and eliminate the unethical and wasteful through due diligence and investigation; forge global partnerships with industry stewards; allow for fair margins, so that research and development can be properly supported; and discard perceived limitations and challenge the status quo.

References 1.

Figure 6. Molten precious metals pour.

June 2022 64 HYDROCARBON ENGINEERING

YOUNG, R., GU, L., ‘Improvement in December’s Global Auto Sales Does Little to Bolster the Year’s Final Tallies’, Scotiabank, (27 January 2022), https://www.scotiabank.com/ca/en/about/ economics/economics-publications/post.other-publications.autos. global-auto-report.january-27--2022.html ’Good Delivery Rules’, London Platinum & Palladium Market’, (July 2020), https://www.lppm.com/good-delivery-rules/

Hydrocarbon Engineering talks to a number of leading experts in catalyst technology about a range of topics. Jay Parekh, Hydrocracking Subject Matter Expert, Advanced Refining Technologies LLC (ART) Jay Parekh is the Hydrocracking Subject Matter Expert for ART. He has over 30 years of industry experience with over 20 years in various aspects of hydroprocessing, including technology, technical service, and process design. He holds multiple patents in hydroprocessing technology development, as well as a Bachelor of Science degree in Chemical Engineering from the University of California at Davis.

Dr Meritxell Vila, Founder & CEO, MERYT Catalysts & Innovation

Dr Meritxell Vila began her professional life working for Repsol at the Research Centre in Cartagena, Spain, studying ion exchange resin catalysts for the ETBE/MTBE synthesis. After spending several years on process development at the pilot plant units of the research centre, focusing on diesel hydrotreatment and gasoline hydrodesulfurisation, she moved to the Repsol Cartagena refinery to work at the quality control laboratory and the process department in the Lubricants and Hydrotreatment divisions. She was the Catalysts Coordinator of the refinery for several years, including the C-10 large project to double the Cartagena refinery’s capacity. In 2011, Meritxell joined IMCD Spain, moving into chemicals distribution, where she worked as the Product and Project Manager, representing the major international catalyst and adsorbent manufacturers in the Spanish and Portuguese markets. In 2016, Meritxell started her own company, MERYT Catalysts & Innovation, to help customers to optimise their processes by reducing costs in catalysts, adsorbents, and chemical products. The company also develops innovative technologies to save energy and reduce emissions.

Sergio A. Robledo, Senior Account Manager, Clean Fuels, Topsoe A/S Sergio A. Robledo is a Senior Account Manager, Clean Fuels, for Topsoe A/S in Houston, Texas, US. He provides expert technical advice to customers relating to the selection, use and operation of catalysts and technologies. He is also responsible for developing refinery business opportunities to acquire new accounts and maintain existing ones. Mr Robledo holds a BE degree from Stevens Institute of Technology and has more than 20 years of experience in the hydrocarbon processing industry.

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Talk us through the main applications of your catalysts within refineries and petrochemical facilities. Sergio A. Robledo, Topsoe A/S: Topsoe has a large portfolio of hydroprocessing catalysts for refinery applications, ranging from light naphtha-hydrotreatment to resid-upgrading, as well as many hydrocracking catalysts for all configurations and applications. Besides the main-bed catalysts used in hydroprocessing services, we also offer a large number of graded-bed products. These grading products trap contaminants, protecting the main-bed catalysts from feed impurities and preventing premature activity-loss and rapid pressure-drop build-up, which would result in shorter cycles. Over the past 20 years, our portfolio has expanded to include catalysts capable of processing many different renewable-feed streams. These streams can be converted to low-carbon fuels – either within standalone units or co-processed with conventional feeds in existing hydroprocessing units. The challenge lies in ensuring high selectivity towards highly-valuable products, avoiding unprofitable yield losses. In addition, minimising hydrogen consumption; trapping unique feed impurities; improving cold flow properties; and maximising cycle length are the main drivers for this service. Topsoe has also been making hydrogen-production catalysts for over 50 years, with continuous development and improvement along the way. Our newest market offerings are the TITANTM series steam-reforming catalysts, which deliver very high activity, stable performance, and low pressure drop. For petrochemical applications, Topsoe has several supported Ni and Pt/Pd hydrogenation catalysts for all saturation and polishing applications.

How can catalyst technology help refiners to get the most out of bottom of the barrel resources? Dr Meritxell Vila, MERYT Catalysts & Innovation: When we talk about bottom of barrel, we are talking about streams with high molecular weights, heteroatomic functional groups that replace hydrogen atoms in the end molecules, or highly conjugated and aromatic, which result in streams with a high deficit of hydrogen or a very low H/C. The H/C ratio is directly associated with the fuel value of the hydrocarbon mixture. To improve the quality of the bottom of the barrel fraction, the heteroatomic molecules need to be removed and the H/C ratio needs to be increased to values in the order of 1:6. This change in the H/C ratio can be achieved either by increasing the hydrogen content or by decreasing the carbon content. According to the followed approach, these processes fall into two broad categories: nn Non-catalityc carbon rejection processes (those that eliminate part of the C-atoms from the molecules): coker, visbreaking, flexicoking, solvent deasphalting (SDA). nn Catalytic and H-addition processes (those that increment their relative H-content): hydrocracking (HCK) and hydroprocessing (HDP) in general, HDT/MHC/HC/RFCC/ENI’s slurry technology/catalytic ebullated reactors. A comparison between thermal (rejection carbon) and catalytic processes for the improvement of bottom of the barrel is the conversion improvement and the final mass losses. Using a process with a specialised catalyst, the conversion grows from 50 to 60% (thermal process) to 95% (catalyst process), with the advantage of better product quality and fewer mass losses.

Sergio A. Robledo, Topsoe A/S: Refiners are always looking to upgrade the bottom of the barrel into more profitable products, such as diesel and gasoline. Technologies such as visbreaking, coking, and resid upgrading are typical bottom of the barrel upgrading technologies, but these technologies do not produce finished products. Instead, they deliver intermediates, such as coker-gas oils, light-cycle oils, coker naphthas, and similar – all of which contain difficult sulfur species and impurities. Our catalysts allow refiners to hydroprocess these intermediate streams, removing sulfur and impurities to deliver sellable products. Resid hydrocracking, while costly, is also an option – and one of the most profitable.

How can catalyst solutions help companies to reduce their energy consumption and emissions? Dr Meritxell Vila, MERYT Catalysts & Innovation: The definition of a catalyst is a material that reduces the energy needed to perform a chemical reaction. Therefore, any improvement in the design of new catalysts or even in the optimal utilisation of the current catalyst means energy savings for June 2022 66 HYDROCARBON ENGINEERING

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the refinery or the petrochemical plant and, therefore, lower emissions. Many scientists around the world are working intensively every day to improve current catalysts and design new catalysts that can perform the required reactions at lower temperature and pressure, or with higher selectivity. The selectivity is an important subject because higher purity means the formation of fewer byproducts, and this avoids additional separation steps or less intensive separation units downstream of the reactor. Furthermore, in order to reduce emissions, new technologies are emerging to convert CO2 that derives from flue gas into chemicals and fuels, where catalysts play a key role. In this sense, refineries will install new catalytic units to convert the CO2 emissions into valuable products, thus applying circular economy to their processes.

Sergio A. Robledo, Topsoe A/S: Energy consumption is directly related to catalyst activity; the temperature required to achieve a certain conversion or product property is most often dictated by catalyst activity. For this reason, most refiners prefer the most active catalyst for a given service. In addition to reducing energy consumption and CO2 emissions, high activity catalyst, combined with the appropriate grading system, will provide the longest cycle length and avoid unplanned shutdowns, both of which are energy-intensive transient modes of operation. Choosing catalysts with the right selectivity is also very important. Today, producers can select hydroprocessing catalysts that maximise hydrodesulfurisation activity, and either minimise or maximise HDN and hydrogenation activity, thereby reducing any unnecessary emissions. In any renewable-hydroprocessing service, selecting the right catalyst(s) will minimise yield loss into CO2, maximise production of high-value products, and reduce energy consumption per barrel of finished product. The correlation between catalyst activity and energy consumption is not only valid for hydroprocessing, but for most other catalysed applications seen in the refining and petrochemical fields. A very good example of how catalysts can reduce emissions can be found in our low-methanol-forming, low-temperature shift catalysts for hydrogen production, the LK-823 and LK-853 FENCETM. These catalysts help to significantly reduce methanol emissions. The SK-501 FLEXTM is a unique high-temperature shift catalyst that can operate at very low oxygen-to-carbon (O/C) ratios, which helps to optimise the hydrogen unit’s energy consumption. Our RC-67-TITANTM steam-reforming catalyst facilitates a very low pressure drop, which helps to ensure low energy consumption.

Talk us through your company’s latest innovations in catalyst technology. Jay Parekh, ART: ART is making many advances to develop new products to meet customers’ demands. The latest innovation includes new zeolite materials, and novel silica-alumina supports geared to enhance selectivity to distillate products for customers looking for more jet/diesel production from their hydrocracking units while maintaining the activity required to meet cycle length requirements. New catalyst products are designed to maintain and/or improve cold flow properties to meet the industry’s new demand for co-processing bio-feedstock for producing renewable diesel and jet fuels. ART is also focused on improving hydrocracker pretreat catalysts, both conventional and bulk metal catalysts, as the industry increasingly trends towards the processing of more refractory feedstocks emanating from resid conversion units.

What R&D processes do you have in place to develop the next generation of catalysts? Jay Parekh, ART: ART conducts customer-focused and market-driven catalyst R&D by engaging with our customers to understand their value drivers and concerns, and developing catalyst or catalyst systems based on their feedback and, sometimes, through joint development programmes. For hydroprocessing and dewaxing catalysts, ART has R&D facilities that include parallel testing units, bench scale units, and research units that all serve various purposes for screening different developmental catalysts to identify the right catalyst mix for the generation of catalysts. ART continues to advance next-generation catalyst performance through innovations in developing new porous materials of alumina, amorphous silica-alumina, and crystalline zeolites with desired pore structures for catalyst supports. Advanced analytical tools such as elemental mapping, electron microprobe imaging, etc, are intensively used to characterise and manage how catalyst powders and promotors are bound together in the mulling and extruding June 2022 68 HYDROCARBON ENGINEERING

A Better Perspective on Hydroprocessing Solutions

In the refining industry, market conditions are always evolving with new regulatory requirements, global demand shifts, and the use of heavier feedstocks among other factors. ART Hydroprocessing can help you take a better perspective on these challenges based on our deep understanding of refinery operations and a full spectrum of hydroprocessing catalysts solutions that maximize profits by balancing run length, severity, feed flexibility, contaminants, and operating constraints. ART is a joint venture of Chevron and W. R. Grace & Co., created to bring you state-of-the-art hydroprocessing catalyst solutions for petroleum refining applications worldwide. We collaborate with the industry’s leading licensor, CLG, to provide complete solutions to address your needs to extract more value from every barrel of oil. Combined with our unparalleled technical customer service, we deliver results for you. Contact your ART representative today for more information.

arthydroprocessing.com

processes. Hydrogenation components of transition metals are deposited on supports using sophisticated manufacturing processes assisted with anchoring chemicals to maximise their performance benefits.

Dr Meritxell Vila, MERYT Catalysts & Innovation: At MERYT Catalysts & Innovation we firmly believe that research and development (R&D) is crucial for the discovery of new catalysts and for the improvement of traditional catalysts, which are essential for the energy transition. In this sense, we focus our efforts on obtaining applicable results by establishing very close and profitable collaborations for both parties with the most advanced research groups in catalysis. MERYT is committed to collaborating with the most brilliant research brains in catalysts, and for this we develop R&D projects with pioneering teams in each type of catalyst in particular, in order to transfer these innovations to our customers. The areas of research in which we are most involved are those that we consider essential to the energy transition. In that sense, we are focusing on the development of catalysts for the conversion of CO2 to methanol and other products.

Sergio A. Robledo, Topsoe A/S: For developing the next generation of catalysts, a large roster of dedicated pilot-plant units is crucial. This must be combined with a large number of specialised techniques for characterising not only feed and products, but also spent and used catalysts. Topsoe also makes use of highly-specialised scanning-tunnelling electron microscopes to understand reaction chemistry at the atomic level.

How do you work with refineries to ensure that the most appropriate catalysts are selected for a given project? Sergio A. Robledo, Topsoe A/S: That depends very much on the client’s catalyst-selection process. In some cases, we use our own highly-specialised prediction models, developed and calibrated with input from both our pilot-plant tests and commercial experience. In other cases, we ship catalysts for independent third-party testing, but the quality of such tests can vary significantly depending on the lab. Some refiners also have their own in-house test facilities, preferring to conduct their own testing for catalyst approval. Finally, Topsoe performs pilot-plant testing of client feeds, at their unit-operating conditions, within our own pilot plant facilities. In all cases, the key is to maintain close, open dialogue with the client. A good understanding of the unit history is also key to further optimisation and improvement of the catalyst load. There may well be some pressure-drop issues, often related to corrosion products, or some feed issues that can be solved using the right catalyst load in a given unit.

What role will catalyst technology play in the transition to low-carbon energy? Dr Meritxell Vila, MERYT Catalysts & Innovation: As previously mentioned, the definition of a catalyst is a material that increases the reaction rate by reducing the activation energy required. Therefore, any improvement in the performance of current catalysts or the design of new catalysts will play an important role in the transition to low-carbon energy. An area that is especially important is the role of catalysts in the conversion of CO2 to chemicals, because this reaction allows CO2 that is emitted to be removed and reused, closing the cycle of the carbon, and therefore creating a circular economy. And there are many challenges for catalysts in the circular economy. For example, the treatment of pyrolysis oil derived from recycled plastics or urban residues is a great field of development for catalysts and specific adsorbents. Another important role of catalysts in low-carbon energy is in the production of biofuels. Catalysts must be adapted to treat many different biofeeds and, in some cases, specific adsorbents will be required to pretreat the biofeeds.

Sergio A. Robledo, Topsoe A/S: Catalyst technologies play an integral role in the transition to low-carbon fuels, as all renewable streams must be thoroughly hydroprocessed before they can be used as fuel, or downstream feeds. Catalysts ensure the efficient conversion of these low-carbon feed streams. Because of this, the transition to low-carbon energy will require the most efficient catalysts available in order to maintain a low-carbon intensity index. June 2022 70 HYDROCARBON ENGINEERING

MERYT Catalysts & Innovation Your global supplier of catalysts, adsorbents and additives focused on new technologies and sustainable processes.

Improve the profitability of your processes with MERYT catalysts and our outstanding technical knowledge, experience, and excellent service

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info@meryt-chemical.com www.meryt-chemical.com +34 868 086 998 +34 670 518 438 MERYT Catalysts & Innovation c/Berlín Parcela 3F Polígono Industrial Cabezo Beaza 30353-Cartagena Murcia SPAIN

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