Hydrocarbon Engineering March 2022

March 2022

Troubleshooting Desalter Challenges MAXIMIZE ASSET VALUE THROUGH SPECIALTY CHEMICAL EXPERIENCE AND EXPERTISE

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CONTENTS March 2022 Volume 27 Number 03 ISSN 1468-9340

05 Comment

49 Can electric pull its weight?

07 Guest comment 09 World news 12 US fuels emerging from the pandemic Nancy Yamaguchi, Contributing Editor, explores the state of the US fuels market as the country begins its slow climb back from the COVID-19 pandemic.

21 Maximising value with C5 olefins Nikolas Larsen and Nicholas Newlon, Marathon Petroleum Corp., alongside Namal de Silva, Daniel Neuman, Yorklin Yang and Brian Killeen, BASF Corp., detail the companies’ collaborative investigation to demonstrate that C5 olefin maximisation can be delivered through FCC catalysts.

25 Keeping things flexible Jitendra Chellani, KBC (A Yokogawa Company), and Hans Lidman, Nynas, outline how to improve margins through feedstock flexibility.

31 Fuels of the future Kevin Bockwinkel, Randy Peterson and Samantha Presley, Elessent Clean Technologies, explore the role of gasoline in the clean fuels market.

37 Tackling unusual desalter challenges Wole Olowu and Tim Oubre, Athlon, a Halliburton Service, USA, offer solutions to some unique desalter challenges that the company has helped refiners to overcome.

45 A race to the bottom Neil Richards, PS Filter, Canada, explains why buying the cheapest product is not always the best solution.

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Decarbonisation efforts worldwide have accelerated the shift from fossil fuels to renewables. One way many industrial organisations can embrace this is by changing process heater systems from fuel-burning to electric. Dennis Long and Roly Juliano, Watlow, USA, detail why.

53 Embracing change Ilan Toledano, Wattco, Canada, evaluates how downstream oil and gas industry leaders are managing the energy transition.

55 Safety: more than a buzzword Fred J. Gossen, Jr, Hallwood Modular, USA, discusses the importance of facility siting in order to ensure worker safety in high-risk environments.

60 Not rocket science Sam Miorelli, Siemens Energy, USA, presents a simplified, four-step approach to stronger cybersecurity in downstream operations.

66 The value of digital assistance Samuli Bergman, NAPCON, Finland, explains how machine learning can aid operators of oil refineries and petrochemical facilities.

71 Out with the old Phil Millette, Honeywell Process Solutions, UK, discusses how timely technology upgrades extended the life of critical assets at Petroleum Development Oman’s government gas plant.

75 Closed-loop neural networks Gil Cohen and Abishek Mukund, Imubit, outline the requirements to automate key operating strategies in closed-loop to achieve optimal plant profitability.

Athlon, a Halliburton Service, provides industrial water and process treatment solutions to refinery, petrochemical, ammonia/fertilizer, and heavy industrial operations. Through onsite technical service and engineering support, Athlon helps customers with their business goals, including improving reliability, increasing throughput, and enhancing the efficiency and flexibility of operating units.

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CALLUM O'REILLY SENIOR EDITOR

R

ussia’s invasion of Ukraine has sent oil and gas prices soaring. Fears are escalating that the crisis – and the tough sanctions on Russia that have been imposed, including Germany’s decision to halt the certification process for the Nord Stream 2 gas pipeline – will disrupt supplies across the world.

Some political commentators (and, indeed, politicians) have described the situation as the most dangerous moment in Europe since the Cuban Missile Crisis. And while the old threat of nuclear tension certainly looms large, there are also increasing concerns over a modern method of warfare: cyberattacks.

Russia has been accused of being behind a string of cyberattacks against Ukraine in recent years – including recent attacks on Ukrainian banks and government departments – and there is apprehension that these security breaches could quickly move beyond Ukraine’s borders. A cyber rapid-response team (CRRT) is being deployed across Europe, after a call for help from Ukraine.

In the US, the Cybersecurity & Infrastructure Security Agency (CISA) has issued a ‘Shields Up’ alert to every organisation in the country, warning that they are at risk from cyber threats that can disrupt essential services and potentially result in impacts to public safety. Meanwhile, here in the UK, the National Cyber Security Centre (NCSC) has updated its guidance, telling firms to “build resilience and stay ahead of potential threats”.

The energy sector is particularly vulnerable to attacks. IBM Security recently published its ‘2022 X Force Threat Intelligence Index’, which revealed that the energy industry was the UK’s top target for cyberattacks in 2021, accounting for 24% of all incidents.1 And the threat to the energy sector is echoed in an article from Siemens Energy that features in this issue of Hydrocarbon Engineering (starting on p. 60). In the piece, Sam Miorelli, Global Head of Cybersecurity for Industrial Applications, points to a 2021 SANS survey on the state of cybersecurity for operational technology (OT) and industrial control systems (ICS), which identifies the energy sector as the most at-risk industry for cyberattacks. The article introduces a four-step approach that the downstream oil and gas sector can adopt to close vulnerable cybersecurity gaps in their operations.

The topic of cybersecurity will also feature heavily in a brand new podcast that Hydrocarbon Engineering has launched alongside our sister publications, World Pipelines, LNG Industry and Oilfield Technology. The Palladian Energy Podcast is a podcast series for energy professionals featuring short, insightful interviews with experts who can shed light on topics that matter to you and your business. Series one focuses on digitalisation in the oil and gas sector, and the first few episodes are out now. We have a number of interesting episodes coming out soon, including a chat with Sam Miorelli about cybersecurity, as well as a conversation with Alan Gelder, Vice President of Refining, Chemicals and Oil Markets at Wood Mackenzie, about the outlook for the downstream sector, and the important role that digitalisation has to play. You can listen for free wherever you usually get your podcasts.

1.

‘IBM X-Force Threat Intelligence Index’, IBM, (February 2022).

GUEST COMMENT CHET THOMPSON PRESIDENT & CEO, AMERICAN FUEL & PETROCHEMICAL MANUFACTURERS (AFPM)

C

biofuel producers to ars and trucks today are twice as efficient come together. as vehicles from the 1970s. They are 99% The policy’s cleaner for common pollutants, emit half neutrality toward the carbon, and are 75% more powerful. This octane sources means record is a testament to the ingenuity of auto makers, it can work for all 50 US states, including those with the fuel producers, and petrochemical manufacturers who toughest fuel and air quality standards. have used lightweight advanced plastics, low-viscosity It’s critically important that we have a long-term lubricants, and other technologies to advance us leaps liquid fuel strategy to reduce vehicle emissions. More and bounds in the direction of better vehicle efficiency.

This progress should be celebrated and furthered. than 85% of drivers in the US want their next vehicle to Like our customers, the be one that runs on gasoline men and women who work or diesel fuel (69% want a in refining and petrochemical pure internal combustion manufacturing want even engine vehicle and 17% note The best and brightest better performance from our a preference for hybrids, cars. while 5% say they’d like to from the refining and For years now, AFPM purchase an EV).1 At the same petrochemical industries time, we’ve noted drivers and our members have been also want better mileage and advocating for reforms to have their eyes set cleaner cars. the Renewable Fuel Standard on reducing emissions Thankfully, programme, coupled with environmental progress is a nationwide 95 RON from every facet of not at odds with consumer high-octane fuel standard. transportation, from our preference because 95 RON The value proposition of this is a way to meet both policy for drivers and the operations, and our end needs. The policy will deliver environment is what makes essential carbon reduction the 95 RON approach so products. at lower cost to consumers exceptional. than technology-forcing In the first year of alternatives. implementation, the use of The best and brightest from the refining and a new high-octane gasoline in vehicles designed with petrochemical industries have their eyes set on reducing higher compression engines would reduce vehicle CO2 emissions by 1.23 million t – the equivalent reduction of emissions from every facet of transportation, from nearly a million electric vehicles (EVs), but at a fraction of our operations, and our end products. Along with the the cost. renewable diesel and sustainable aviation fuel that For drivers, this would mean no compromising on refiners are producing in record volumes, and the comfort or convenience for the sake of better vehicle petrochemical body components reducing weight performance. A range of family-sized cars and trucks while keeping drivers and passengers safe, 95 RON is designed to run on 95 RON high-octane fuel will fit an affordable, fuel-based answer for family drivers and within their budgets, and they’ll be able to travel farther commuters around the US. There is no better approach and cleaner on each gallon of gas. for consumers, refiners, liquid fuel producers, our For farmers and biofuel producers, a 95 RON standard economy, and the environment. will create opportunity for American-grown ethanol since it is so often the most affordable source of octane in the 1. '2022 Global Automative Consumer Study', Deloitte, market. 95 RON creates a rare opportunity for refiners and (January 2022).

HYDROCARBON

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WORLD NEWS Worldwide | Optimism

surging as global energy industry focuses on transition

E

nergy industry leaders say the energy transition is accelerating faster than ever, and that 2022 is set to be a strong year for industry growth, according to a new global report from DNV analysing the views of more than 1000 senior energy professionals.

Industry players from across power, renewables, and oil and gas believe the huge commercial opportunities presented by the transition outweigh the risks to their businesses, according to ‘The Power of Optimism: Managing

UK | Essar

furnace

scale and complexity as the energy transition accelerates’.

Energy leaders are finding most confidence from their own company’s strategies within renewables and low-carbon gas, followed by expectations for supportive policy changes and reforms. Confidence for growth is highest among power and renewables companies, and while it is lower in oil and gas, the sector has bounced back from a crash in confidence going into 2021.

to build refinery-based hydrogen

E

ssar Oil UK (EOUK) has announced plans to install a new £45 million furnace at Stanlow that’s capable of using hydrogen as its fuel source.

This is a first in the UK, and marks a significant milestone in Essar’s commitment to becoming the UK’s first low-carbon refinery. It follows the launch of Vertex Hydrogen last month, a new Essar-led joint venture, in which the company will invest £1 billion over the next five years to drive down emissions, including the development of new hydrogen production plants at Stanlow,

forming a central part of the HyNet North West decarbonisation cluster.

The scheme will provide a number of improvements that will lead to benefits for Stanlow and the surrounding area, including lower carbon emissions due to gas-only firing and new burners that emit lower levels of nitrogen oxide (NOx) and futureproofing to enable the use of sustainable fuel types, such as hydrogen, in the future.

Set to be installed in 2022, the furnace will become fully operational in 2023.

Worldwide | LNG

industry rebounded in 2021

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lobal trade in LNG increased 6% to 380 million t during 2021, as many countries rebounded from the economic impact of the COVID-19 pandemic, according to Shell’s latest annual ‘LNG Outlook’.

Rising LNG demand, combined with supply constraints, caused gas and LNG prices to remain volatile throughout the year. Prices reached record levels in October 2021 as Europe, with historically low storage levels, struggled to secure LNG cargoes to meet expected winter gas demand.

The volatility emphasises the need for a more strategic approach to secure reliable and flexible gas supply in the future to avoid exposure to price spikes. An LNG supply-demand gap is forecast to emerge in the mid-2020s and focuses attention on the need for more investment to increase supply and meet rising LNG demand, especially in Asia.

Overall, global LNG demand is expected to cross 700 million tpy by 2040, a 90% increase on 2021 demand.

Asia is expected to consume the majority of this growth as domestic gas production declines, regional economies grow, and LNG replaces higher-emissions energy sources.

The Netherlands | Global

Energy Storage closes investment in the Port of Rotterdam with Gunvor Group

F

ollowing the signing of a binding agreement in November 2021, Global Energy Storage (GES) has announced that it has successfully closed the transaction to acquire part of the Stargate Terminal from Gunvor Group in Europoort, Port of Rotterdam, the Netherlands.

Consequently, GES now owns four Class 1 product tanks totalling over

212 000 m3 with long-term offtake from Gunvor. In addition, GES has acquired the rights to develop approximately 20 ha. of vacant land.

Furthermore, it is pursuing expansion projects to support the energy transition, such as import facilities for ammonia, storage for biofuels and feedstock, chemicals, gases, and waste-to-fuel production.

Peter Vucins, CEO of GES, commented: “This is an important milestone for GES. The location of this first investment in the heart of the Port of Rotterdam positions us perfectly to significantly contribute to our client’s needs to develop the new storage and logistics infrastructure to facilitate the energy transition which is upon us and accelerating.”

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March 2022

WORLD NEWS DIARY DATES 13 - 15 March 2022 AFPM Annual Meeting New Orleans, Louisiana, USA www.afpm.org/events

13 - 15 April 2022 24th Annual International Aboveground Storage Tank Conference & Trade Show Orlando, Florida, USA www.nistm.org

09 - 11 May 2022 Sulphur World Symposium Tampa, Florida, USA www.sulphurinstitute.org/symposium-2022

09 - 13 May 2022 RefComm Galveston, Texas, USA www.events.crugroup.com/refcomm

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

23 - 27 May 2022 World Gas Conference Daegu, South Korea www.wgc2022.org

24 - 26 May 2022 Asia Turbomachinery & Pump Symposium Kuala Lumpur, Malaysia atps.tamu.edu

07 - 09 June 2022 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

March 2022 10 HYDROCARBON ENGINEERING

Singapore | Shell

to supply SAF

S

hell has announced that it has become the first supplier of sustainable aviation fuel (SAF) to customers in Singapore.

The company has also completed upgrades of its facility in Singapore, which will enable blending of SAF. Currently, SAF is only approved for use in aircrafts when it is blended in a ratio of up to 50% with conventional jet fuel. Having a blending facility in the region enables a more efficient operation by moving neat SAF in bulk from production sources to the blending facility, and then delivering blended SAF parcels to where it is needed.

The announcement represents a significant milestone for the aviation industry in Asia, as the enhanced SAF supply chain capabilities will increase customers’ access to SAF. The SAF supplied is made from waste products and sustainable feedstocks, and will be blended with conventional jet fuel. The first batch is blended in Europe and aims to test and verify the supply chain for SAF that Shell has established in Asia. The SAF is being supplied by Shell Aviation, as part of its supply agreement with Neste – the producer of SAF. Shell is seeking to commence blending at its Singapore facilities for subsequent batches.

Egypt | Coalition

of energy companies to decarbonise downstream facilities

A

coalition of energy transition leaders – Bechtel, Enppi, Petrojet, GE, Baker Hughes, HSBC, and the National Bank of Egypt – have signed a Memorandum of Understanding under the auspices of Tarek El Molla, Egyptian Minister of Petroleum and Mineral Resources, in Cairo, Egypt.

The coalition will provide execution, technology and financing expertise for a new initiative to support the decarbonisation of select downstream facilities in Egypt, aligning plans with the country’s leadership of the COP27 UN Climate Change Conference 2022.

USA | US

demand for residual fuel oil rose late in 2021

I

n November 2021, more residual fuel oil was consumed in the US than during any month since January 2017 (measured as product supplied), reports the US Energy Information Administration (EIA). Residual fuel oil has several uses, but it is primarily consumed as bunker fuel in the maritime shipping sector.

Consumption in December 2021 was at its highest end-of-year level since 2012, according to the EIA’s ‘Weekly Petroleum Status Report’ (WPSR).

The increase in residual fuel oil demand comes with record increases in maritime shipping volumes and rising high-sulfur fuel oil prices in Singapore.

The Singapore market is a global benchmark for marine shipping.

Since the beginning of November 2021, Singapore’s very-low-sulfur fuel oil price premium over high-sulfur fuel oil increased to more than US$20/bbl and neared US$30/bbl throughout December 2021 and January 2022.

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March 2022 12 HYDROCARBON ENGINEERING

Nancy Yamaguchi, Contributing Editor, explores the state of the US fuels market as the country begins its slow climb back from the COVID-19 pandemic.

T

he COVID-19 pandemic caused a tectonic shift in the US national economy and its energy market. At the time of writing this article, nearly two years have passed since states announced stay-at-home orders to combat the spread of the coronavirus. The country launched drastic and immediate changes in consumer behaviour, business practices, fuel use, and every facet of economic and social life. In contrast, pulling out of the pandemic is proving to be a lengthy process, with stretches of optimism alternating with surges in infections. No one is exactly sure when it will be formally over. The only certainty is that ‘business as usual’ will not look like it used to. Some economic and

behavioural changes will be long-term and structural, and businesses and individuals must adapt.

One of the most momentous changes is the increased use of telework. This must be assumed a permanent change, though the extent will vary from place to place. Many major firms are adopting hybrid working schedules that split time between home and headquarters. Some companies have noted that failure to offer this flexibility limits their ability to attract and keep talented people. It must also be assumed that consumers will retain some aversion to person-to-person interaction in shopping, dining, entertainment and travel. These factors will have profound impacts on fuel demand.

HYDROCARBON 13

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March 2022

Indeed, forecasting demand for fuel and energy has become far more complicated, and even small variations in the modelling assumptions can result in huge changes in what can be expected for gasoline, diesel and jet fuel demand.

This article examines recent trends in US refining and demand, emphasising the rapid downturn caused by COVID-19 and the slow climb back. The US refining industry is large and sophisticated, but it finds itself in a reactive phase. Refiners are raising throughput in response to market signals, but they are aware that demand has not been fully restored. In the future, demand for petroleum fuels may grow incrementally, and it is possible that demand will shrink.

Figure 1 illustrates how the COVID-19 pandemic caused the US unemployment rate to skyrocket, followed by a slow downward path. The pattern is analogous to a swift onset of a disease followed by prolonged recovery, an analogy that will be carried forward in this article in the discussion of refinery behaviour and fuel demand.

The US unemployment rate shot up from 3.5% in February 2019 (one of the lowest rates in history) to 14.7% in April 2019. It then took 20 months until the unemployment rate retreated to 3.9% in December 2021, and the rate increased slightly to 4% in January 2022. The US Bureau of Labor Statistics (BLS) reports unemployment rates stretching back to 1948, and the double-digit rates experienced in the April, May and June 2019 period were the worst in history.1

US refining: capacity changes and inputs

The US refining industry is large and mature, having survived several downturns and phases of rationalisation and downsizing. The challenging work had been done, it seemed. Utilisation rates were respectable, and capacity was creeping up modestly. Then the COVID-19 pandemic hit, and utilisation and capacity retreated. At the beginning of 2021, there were 129 operable refineries in the US with a total crude capacity of 18.1 million bpd. Relative to 2020, this was down by five refineries totalling 0.8 million bpd of crude capacity. The closures included the 335 000 bpd Philadelphia Energy Solutions refinery in Philadelphia, Pennsylvania. This refinery was severely damaged by explosions and fire in October 2019, and the decision was made to close the facility rather than to make investments to repair it, or to find a buyer.

The following recent refinery closures were also motivated by the COVID-19 pandemic: n The 27 000 bpd Western Refining refinery in Gallup, New Mexico. n The 161 000 bpd Tesoro (Marathon) refinery in Martinez, California. n The 19 000 bpd Dakota Prairie refinery in Dickinson, North Dakota.

Figure 1. COVID-19 and the US seasonally-adjusted unemployment rate, n The 48 000 bpd HollyFrontier % (source: US Bureau of Labor Statistics [BLS]). refinery in Cheyenne, Wyoming. n The 211 146 bpd Shell refinery in Convent, Louisiana.

Figure 2. US downstream fresh feed inputs, 2020 and 2021 as % of 2019 (source: US Energy Information Administration [EIA]).

March 2022 14 HYDROCARBON ENGINEERING

In 2019, US refiners processed an average of 19.371 million bpd of crude oil and other refinery feedstocks. This dropped by 14% to 16.566 million bpd in 2020. Refinery runs rose to 17.661 million bpd during the January to November period in 2021, which was 91% of its 2019 level. The industry is ramping back up, but not yet to pre-pandemic levels.

Figure 2 shows the impact of the pandemic on fresh feed inputs to four key downstream refinery technologies: catalytic reforming, catalytic cracking, catalytic hydrocracking, and coking.

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refineries in the US use some combination of these technologies, and some have all four in place (including major refineries in Texas, Louisiana, California and Indiana).

In 2020, fresh feed inputs to catalytic reformers fell to 88.2% of their 2019 levels. Fresh feed inputs to catalytic crackers fell to 84.9% of their 2019 levels. Hydrocracker feed inputs fell to 90.8%, and coker feed inputs fell to 89.9%. In the January to November 2021 period, fresh feed inputs began to recover. Relative to their 2019 levels, catalytic reformer feed inputs rose to 93.2%, catalytic cracker inputs rose to 91.1%, coker inputs rose to 92.4%, and hydrocracker inputs were back at 99.8% of their 2019 levels. As will be further discussed in the section on product supplied, diesel demand did not drop as sharply as gasoline demand did, and it rebounded more quickly.

Hydrocracking utilisation therefore did not drop as dramatically, and fresh feed inputs to hydrocrackers recovered to nearly 100% as of November 2021.

through to November 2021. Refinery output of gasoline and jet fuel plummeted, while diesel production declined more modestly. Gasoline production averaged approximately 318 million bbl in October 2019, and this collapsed to 191 million bbl in April 2020. Jet fuel production of 59.3 million bbl in December 2019 was slashed to 15.8 million bbl in May 2020. Diesel production of 164.6 million bbl in December 2019 fell to 139.6 million bbl in February 2020.

Of the three key fuels, diesel output was cut the least, and it rebounded the most quickly. In November 2021, refinery output of diesel was 148.6 million bbl – very close to where it was before the pandemic. Gasoline and jet fuel output have risen, but they remain suppressed.

Demand side: US fuel supplied

The future of demand is now the critical unknown. In 2020, the country was optimistic that the pandemic was coming to an end, and economic activity was picking up.

By late 2021, however, the Omicron variant had emerged, Refinery production and infections began to surge. While the Omicron variant Because US refiners were forced to reduce their has not proven as fatal as feared, it is easily transmissible throughput, refinery fuel output fell. Figure 3 shows the nonetheless, and US hospitals and healthcare monthly trend in refiner and blender net production of professionals were once again swamped. US oil demand gasoline, jet/kero, and diesel from September 2019 retreated in the fourth quarter. Soaring prices are also tamping down demand growth, and some economic and recreational activities are stymied because of supply chain issues.

US fuel demand is visibly recovering, however. Figure 4 compares monthly fuel demand for the three key fuels: gasoline, jet/kero and diesel. The bars compare fuel use in the months November 2019 (before the COVID-19 breakout), April 2020 (a month of severe economic and social disruption as stay-at-home orders took effect), November 2020, and November 2021. Gasoline supplied in November 2019 averaged 9.209 million bpd. Demand collapsed to 5.866 million bpd in April 2020, an Figure 3. US refiner and blender net production of gasoline, diesel and incredible drop of 3.343 million bpd. To jet fuel, million bbl/month (source: EIA). place this in perspective, the drop in US gasoline demand was greater than the entire market demand of all other North and South American countries combined, and almost double the market size of Europe (BP reported European gasoline demand at 1.768 million bpd in 2020).2 Jet fuel supplied was slashed from 1.723 million bpd in November 2019 to 0.681 million bpd in April 2020, a 166% drop. Demand recovered to 1.131 million bpd in November 2020 and 1.501 million bpd in November 2021.

Diesel supplied fell from 4.201 million bpd in November 2019 to Figure 4. The COVID-19 impact on US fuels supplied, ‘000 bpd 3.528 million bpd in April 2020. Demand (source: EIA). rose to 3.879 million bpd in March 2022 16 HYDROCARBON ENGINEERING

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The 2007 – 2008 period was the subprime mortgage crisis, which resulted in the Great Recession, officially defined as beginning in December 2007 and ending in June 2009. Fuel prices recovered subsequently, and they Gasoline and diesel retail prices were strong and stable for most of 2011 – 2014 until The COVID-19 pandemic caused immense oil price oversupply dragged prices down in 2015 – 2016. volatility. As economic activity and travel slumped, prices Oil prices were weak overall from 2015 to 2019, and collapsed. In a historic moment, West Texas Intermediate during this time, OPEC and allied producer countries (WTI) crude oil futures prices closed in negative territory (known as the OPEC+ group) worked together to place on 20 April 2020. While future prices for crude oil do not ceilings on production to help drain global inventories and fully determine retail prices for gasoline and diesel, the support prices. The COVID-19 pandemic overwhelmed crude price collapse forced retail prices down in 2020. these efforts by eliminating a large chunk of demand, Figure 5 displays weekly retail prices for regular grade causing the price collapse visible in early 2020. Gasoline gasoline (all formulations) from 2005 through to retail prices dropped to US$1.77/gal. in April 2020, while 7 February 2022. Figure 6 displays the weekly price data for diesel retail prices fell to US$2.39/gal. in May of that year. diesel during the same period. Both gasoline and diesel Since then, however, US retail fuel prices have climbed prices spiked in the summer of 2008, with gasoline hitting steadily. Some of this is attributed to the resumption of US$4.11/gal. and diesel hitting US$4.76/gal. during the week economic activity after a lengthy period of pandemic of 14 July 2008. Prices then crashed, with gasoline prices shutdowns. Fuel inventories (and inventories of many other bottoming out at US$1.61/gal. in late 2008, and diesel goods) were drawn down and have not been replenished prices dropping as low as US$2.02/gal. in early 2009. over the past two years. Rising prices for fuel, food, and other goods and services are feeding inflation and leading to consumer complaints.

The current Russian-Ukraine tension is strengthening oil prices even further. Overall, weekly average retail prices for gasoline have doubled, rising from US$1.77/gal. in April 2020 to US$3.49/gal. in early February 2022.

Prices are far above their pre-pandemic levels. Indeed, gasoline retail prices are the highest they have been since August 2014, nearly seven and a half years ago. Diesel prices rose from their nadir of US$2.39/gal. in May 2020 to hit US$4.02/gal. during the first week of Figure 5. Weekly retail gasoline prices, all regular formulations, US$/gal.

February 2022. It has been eight years (source: EIA). since US retail prices for diesel have been above US$4/gal.

The COVID-19 pandemic caused a severe price crash, and now oil prices are climbing to the point that consumers are complaining, and there are inflationary pressures on many non-energy goods and services.

The oil market has been subject to numerous up-down fuel price cycles.

It is always possible that prolonged periods of low prices, such as the recent one caused by oversupply and burgeoning inventories, can be followed by price spikes. During the recent glut, compounded by the COVID-19 crash, many investments in the oil sector were postponed. A glut may tip into shortage if the pandemic ends and pent-up demand Figure 6. Weekly retail diesel prices, US$/gal. (source: EIA). returns. These cycles are a feature of November 2020 and bounced back to 4.174 million bpd in November 2021 – almost its prior level.

March 2022 18 HYDROCARBON ENGINEERING

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the market. The current upward trajectory in fuel prices may be tempered by several factors, including increases in energy supply, a reduction in geopolitical risk, and consumer response.

THE EXPERT IN YOU

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As 2022 begins, there are many good reasons to believe that the worst of the COVID-19 pandemic is over. The path is not a smooth one. January 2022 brought a shocking surge in new cases in the US, but the numbers dropped sharply in February. According to Our World in Data, the seven-day rolling average of daily new confirmed COVID-19 cases in the US spiked to over 800 000 in mid-January 2022.3 Hospitals and medical personnel were overwhelmed once again, but new cases thankfully dropped to approximately 177 000 in mid-February. Many states in the US are phasing out simple protective measures such as mask mandates. It remains to be seen if this optimism results in another rise in infections. However, cautious individuals still wear masks, and as of 14 February 2022, 76% of the US population had received at least one dose of the COVID-19 vaccine.

The economy is moving once again. BLS reported continued improvement in its January Employment Situation report, also known as the ‘Jobs Report’.1 The unemployment rate in January 2022 was 4%, comparable to its pre-pandemic level, and 467 000 jobs were added. BLS noted that “employment growth continued in leisure and hospitality, in professional and business services, in retail trade, and in transportation and warehousing”.1 Initial claims for unemployment insurance fell to 223 000 during the week ended 5 February 2022, only modestly above the pre-pandemic norms. Looking back to when the lockdowns first hit, it was reported that initial claims for unemployment insurance skyrocketed to 6 867 000 during the week ended 28 March 2020, and another 6 615 000 claims were made during the week ended 4 April 2020.

The US Energy Information Administration (EIA) assumes that the US GDP grew by 5.7% in 2021, and it will grow by 4.2% in 2022 and 2.8% in 2023.4 These are strong rates. They are being achieved despite inflationary pressures caused by rising prices for crude oil and petroleum products. The EIA forecasts that WTI crude oil spot prices jumped from US$39.17/bbl in 2020 to US$68.21/bbl in 2021, and those prices will continue to rise to US$79.35/bbl on average in 2022 before subsiding in 2023. Refined fuel prices will follow crude, but demand for gasoline, diesel and jet fuel will continue to recover.

The COVID-19 pandemic had a swift and terrible onset in the US. Recovery has been prolonged, however it does finally appear to be underway, and US refining and demand are trending back up in 2022.

SIM

OF N O U L AT I

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You need the right answers!

We can help provide them.

References 1.

2.

3.

4.

U.S. Bureau of Labor Statistics, https://www.bls.gov/ BP, https://www.bp.com/ Our World in Data, https://ourworldindata.org/ US Energy Information Administration, https://www.eia.gov/

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Nikolas Larsen and Nicholas Newlon, Marathon Petroleum Corp., alongside Namal de Silva, Daniel Neuman, Yorklin Yang and Brian Killeen, BASF Corp., detail the companies’ collaborative investigation to demonstrate that C5 olefin maximisation can be delivered through FCC catalysts.

C

5 olefins pose an interesting challenge for refiners in North America.1 Ever since methyl tert-butyl ether (MTBE) was banned from use in gasoline blending in the early years of the millennium, refiners have faced the challenge of utilising C5 olefins. The high Reid vapor pressure (RVP) of C5 olefins limits the amount that can be blended into the gasoline pool, particularly during the summer.

One option for increasing the value of C5 olefins is alkylation.

Existing alkylation units with feed segregation capabilities can process C5 olefins as a feedstock for alkylate production.

While the quality of alkylate created from C5 olefins is not as good as that obtained from the alkylation of butylenes, the product is a significantly-improved gasoline blending component (higher octane; lower RVP) vs the feed.

C5 olefin alkylation is not without its challenges. As with the butadienes present in C4 feeds, di-olefins present in C5 olefin feeds will increase acid consumption. However, refiners with the ability to segregate C3 olefin and C5 olefin feeds in the alky unit have found increased flexibility on where to put the C5s produced in the fluid catalytic cracking (FCC), increasing the value of this stream as a result. Recently, it has been observed that C5 olefin values are in line with butylene value at refineries that have sufficient alkylation capacity and the capability to alkylate C5 olefins. As such, these refiners have significant incentives to promote C5 olefin production.

Utilising an FCC catalyst that increases the ratio of butylenes-to-propylene may also show significant benefits with respect to C5 olefins production that is unlikely to be HYDROCARBON 21

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captured in current kinetic modelling data. As such, a catalyst that provides improved C5 olefin selectivity will add additional value to refineries with the capability to alkylate this stream in the summer, while still allowing for use as a gasoline blending component in the winter when RVP constraints are not as onerous.

While there are no dedicated efforts to develop C5 olefin maximisation catalysts, refiners have shown interest in employing

FCC catalysts that have the upper hand of increased C5 olefin yields, in order to take advantage of local refinery economics, along with FCC and alkylation unit capacities and constraints. As a catalyst vendor, BASF has explored catalyst design to help refiners with these specific needs.

This article highlights the collaborative investigation between BASF and Marathon Petroleum Corp. (MPC) to demonstrate that C5 olefin maximisation is delivered by BASF’s olefin catalysts: FourteTM and FourtuneTM. Both catalysts belong to the company’s Multiple Framework Topology (MFT) technology family of catalysts.2,3

A collaborative investigation

Figure 1. MFT has the appropriate zeolitic pore

size and optimum acidity to generate and preserve C5 olefins.

Figure 2. CRU testing data for lab-deactivated fresh catalysts of BASF’s non-MFT catalyst and MFT catalysts – Fourte and Fourtune.

In MPC’s circulating pilot plant, both fresh and equilibrium catalysts belonging to the MFT family were tested against conventional catalysts lacking the MFT technology, in order to determine whether the olefin enhancements observed for MFT catalysts extend to C5 olefin selectivity improvements.

The results obtained in pilot testing were further validated using operating data from multiple MPC units.

In 2018, BASF introduced MFT to address the challenge of butylene maximisation and octane enhancement in the FCC. The catalysts are created by combining four key elements: multiple zeolite frameworks, active matrix, low acid site density and higher activity. Since the commercial introduction of the first generation MFT catalyst, Fourte, in 2018, the technology has delivered profitability improvements in numerous refineries across the globe.2 BASF introduced the second-generation Fourtune catalyst in 2020.3 This catalyst provides enhanced butylene selectivity through enhancements to the specialty zeolite framework that yields selective cracking of (predominantly gasoline range) olefins to butylenes. In principle, the key elements utilised in MFT should facilitate the generation and preservation of C5 olefins.

Literature indicates that phosphorous-modified microporous and mesoporous ZSM-5 crack C5 olefins into lighter olefins (propylene and ethylene) where both conversion of C5 and the yield into lighter olefins show volcano shaped curves, with respect to strong acidity.4 Zeolitic frameworks used in MFT catalysts have appropriate pore size to C5 generation. Most importantly, the acidity of these frameworks is optimised by the key elements of MFT to minimise C5 olefins from further cracking into lighter olefins (Figure 1).

Over the years, BASF’s partnership with MPC has helped to design the right catalyst for its units and to ensure successful catalyst trials.

Catalyst selection

Figure 3. CRU testing data for equilibrium catalysts drawn for back-to-back trials of BASF’s non-MFT incumbent with Fourte and Fourtune MFT catalysts in MPC unit 1.

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MPC’s FCC catalyst selection philosophy is to thoroughly evaluate competitive catalyst products for a given application prior to using them commercially. The programme testing history has revealed that some proposed catalyst formulations would have a large negative economic impact if utilised in a commercial unit. As such, catalyst testing is employed to validate catalyst performance for a given application. Testing is especially important when evaluating emerging catalyst technology that has limited commercial experience.

MPC utilises a Davison Circulating Riser (DCR) FCC pilot unit, complemented by an Advanced Catalyst Evaluation (ACE) fixed fluidised bed micro-testing unit, along with accumulated

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Testing results

Figure 4. Operation data analysis with regression analysis model on Delta C5= (actual - predict) for unit 1.

Table 1. Regression modelling results for MFT catalyst transitions in MPC units Unit

Catalyst

Delta C5= (wt%)

1

Fourte

0.24

1

Fourtune

0.53

2

Fourte

0.55

3

Fourte

0.33

4

Fourtune

0.10

5

Fourte

0.50

Table 2. KBC kinetic modelling results for MFT catalyst transitions in MPC unit 1 Catalyst

Non-MFT

Fourte

Fourtune

Delta C5= (vol%)

Base

+0.19

+0.36

Gasoline (vol%)

Base

-1.35

-0.19

analytical expertise. These testing capabilities are part of the company’s Refining Analytical and Development (RAD) facility located adjacent to the Catlettsburg refinery in Kentucky, US. MPC’s testing philosophy is to run lab units with commercially-collected materials and adjust the pilot plant operating parameters to generate lab yields that match the commercial units. By minimising offsets between the lab and commercial units, a high degree of confidence can be placed in the measured results. The testing results are used within an FCC process model (KBC’s FCC-SIM) to determine expected yields and optimised unit conditions for each catalyst candidate. Pilot unit results have been validated with post-audits of unit data from numerous commercial catalyst changes.

Another important part of the catalyst selection philosophy is the close working relationship that the company establishes with each of the participating FCC catalyst suppliers. This collaboration is needed to select catalyst candidates formulated to have the highest likelihood of success, and to ultimately support the commercial FCC application for the selected catalyst. MPC strives to understand the technology behind the catalyst formulations so that the technology advantages for a given catalyst can be recognised in the test results. A consistent thread between catalyst design, intended performance, and the test results ensures that final catalyst selection is correct for the operating FCC unit.

March 2022 24 HYDROCARBON ENGINEERING

Figures 2 and 3 show Circulating Riser Unit (CRU) testing results for back-to-back commercial trials from BASF’s non-MFT incumbent catalyst to the Fourte and Fourtune MFT catalysts in an MPC unit 1. MFT catalysts were qualified based on CRU testing results carried out at MPC for lab-deactivated fresh catalysts. As shown is Figure 2, MFT catalysts Fourte and Fourtune demonstrated increased C5 olefins compared to the non-MFT catalyst. Ultimately, the refinery performed commercial trials with both Fourte and Fourtune formulations. In the post-audit study carried out at an MPC facility, equilibrium catalysts were drawn from the unit during each catalyst trial at close to the full catalyst turnover in the unit. These catalysts were then tested in CRU to evaluate C5 olefin production. As shown in Figure 3, the results clearly demonstrated that BASF’s Fourte and Fourtune MFT catalysts delivered increased C5 olefin yields compared to the non-MFT catalyst.

To further validate the results obtained in the circulating riser evaluations, the companies examined unit 1 operating data (Figure 4). Multivariable regression analysis was employed to determine olefin yield deltas observed in the FCC unit. The strongest operating variables found to impact C5 olefin yield shifts include riser outlet temperature, equilibrium catalyst activity, feed API, unit conversion, and ZSM-5 zeolite crystal content of the circulating inventory. The regression results showed that C5 olefin yields increased by an average of over 0.24 wt% for Fourte and 0.53 wt% for Fourtune.

Similarly, regression analyses of several MPC units where MFT catalysts were employed were carried out. In each case, it was observed that C5 olefin gain with the catalyst transitions to MFT catalysts (Table 1). Furthermore, heat-balanced KBC FCC-SIM modelling studies were carried out based on MPC CRU testing results for unit 1, with non-MFT, Fourte and Fourtune. The modelling results at optimised conditions showed a C5 olefin increase for MFT catalysts in both optimised cases (Table 2).

Conclusion In summary, the benefits that MFT-based catalysts provide with respect to delivering profitability through butylene maximisation and octane enhancement can be further magnified for refineries that have the capability to alkylate C5 olefins or otherwise profitably handle additional C5 olefin products. Both Fourte and Fourtune delivered enhanced C5 olefin production to further increase FCC profitability in a number of MPC’s units.

References 1.

2.

3.

4.

NIELSEN, R., ‘Refinery C5s Utilization’, IHS Markit, Report No. 254, (November 2004).

LARSEN, N., CLARK, T., CLOUGH MASTRY, M., and DE SILVA, N., ‘Boosting profitability with butylenes’, Hydrocarbon Engineering, (June 2020), pp. 43 – 46.

LARSEN, N., CLARK, T., DE SILVA, N., YANG, Y., and NEUMAN, D., ‘Boosting profitability with butylenes to propylene ratio’, Hydrocarbon Engineering, (September 2020), pp. 53 - 58.

LEE, J., HONG, U. G., HWANG, S., YOUN, M. H., and SIONG, K., ‘Catalytic cracking of C5 raffinate to light olefins over phosphorous modified microporous and mesoporous ZSM-5’, Journal of Nanoscience and Nanotechnology, (November 2013), pp. 7504 - 7510.

Jitendra Chellani, KBC (A Yokogawa Company), and Hans Lidman, Nynas, outline how to improve margins through feedstock flexibility.

T

he cost of feedstock has a significant impact on revenue and, therefore, the profitability of a refinery and petrochemicals complex. The quality of different feeds governs the overall yields and thus the gross product worth. With feedstock flexibility, these facilities can process diverse feeds from different sources and at different prices. In the dynamic market, the availability and price of feedstocks swing continuously. In addition, crack spreads and product demand have an impact on feed selection. With this, it is evident that being able to know what and how to process a range of feedstocks can improve operating margins. Pacesetters are equipped with precise tools, methodologies and resources to process the best possible feedstocks for their assets. These practices are essential in the existing dynamic market in which various parameters change continuously.

Constraints for feedstock flexibility Though feedstock flexibility is preferred by most refinery and petrochemical complexes, various constraints impose restrictions on changing feed quality. Some of these constraints are imposed

by the logistics and location of the complex. Configuration of the complex, operating limits, and unit design also determine the feedstock quality range.

Logistics Coastal facilities usually have higher degrees of freedom with regard to feedstock flexibility than those that are landlocked. For a coastal complex, the flexibility is determined by the available infrastructure e.g. port facilities, capacity, and the number of tanks. Availability of storage tanks and the set-up for blending different crudes may also restrict the number and types of crudes that can be processed.

The logistics of importing crude through the terminal, infrastructure for transferring crude to the processing units, and product dispatch can be major constraints for the operator. For landlocked facilities, further constraints to feed flexibility are associated with the feed and product pipelines or truck facilities.

Configuration The overall configuration of the refinery and petrochemicals complex decides the feasibility and economics of processing different feedstocks. The design of the crude unit limits the maximum volume of impurities in the fresh feed, whereas the design of downstream process units restricts the qualities of products from the crude unit. The operating constraints of individual process units and equipment also limit the quality and quantity of feed that can be processed in the complex.

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Figure 1. The feasibility of processing new feedstock.

Apart from the operating constraints, the economics of processing new feedstocks should be attractive.

Bottom-of-the-barrel technologies are required to upgrade the heavy crudes, and an integrated refinery/petrochemicals complex can upgrade naphtha in the lighter crudes.

Integrated operation Though the integrated operation of the upstream facility with the refinery, and the refinery with the petrochemical complex, is beneficial, in most cases it eliminates feedstock flexibility. A refinery that is designed to operate with specific types of local crudes without logistics for importing new feeds may not be beneficial throughout the life cycle of the assets. If the price of the local crudes increases or its quality changes, processing imported feedstock and exporting local crudes can be positive for both the refinery and the upstream facility. A similar philosophy is applicable for a petrochemicals complex as well. Rather than processing heavy naphtha from the refinery in a steam cracker, it can be sold to the aromatics complex, and light naphtha can be imported for the cracking. These changes will increase freight costs and the complexity of logistics, but have been found to be economically-attractive in several cases.

Feasibility and implementation of feedstock flexibility The feasibility of processing different feedstocks requires techno-economic analysis of various parameters. The methodology for assessing the feasibility of processing new feedstock is shown in Figure 1. If the logistics allow for processing of new feedstocks, a holistic view of the overall complex is required ahead of analysing individual process units and equipment.

A linear programming (LP) model provides an excellent solution for this problem, as various parameters, including the percentage of new crude in the crude basket, are estimated by March 2022 26 HYDROCARBON ENGINEERING

the model. The optimisation includes constraints such as unit capacities, product demand, and specifications. This step ensures that the processing of new feedstock in the complex is economically-attractive.

Validation of the LP solution can be performed using refinery-wide flowsheets. These flowsheets include reactors which are simulated using non-linear first principles kinetics or equilibrium equations. The fractionation is simplified to represent individual sections in the column rather than each tray. The refinery-wide flowsheets can ensure that the major constraints in the unit including qualities of the downstream units will not be violated with the new feed. The flowsheets can also help to identifiy probable bottlenecks that require further analysis. This analysis is usually carried out using rigorous standalone models of the individual units.

The rigorous models of the units can identify bottlenecks for primary and secondary equipment. This analysis is generally not required for all process units and equipment – the focus area is identified using results from the refinery-wide flowsheets. The first step in this evaluation is to focus on primary equipment, including reactors and distillation columns.

Flooding analysis of the columns may be required with an increase in the unit capacity or with a significant shift in the yield of specific products. A qualifying analysis of secondary equipment i.e. heaters, compressors, pumps, etc. is performed to ascertain violations of any operating limits before performing the rigorous calculations.

The refinery-wide flowsheets and standalone models ensure that the unit operating conditions will be within the safe operating envelope. In addition to this, these models estimate the operating targets which are required for a substantial shift in the unit operation.

After assessing the feasibility of processing new feedstock, its relative ranking is required. This is to ensure that the right feedstock is purchased when all feasible feeds are available to the traders. These feedstocks may be purchased using

Figure 2. A Petro-SIM simulation and Excel workbook for the case study. long-term contracts or on a spot basis. As such, the relative ranking and incremental values of the feedstocks should be available to traders.

The relative ranking of feedstocks is usually performed using complex-wide tools i.e. LP or refinery-wide flowsheets.

For a crude basket, a fixed percentage of crude is replaced with new feedstock to understand the impact on the margins. Based on the shift in the margins, incremental values and the breakeven price of the new feedstock are estimated.

Case study Nynas specialises in the production of naphthenic oils and bitumen which are produced from its various refineries in Europe. In close collaboration with its customers, the company has developed products for various applications.

The company was interested in processing different feedstocks at one of its refineries. The purpose of processing these feedstocks was to improve the yield and quality of the high-value products from the refinery. KBC and Nynas worked together to assess the feasibility of processing various feedstocks.

To understand the operating constraints of the existing assets, a roundtable discussion was conducted. The operating strategy and key bottlenecks observed to date were discussed during this meeting, and operating data for various feeds was analysed. Product yields, properties, and feed assays were also analysed to form a representative operation.

To estimate intrinsic key performance indicators (KPIs) and bottlenecks, the Petro-SIM® model for the operating assets was developed. Results from the simulation were compared with the operating data to improve confidence in the model results. Some of the KPIs estimated by the model provided insights into equipment that are difficult to measure and monitor using just raw data. Along with the model, an Excel® workbook was automatically generated to contain all of the results from the model in a user-friendly tool in order March 2022 28 HYDROCARBON ENGINEERING

to compare various cases. Figure 2 shows a snapshot of the Petro-SIM model and Excel workbook.

The list of probable feedstocks was populated based on discussions with various stakeholders. Rather than performing rigorous analysis for all feedstocks, a preliminary assessment was performed to eliminate similar feedstocks.

A rigorous assessment, which included an adequacy check of major equipment, was performed for the selected feeds.

The simulation model was utilised to identify the key bottlenecks for various feeds. New feedstocks were defined using detailed information in the form of assays, and improved product qualities were targeted in the model. To manage some of the operating constraints, operating targets were adjusted within the operating envelope.

The Petro-SIM simulation was able to identify the feasibility of processing some of the feedstocks and bottlenecks for the rest of the feedstocks with the targeted product qualities. The bottlenecks of primary and secondary equipment were identified using the simulation. Various recommendations were made to eliminate these bottlenecks.

These recommendations are in the form of a roadmap that includes various options for the equipment that will constrain the processing of new feedstocks.

Conclusion Feedstock flexibility is an essential mechanism for profit improvement of a refinery and/or petrochemicals complex.

The feasibility of processing new feedstock depends on the economics and various constraints. An LP model is required to understand the economics of processing different feedstocks and to identify high-level constraints. The results from the LP model should be validated using the integrated complex-wide flowsheet. Petro-SIM flowsheets and rigorous models not only validate the results but also identify constraints at the unit and equipment levels. These models can also estimate the operating targets for new feedstocks.

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Kevin Bockwinkel, Randy Peterson and Samantha Presley, Elessent Clean Technologies, explore the role of gasoline in the clean fuels market.

T

he global fuels market will see a dramatic shift over the next 10 years. Despite its steep reduction in demand in 2020 due to the onset of the COVID-19 pandemic, global liquid fuel consumption is expected to surpass pre-pandemic levels sometime in 2022.1 Stricter fuel specifications, a changing vehicle fleet, the growing role of alternative fuels and the potential for a tightening crude market will determine developments of the fuel market through to 2030 and beyond. Europe has been leading the way towards cleaner, lower-emission fuels. The proposed Euro 7 standards are set to feature even stricter rules on emission levels for all gasoline and diesel cars, vans, trucks and buses. Other industrialised regions of the world are likely to follow. The pandemic has also accelerated the trend to decarbonise, reduce emissions and incorporate renewable fuels.

Despite the increase in the number of electric vehicles (EVs), fuel cells, and other alternatives around the globe, worldwide gasoline demand is expected to grow continuously for the next 15 years and remain above the current level until 2050 (see Figure 1). Demand for lower-quality fuels is set to decline, while demand for higher-quality products will increase. Refiners will not only be expected to produce cleaner fuels, but also to decarbonise their own operations and incorporate renewables.

Alternatives to gasoline are all beset by the challenges of scalability, raw material, sourcing, and capacity. Furthermore, most developing countries have inadequate power grids for reliable EV transportation. When you factor in strong population growth, increasing vehicle demand, and the growing middle-class preference for cars over scooters in countries such as India, as well as the fact that gasoline vehicles are less HYDROCARBON 31

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March 2022

expensive to purchase than a comparable diesel or EV, it is not surprising that industry analysts predict positive global gasoline growth for the next 15 years.

Low-sulfur fuels Global demand for low-sulfur fuels has experienced continuous growth and is expected to continue to rise as environmental regulations become more stringent. New fuel specifications have been introduced in many countries to improve air quality and to limit harmful pollutants from vehicle emissions. Europe, Japan and South Korea led the way by setting a maximum limit of 10 ppm of sulfur as early as the mid-2000s. The US and other countries followed shortly thereafter.

While current maximum gasoline sulfur limits vary widely around the world (see Figure 2), many countries are planning to

introduce lower gasoline sulfur limits of either 50 ppm or 10 ppm within the next five years. In 2021, eight countries and sub-regions announced plans to cut national gasoline sulfur content to less than 500 ppm, or import lower-sulfur gasoline.

The trend of so-called ‘sulfur-free’ gasoline is clearly here to stay.

In addition to the limits on sulfur, many of the national or regional specifications also include targets for octane, aromatics, olefins and Reid vapor pressure (RVP). In fact, according to global industry consultancies, sulfur reduction and octane enhancement are the two dominant gasoline fuel objectives of governments and stakeholders around the world (see Figure 3).

Global demand for octane continues to increase as vehicle manufacturers downsize engines, add turbochargers, and increase compression to render internal combustion engines more efficient. The need for clean, higher-octane gasoline should continue to grow for the next 15 years, as shown in Figure 4. Even with the increase in alternative vehicles, many of the major automanufacturers are continuing to focus on improving the internal combustion engine. Refiners are being tasked with supplying clean, high-octane gasoline to fuel these more efficient engines.

However, typical strategies that refiners use to reduce the content of sulfur and regulated hydrocarbon (i.e. aromatics and olefins) in the gasoline that they produce have a negative impact on octane rating due to saturation of olefins and aromatics, both of which have relatively high octane numbers.

For example, hydrotreating FCC gasoline can reduce the research octane number (RON) by as much as 7 – 10 numbers.

This effect is impacted by the feed properties, as well as the specifics of the process and its operation. As such, refiners must weigh up sulfur reduction strategy vs associated octane loss when optimising operations.

Increasing gasoline pool octane There are different approaches and methods for increasing octane. Oxygenates added to gasoline not only increase (source: Stratas Advisors, December 2021). octane, but also reduce emissions in engines without oxygen sensors and controllers. This includes most small engines worldwide, and many vehicle engines in the developing world. Throughout the 1990s, the preferred oxygenate of US petroleum refiners was methyl tertiary-butyl ether (MTBE), which converts a portion of the FCC butylenes by reacting isobutylene with methanol. Resulting RON and motor octane number (MON) values are very high (MTBE has a blending octane in the range of 106 – 110), and the methanol feedstock is typically low-cost. As such, nearly 90% of the cleaner burning (reformulated) gasoline in the US originally contained MTBE as the prime pollution-fighting oxygenate.

As a result of the groundwater contamination issues experienced in California and other areas, as well as concerns about the possible carcinogenic nature of MTBE, it has now Figure 2. 2021 sulfur limits in gasoline. Note: countries may apply been phased-out of the gasoline pool in the US. lower limits for different grades, regions/cities, or based on average While there are other oxygenates available to content.2 meet the requirements of reformulated gasoline

Figure 1. Global product demand

March 2022 32 HYDROCARBON ENGINEERING

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in Brazil it is made from sugar cane. Together, these two countries account for approximately 80% of global ethanol production. As a result, the strategy used by refiners in the Americas includes adding ethanol, shutting down the MTBE unit, and then alkylating the isobutylene that fed the MTBE unit. This strategy not only allows refiners to meet regulations, but it also adds additional gasoline volume.

Besides ethanol, reformate and alkylate are two additional options that can increase gasoline pool octane. Alkylate is the more desirable choice to meet the new fuel requirements due to its lack of aromatics and because of its ability to upgrade low-value LPG into a gasoline Figure 3. Market share of primary octane grades (shown in %) in product. The alkylation process reacts light countries expecting fuel economy changes. Note: ‘primary market olefins (propylene, butylene and amylene) with octane grade’ means X% or more of the gasoline in the country is at isobutane in the presence of a strong acid this RON or AKI (whichever is applicable).2 catalyst (see Figure 5). The resulting alkylate product consists of a branched paraffinic compound that offers multiple benefits: high yields, high RON and MON, low RVP, zero aromatics and olefins, and very low sulfur. These properties make alkylate an ideal blendstock for cleaner-burning gasoline.

The demand for alkylate

Figure 4. Global gasoline demand by octane type (source: Stratas Advisors, December 2021). (e.g. the US Environmental Protection Agency has approved ethyl tert-butyl ether and tert-amyl methyl ether for blending), there remains some concern over the toxicology of these oxygenates. However, despite the choices made in the US, MTBE is still widely used throughout the rest of the world, particularly in Asia.

In the US today, the primary replacement oxygenate to meet regulations and enhance octane is ethanol. Unlike MTBE, ethanol is a renewable fuel, but requires additional handling and blending investments. As with MTBE, ethanol provides an octane boost to the gasoline pool as it has a blending octane of 110+. Its oxygen content is approximately 35% compared to MTBE’s content of 18%. Therefore, approximately half as much ethanol is required to meet specific oxygen requirements.

Most gasohol (gasoline and ethanol) grades in the US are currently limited to 10 vol% ethanol to minimise vehicle fuel system deterioration. In the US, ethanol is produced from corn; March 2022 34 HYDROCARBON ENGINEERING

While alkylate already represented 13% of the gasoline sold in the US in 2019, it accounted for less than 5% in many other countries, including Russia and Argentina. A region which has seen a significant change in its gasoline pool composition due to regulatory changes over the last 10 years is China. Less than 15 years ago, alkylate made up below 2% of the gasoline pool.

Currently, it makes up over 6% (see Figure 6), with that number expected to grow as more alkylation units come online.

In 2019, the US accounted for 56% of global alkylate production, followed by Asia (14%) and Europe (12%). Due to heightened global environmental awareness, demand for alkylate is forecast to grow steadily between 2021 and 2031.

According to industry reports, global alkylation unit capacity grew from 2.4 million bpd in 2015 to 2.5 million bpd in 2020, and is expected to expand further to an anticipated 2.75 million bpd by 2036.3 China’s alkylate industry is currently the fastest-growing in the world.

Historically, international demand for alkylate has lagged behind that of the US due to economics and less strict environmental laws. Many countries outside the US have imposed substantially higher taxes on finished gasoline products which reduces the mileage driven/year per capita.

Europe, for example, has long punished gasoline with higher taxes vs diesel. However, as populations and income continue to rise in many developing countries, more gasoline will be consumed. Gasoline engines are less expensive to manufacture than diesel. When growing concerns about pollution are factored in, the status quo of using highly aromatic and/or olefinic fuels is no longer acceptable.

Recently, there has been a significant shift in the international refining industry as emphasis is placed on high-conversion refineries. This is due, in large part, to heightened worldwide environmental awareness and low-sulfur gasoline legislation. As countries implement clean

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fuels specifications, companies that supply the fuels are being pushed to revamp existing facilities or construct grassroots refineries to meet increasing demand for cleaner burning and environmentally-friendly gasoline.

Alkylate serves as a viable solution for meeting the stricter gasoline regulations and, therefore, will likely make up a larger portion of the future gasoline pool in countries outside of the US.

The economics of alkylate Under current market conditions including rationalisation of global capacity, the alkylate produced in the alkylation process offers ® refiners high margins, reflecting the upgraded Figure 5. STRATCO alkylation process. value of the refinery’s gasoline stream. At the same time, the feedstocks used for alkylation – butylene, amylene or propylene from the refinery’s fluid catalytic cracker, and isobutane sourced from the cracker, reformer, or distillation column – are of greater value as alkylate than they are if used for other applications such as LPG. Alkylation may therefore provide an improvement on gross margins compared to the use of an MTBE unit.

Rather than purchasing methanol to make MTBE, refiners can use isobutane to produce a larger volume of alkylate. Similarly, refiners can direct propylene and butylene that are currently supplied to a polymerisation unit, towards an alkylation unit instead, for an even greater yield per volume of olefin (see Table 1).

In a new plant, or one without an existing Figure 6. Global shift in gasoline composition by region, 2020.

MTBE or poly unit, it is necessary to consider the product requirements such as regulations, site-specific octane margins, and economics, in order to decide Table 1. Yield comparison which methodology is most appropriate for octane MTBE Polymerisation Alkylation enhancement and low-sulfur gasoline production.

Yield vol. (C5+ gaoline 1.25 from reacted olefin)

0.83

1.78

Conclusion While gasoline alternatives will increasingly come onstream in the next few decades, there will be growing demand for cleaner conventional fuels. Refineries are already adapting. As alkylation is one of the more attractive options for meeting new fuel requirements, this market segment is set to grow.

Since the turn of the century, refiners have overwhelmingly selected sulfuric vs other alternatives such as hydrofluoric acid (HF), solid or ionic liquid acid catalysts when building new alkylation units.

With over 80 years of alkylation research and process design, along with extensive experience in optimising, troubleshooting and analytical testing at customer sites, Elessent has licensed more than 100 STRATCO alkylation units worldwide (see Figure 7), with a combined capacity in excess of 915 000 bpd.

References Figure 7. STRATCO alkylation unit.

March 2022 36 HYDROCARBON ENGINEERING

1.

2.

3.

Stratas Advisors, (December 2021).

Stratas Advisors, (May 2021), www.stratasadvisors.com Stratas Advisors, ‘Global Alkylate Outlook’, (February 2021).

Wole Olowu and Tim Oubre, Athlon, a Halliburton Service, USA, offer solutions to some unique desalter challenges that the company has helped refiners to overcome.

F

or many desalter challenges, there is a proven solution to mitigate the impact on a refinery’s performance and economics. Whilst troubleshooting, companies’ operations teams are often taught the following: when you hear hoofbeats, think horses not zebras. However, once in a while there are zebras.

This article details some of the most difficult situations that Athlon team members have encountered over the years, which may offer a solution to the reader’s unusual desalter challenges.

emulsion between the two phases. In Figure 1, clean water is seen at the 3 ft and 2 ft, 6 in. try-lines, but the desalter effluent from the bottom of the vessel shows 10% oil.

In this example, the plant assumed (and had been told by the chemical supplier) that there was heavy oil and/or asphaltenes in the brine. A sample and extraction of the oil in the effluent with heptane revealed that the oil was heptane soluble, which eliminated asphaltenes as the culprit. Somehow, oil was transferring through the water phase to the effluent.

Case one: three phases in a desalter

A skin temperature profile was conducted on the vessel, using corrosion inspection ports on the insulation. Skin temperature vs desalter oil temperature suggested significant mud buildup. A continuous bleed of the two bottom try-lines for approximately 30 minutes eventually

Challenge

It is very unusual for a desalter to have three phases.

Usually, there are only two – oil and water, with an

Solution

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yielded oily water. An extended mud wash of the desalter, employing 50% of the mud wash header at a time, removed a significant amount of solids. Clear water was eventually re-established in the effluent.

Cleaning and inspection of the desalter three months later revealed a large buildup of solids at each end of the vessel, as suspected from the skin temperature profile. The zone around the sample taps

for the try-lines had a large, hollow depression carved out of the solids, creating a ‘stilling well’. The three-phase situation was created by a dead zone at the end, near the sample points that allow free water to separate in this large quiescent zone, resulting in a false sample reading. By mud washing, additional water residence time was provided for the oil and water to separate in the desalter, resulting in oil-free effluent.

Case two: plugged valves created a vortex Challenge

Figure 1. Oily water was being drawn from the bottom of the desalter, containing 10% oil despite samples 2 – 3 ft higher in the vessel showing clean water.

The bottom two try-lines were running clean water, but the effluent water consisted of 5 – 10% oil more than 75% of the time on average.

It is typical for desalters that have been modified with new internals to have the water draw header removed and the water draw flush with the bottom of the vessel. It is not typical for desalters to have vortex breakers as part of their design. The first step in troubleshooting oily effluent is to carry out a temperature survey of each of the water draw valves to check for any plugging.

Figure 2. Lower temperatures on the end valves indicated plugged valves and buildup in the desalter, resulting in a vortex over the two unplugged valves, which drew oil into the effluent brine.

Figure 3. Over a period of approximately one week, the salt content in this refinery’s desalted crude increased to near 7 pounds per thousand barrels (PTB) from a normal 1 – 2 PTB.

March 2022 38 HYDROCARBON ENGINEERING

Solution

The temperature readings of the valves on the end of the desalter were up to 125°F cooler than the bulk oil temperature. As the team moved closer to the middle of the desalter, the temperature of the valves rose, indicating more activity and flow.

Three of the valves were completely plugged and one was restricted. With a flow that is supposed to go through six valves only going fully through the two right of the desalter’s centre (see Figure 2), a vortex was created.

The process is similar to water draining from a bathtub. If it is drained too fast or faster than the drain line can handle, it can create a whirlpool at the drain, pulling in air with the water. The energy of all of the brine flowing through two of the six lines was sucking a little bit of oil out of the interface, leaving the desalter in the effluent water.

The team performed a mud wash and also blocked in several of the valves at a time to force out the buildup in the plugged valves. They cleared all of the valves except for those on the end, which had too much buildup. However, once the middle four valves were opened up to good flow, the effluent cleared up.

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Case three: maintain material balance Challenge

Routine analysis showed that the salt content in the refinery’s desalted crude was rising (see Figure 3). Water carryover was less than 0.3%, mix valve settings were within control ranges, and no changes in crude slate or wash water quality or quantity were noted.

Solution

It took a few tests to identify the problem, as this is not normally expected. First, with no excess water carryover, the wash water rate and mix valve pressure drop were increased.

Second, a material balance was performed to compare how much salt the crude was giving up and wash water was being taken on. This did not reveal an obvious issue.

Material balance closure error was within 7%. Testing the wash water rate with an external flow meter indicated that the flow to the oil was good.

Finally, the team took a sample downstream of the mix valve, performed a water spin-out, and found that only 2.5% water was entering the valve mix, even though the flow meter indicated that 5 – 6% was being added into the system. Approximately two-thirds of the wash water was getting lost somewhere between the wash water pump, the flow meter, and the desalter.

A measurement of the chlorides in the desalter’s bottom try-line measured 1265 ppm, and the brine water after the exchanger measured 525 ppm (see Figure 4).

This helped the team to determine that the brine water vs fresh wash water exchanger had exchanged more than just heat between the two water streams. It was assumed that there was a significant leak.

Based on the flow meter and water spin-out, as well as the chloride dilution from 1265 ppm to 525 ppm, it was determined that two-thirds of the wash water was bypassing the desalter. This significant leak was causing the poor salt removal.

The exchanger was bypassed and checked for leaks.

Significant general corrosion created failures in at least 40 tubes, with pressure testing resulting in an additional 80 tubes requiring plugging. The bundle was returned to service until a replacement could be delivered and installed.

In all of their years of collective experience, Athlon’s team members have rarely seen a leak in this exchanger service as sudden and significant as this refinery experienced. The current best practice is to sample and test the bottom try-line for chlorides once a month and compare the chloride content to desalter effluent chloride levels.

Case four: control valves created too much shear Figure 4. A measurement of the chlorides in the desalter’s bottom try-line measured 1265 ppm, while the water after the exchanger contained 525 ppm, demonstrating that something was diluting the water leaving the desalter.

Challenge

Before a crude unit was shut down for a turnaround, it was running at its targeted crude charge rate of approximately 150 000 bpd. When restarting after the turnaround, the charge rate to the unit was initially set at 90 000 bpd, with a plan to ease back up to normal operations.

During routine testing after start-up, it was observed that the water content remaining in the desalted crude was much higher than normal.

Levels ranged from 0.6 – 0.8% instead of 0.1% (see Figure 5).

This was a big and costly problem, as the refinery was losing valuable revenue every day that it could not return to its pre-turnaround charge rate.

Solution Figure 5. Water in the desalted crude rose to more than 1% after start-up, when the flow control valves over-sheared the emulsion at a lower charge rate.

March 2022 40 HYDROCARBON ENGINEERING

After a review of all of the mechanical changes made during the turnaround, and any procedural changes to identify potential problems, a specific change

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Figure 6. After a turnaround, the chlorides measured in the overhead and hydrolysis rate were significantly higher than pre-turnaround values. The desalted crude salts, however, were in line after start-up.

to control the flow at the lower crude charge rate was identified.

The refinery in question injects all of its desalter wash water upstream of the crude preheat train. Single stage desalting and an undersized brine water exchanger made this an effective way to increase mixing and reduce overhead chlorides. This process change had been made since the previous turnaround. Part of the change modified the start-up procedure so the water was to be injected into the desalter mix valve until the charge rate of 150 000 bpd was established.

After full rates were reached, the wash water was then to be switched to the frontend of the preheat train. This water wash injection was located between the crude charge pump and the flow control valves. The pressure drop through the control valves at 90 000 bpd created an emulsion that could not be resolved in the single-stage desalter. The water was diverted to the mix valve for three days as the charge rate was increased, and the water carryover decreased to less than 0.2%.

Once up to full charge, the water was then returned to the frontend of the preheat and dehydration remained at less than 0.1%.

Another lesson to learn from this case is to ensure that the operations teams and supporting vendors review turnaround and start-up procedures. Diverting the water to the mix valve at start-up was already documented in the procedures.

Case five: high hydrolysis rate caused by an open isolation valve Challenge

After a brief turnaround, a refinery’s desalted crude numbers were within control ranges, but the chloride numbers in the overhead were twice the KPI limit of 20 ppm. This was also reflected in a high hydrolysis rate, which is the percentage of chlorides coming out of the desalter compared to what is measured in the overhead (see Figure 6). The hydrolysis rate was so high that it did not make sense. There was no reason for it to be that high.

Solution

Athlon’s team reviewed the system after start-up. The sample point for the desalted crude was checked, as was the overhead water sample. The desalter had been isolated during the turnaround to repair an entrance March 2022 42 HYDROCARBON ENGINEERING

bushing. The desalter was isolated and bypassed with two block valves and a bypass valve and associated piping. Inspection of this bypass valve showed that it was partially open. It had not been fully closed after start-up.

The sample point was upstream of where the bypass line joined up with the desalted crude. As a result, a portion of the raw crude was bypassing the desalter, resulting in a higher amount of salt in the desalted crude than in the sample, which was inside the bypass loop. It was reported that 1 lb of salt remained in the desalted crude, when it was actually closer to 3 – 4 lb.

Once the bypass valve was fully closed, chlorides in the overhead came down and the hydrolysis rate returned to a believable range.

Conclusion Athlon’s toolkit of process treatment solutions is stronger because of these difficult desalter experiences.

The company leverages and builds on them each time that it collaborates with teams and customers, as it does not want customers to face challenges such as these.

Steady-state operations is always the goal, but it is important to provide support to clients that require a solution.

The following checklist summarises the key take-aways from these unusual desalter situations: nn If three phases are being drawn from a desalter (oil, emulsion and water), something is wrong. nn Low desalter water draw valve temperatures can indicate plugged valves and solids build-up within the desalter. nn Leaky water exchanger tubes can impact desalter performance. nn Flow control valves create tremendous shear. They are not mix valves. When used, they can result in an emulsion that is hard to break. nn Review shutdown, turnaround and start-up procedures, especially if they have changed since the previous start-up. nn Document turnaround activities for a complete start-up checklist and a breadcrumb trail to follow when something goes wrong.

Acknowledgement

The authors would like to thank Harold Eggert, John Jacobson, Jim Devine, Chip Aloisio, Wesley Teasdale, Fred Brown and other process treatment experts, whose experience and expertise over the years have helped prepare this article.

Water and Process Treatment SUPERIOR SERVICE AND CHEMICAL APPLICATION EXPERTISE TO MAXIMIZE ASSET VALUE Our experienced team provides customized water and process treatments, dedicated engineering, and expert technical support to refineries worldwide.

We can help you improve reliability, increase throughput, and enhance the efficiency and flexibility of your operating units. We have a proven history of working with refineries to identify, deliver, and document process improvements and cost avoidance.

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T

Neil Richards, PS Filter, Canada, explains why buying the cheapest product is not always the best solution.

he constraints and pressure placed on producers to reduce costs in order to maintain profitability in the face of slumping revenues is enormous in the energy sector. This is nothing new when it comes to up and down cycles of commodity products such as oil and gas, but in today’s environment, there are indiscriminate cost-cutting measures that will have severe ramifications, costing operators dearly.

Whilst this article will specifically address filtration-separation, there are many other areas with indiscriminate cost cutting that are also impacting production and operations in detrimental ways that have yet to be addressed.

It is unrealistic and impractical – from both a functional and safety standpoint – that the cheapest possible product will always be the most suitable.

Filtration specifications are put in place for a reason and not following them will lead to various issues, such as: n Amine foaming – an excessive amount of chemicals to control because of poor effluent filtration quality. n Increased operator exposure to hazardous hydrogen sulfide (H2S) – excessive sour service maintenance and filter changes. n Water flood/water disposal/formation damage/plugging – resulting in lost production. n Excessive maintenance of rotating equipment as passing contaminants downstream causes erosion, wear and plugging issues for equipment such as pumps, contactor tray towers, heat exchangers and carbon beds. n The environmental impact of high disposal costs (of thousands of dollars) due to inefficient filters that are underperforming. This can be avoided with the right technology in place.

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Figure 1. Schematic of Alberta NGL flow.

Figure 2. A gas processing plant where PS Filter tested its filtration

systems.

March 2022 46 HYDROCARBON ENGINEERING

Filtration needs to be addressed as a systems approach. There is not one solution that fits all – what may work in one process may need to be fine-tuned to work effectively in another situation.

Buying the cheapest and least effective product is not a viable answer to reducing overall costs, and this is where the expertise of a trusted partner is required.

PS Filter has over 32 years’ experience working on various filtration applications in the energy sector, and works with its customers to understand their process application requirements to ensure a positive solution.

Hundreds of millions of dollars are spent each year in Alberta, Canada, alone on consumable filtration for oil and gas processing operations. An estimate based on the company’s sales volume in this sector would be a total market in the range of US$200 million+ (based on the company’s market share, which it estimates at 5% [US$1 million] consumable filter sales yearly).

There is enormous growth potential. With the right strategy of using customer investigation to better understand their needs, suppliers can work to provide true value in this area.

The market consists of many procurement types, from company head offices to various field offices at plant facilities, and they all have purchasing power based on their individual budgets. Each group may be influenced by technical specifications from engineering or operations input, or they may be free to make purchases based on their own criteria and past vendor experiences. Operator input weighs heavily on filter products that may or may not be chosen, and it is imperative to understand what influences decisions in order to ensure the provision of a product that effectively meets or exceeds requirements.

Based on industry knowledge and experience, companies must work together with buyers and users to educate them to provide a technically-superior product that will improve filtration systems and lower total filtration costs. This is done by first providing a minimum viable product (MVP) to gain trust, followed by the introduction of upgraded pleated medias that can provide longer intervals between servicing, and fewer filter disposal costs. On the surface, a less expensive commodity type product may appear to offer cost savings, but when increased operational costs, lower performance affecting downstream

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operations, and the added disposal costs are factored in, this turns out to be an expensive choice.

Even with all of the advances in filtration technology, many facilities continue to make purchases based on the assumption that they are saving money by buying the least expensive filter product. What is often overlooked is the added costs that may be incurred whilst making this choice. Customers should be supplied with informative filtration information ahead of a purchase in order to assess the benefits of working with a knowledgeable supplier who can also provide technical support on many levels.

To form the basis of a strategy and ensure that everyone is on the same page regarding CAPEX and OPEX expectations, it can be helpful to ask buyers and users what they consider to be the most important feature(s) of their filtration requirements. This might include some or all of the following: nn Efficiency of the product (nominal, absolute, high efficiency). nn Price. nn Dirt capacity (lower operational servicing). nn Availability (inventory-logistics). nn Any special features deemed important. nn Technical support.

Figure 3. A gas conditioning filtration skid.

Common mistakes Three common filtration mistakes that can cost operations are as follows: nn Choosing the wrong efficiency filter to meet performance criteria. nn Buying the cheapest filter thinking it will save money. nn Not having all of the filter performance information documented to ensure it will be operationally suitable.

Questions to ask Three simple questions to ask when choosing a filter are: nn Does the filter have the dirt capacity required to be operationally feasible? nn Does the filter have the performance efficiency required for a particular process? nn Is the filter designed to meet desired flow requirements so that it will be cost-effective?

The consumable filter business is an area for improvement, and the market is growing as companies strive to increase oil and gas production targets as environmentally-consciously and cost-effectively as possible. Companies need to ensure that their target customers have a positive experience, and it is important to demonstrate authenticity in order to offer value in all products and services. Building success in this market will provide added references and case histories that can be used to expand into the upstream, midstream and downstream oil and gas market, and present opportunities for company growth.

There are thousands of companies in the supply chain.

Unless these companies can find ways to add value to the end user, they will be faced with difficulties. Some of the current trends in oil and gas supply chain management include:1 nn Increasing supply chain responsiveness. nn Forming strategic partnerships – successful and trusting relationships with top-performing suppliers. nn Operations demand management – match demand to available capacity. nn Supply chain process integration – when supply chain participants work towards a common goal.

Even though the market is very concentrated, with lots of buyers and sellers, there is still room for a new entrant who can bring fresh ideas and process innovations to the table to improve the bottom line of its customers.

Conclusion In Alberta, there are over 600 active gas processing plants that recover natural gas liquid mix or specification product, 11 fractionation plants that separate out natural gas liquid mix streams into specification products, and eight straddle plants.

No matter what area of energy production, filtration is of paramount importance to ensure production is optimised and operational costs are kept within budget forecasts. Producers need to work with suppliers who have a proven project track record and the experience to understand the intricacies of each process application.

Reference Figure 4. PS Filter’s multi-plex filtration package.

March 2022 48 HYDROCARBON ENGINEERING

1.

‘Plants and facilities’, Alberta Energy Regulator, (June 2021), https:// www.aer.ca/providing-information/data-and-reports/statistical-reports/ st98/pipelines-and-other-infrastructure/plants-and-facilities

Decarbonisation efforts worldwide have accelerated the shift from fossil fuels to renewables. One way many industrial organisations can embrace this is by changing process heater systems from fuel-burning to electric. Dennis Long and Roly Juliano, Watlow, USA, detail why.

T

here is a sea-change occurring when it comes to process heating. Pressures to electrify all industrial processes are increasing, from governments, non-profits and business leaders alike. However, the transition from gas to electric process heating is not as simple as flicking a switch. This article illustrates, in broad brush strokes, how that transition can occur (and why it should happen sooner rather than later).

The market pull toward electrification and decarbonisation According to the US Environmental Protection Agency (EPA), a substantial portion of global greenhouse gas (GHG) emissions (21% as of 2010) comes from industrial sources burning fossil fuels. Much of this energy is burned onsite for energy and heating needs. In fact, the US Department of Energy’s (DOE) Energy Information HYDROCARBON 49

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Administration estimates that the industrial sector uses approximately 24 quadrillion Btu/yr of heat, or roughly one-third of the country’s Branch circuits Connection delivered energy supply. Process heating required cables required applications alone account for 36% of total 131 393 delivered energy consumption within the 21 63 manufacturing sector. Thus, there is increasing 13 39 pressure to decarbonise and electrify, where possible. This pressure has resulted in the following measures: nn In 2015, the historic Paris Agreement was signed, with countries agreeing to curb the increase in global average temperature well below 2°C, and pursuing efforts to limit the temperature increase to 1.5°C. That same year, the Deep Decarbonization Pathways Project (DDPP) suggested fuel switching as a key part of any strategy to reduce carbon emissions. nn In 2017, the DOE published a report analysing US energy use and GHG emissions in scenarios where there is widespread electrification and solar power decarbonisation. nn In 2018, the Bank of England released a statement stating that the financial sector has been “too slow in divesting investments into fossil fuels” and warned that assets could become useless. Two years later, BlackRock leads several firms that have begun divesting themselves of companies that are not addressing climate change. nn After years of protests, 17 000 Dutch citizens sued Royal Dutch Shell in 2019. In May 2021, a Dutch court ruled that the company must dramatically reduce its carbon emissions by 45% compared to 2019 levels.

Table 1. Reduction in cable size and number of branch circuits (7.5 MW heater example)

MW

Voltage supply (AC)

Phase

Total amperage

7.5

690

3

6275

7.5

4160 USA

3

1040

7.5

6900 IEC

3

627

Figure 1. Fuel gas heater for a gas turbine.

As a result of these pressures, industry has been accelerating the pace of decarbonisation. In a recent survey, Watlow found that over 90% of respondents in the oil and gas industry have developed, or are in the process of developing, a long-term strategy to reach sustainable, low-carbon site statuses.

The electrification of heat

Figure 2. Gas turbine energy station.

March 2022 50 HYDROCARBON ENGINEERING

Electrification of processes – and more specifically, process heating – is one of the key strategies for addressing climate change concerns in oil and gas. This requires shifting to electric heat exchangers in several applications. These electric heaters do not burn fossil fuels and can be powered via renewable energy sources.

Electric heat exchangers are no stranger to oil and gas operations. Historically, however, they have only been used in applications with a nameplate under 1 MW (for example, glycol reboiler heaters, knock-out drum heaters, seawater heaters, fuel gas heaters and preheaters, lubrication oil and seal gas heaters, etc). Gas-fired process heaters are still used in several ways, since the Btu requirements for some of these processes can only be met by electric heaters with a much higher wattage. Some examples include: nn Feed/product exchanger (2 MW). nn Dehydration inlet preheater (3 MW). nn Heater treater (4 MW). nn Molecular sieve regen (6 MW). nn Waste gas heater (6 MW). nn Once-through steam generator (20 MW). nn Crude oil heater (28 MW).

nn nn nn nn nn nn

Hot oil heater (32 MW).

LNG vaporiser (34 MW).

Thermal oxidiser (54 MW).

Hot water heater (56 MW).

Crude heater (150 – 200 MW).

FCC heaters (150 – 200 MW).

Currently, there is a large and growing potential to use electric heaters for applications requiring more than 1 MW but less than 15 MW. These span several areas, including oil and gas production, as well as: nn Renewable fuel production: hydrocarbon biofuels that are chemically-identical to petroleum gasoline or diesel, but produced from biomass sources through various biological, thermal and chemical processes. nn Ammonia production: ammonia produced using hydrogen from water electrolysis (green ammonia), fossil hydrogen (grey ammonia) or natural gas feedstock (blue ammonia). nn Carbon recycling: methanol created from carbon dioxide captured from industrial exhaust combined with hydrogen (either collected from industrial waste gas or from water through electrolysis). nn Distillation column and/or fractionation column reboilers: electrical generation using energy supplied by the reboiler system of a distillation or fractionation column.

Aside from reducing the use of fossil fuels, electric heaters and heat exchangers have other advantages, including: nn Less thermal lag: temperature is controlled through direct application of electricity.

nn Safer operation: no fossil fuels to burn or combust. nn More uniform distribution of heat: more control of the current means more control of the heat. nn Smaller overall footprint: there is no need for storage of heating oil, for example, or transporting it from stage to stage.

Can electric really pull its weight?

What matters most in achieving process heating parameters is not the method of heating, but the heat flux of the heating surface. When it comes to these kinds of applications, electric heaters can safely achieve operating temperatures comparable to gas-fired heaters and with better uniformity and control. Watlow has been a leader in innovative heat exchanger design, introducing its POWERSAFETM integrated medium voltage control and heating solution. The POWERSAFE offers longer heater life, allowing fossil fuel solutions to be replaced with a clean electric solution. It also meets the necessary agency requirements to help make processes safe and reliable.

Wattage size requirements for electric thermal equipment have been on the rise. This makes medium voltage solutions attractive because they reduce overal installation costs for the customer compared to low voltage electric heaters. The POWERSAFE medium voltage solution lowers this cost by eliminating unnecessary cables and additional transformers. Thanks to this innovation, the company is contributing to the decarbonisation needs of many industries that, historically, have faced the greatest challenges when it comes to controlling emissions.

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Ilan Toledano, Wattco, Canada, evaluates how downstream oil and gas industry leaders are managing the energy transition.

he oil and gas industry was hit hard by reduced demand during COVID-19 lockdowns. For many oil producers, it was a wake-up call, as they recognised the need to make big changes. Climate concerns and changing energy demands have always meant that the industry would have to adjust, and companies are now starting to make arrangements to meet net zero goals. This article will look at why and how oil and gas companies are handling this transition.

Why the transition is happening now The conversation around an energy transition has been ongoing for decades. While it has always been considered as an inevitable event, the goalposts seemed to be moving back from one generation to the next. However, it is starting to happen. Why now?

Climate concerns have been one of the biggest drivers. In 2006, Al Gore’s ‘An Inconvenient Truth’ placed the climate crisis in the spotlight. Debates over global warming went back and forth, delaying action. Today, however, scientists are in consensus, and the general public supports the reality that climate change must be addressed.

While companies are beginning to make changes to reduce their impact, it is not all about saving the environment. A more environmentally-friendly approach is important for company reputation. There is immense pressure from the public and from governments to reduce environmental impact. The oil and gas industry is especially under scrutiny. Making smart energy choices is not just about going green, it is about survival.

While these factors have existed for 15 years, a transition was not always practical. However, technology has now started to catch up, making it possible to fill this need.

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There are increased alternatives available, and energy sourced from wind, solar and batteries has the capacity for greater output at better price targets than ever before.

Not only can the oil and gas industry begin to incorporate alternative energies into downstream processes, but they can actually reduce costs and improve efficiency.

Investing in these technologies is not just about impacting processes and reputation. It is also about future-proofing. As battery capabilities continue to improve and pressure to change grows, these technologies will be a necessity for the downstream oil and gas industry.

The climate of the energy industry is changing. Leaders who are taking early transitionary steps are helping to protect jobs, profits, and the future of the oil and gas sector.

Managing the energy transition for downstream oil and gas processes is not as simple as switching over to purely zero-emission energy sources. Instead, industry leaders are using the available technology and resources to revamp processes and operations to increase efficiency, decrease waste, and reduce environmental impact.

The next section of this article will outline a few methods that downstream oil and gas companies are using to manage the energy transition.

By investing in the battery revolution, the downstream industry is reducing its reliance on fossil fuels for primary or backup power.

Investing in low-emission technologies

Improving operational efficiency

Immersion heaters play a series of essential roles in downstream operations, from preheaters and boilers in the actual refinement process, to freeze protection in pipelines and heating storage tanks.

Older technologies made use of combustion heaters and heat exchangers. These were large, produced emissions, and were susceptible to damage, resulting in shorter lifespans. The waste in spending, repairs, carbon emissions and inefficiencies were adding up.

Now, downstream oil and gas companies are looking to electric immersion heaters. Electric power is almost 100% efficient, and can achieve target temperatures quickly and emission-free. As a result, these heaters allow for greater efficiency from both a carbon and profitability standpoint.

The deployment of new technologies in batteries, electricity and renewables is not just about reducing emissions and reliance on fossil fuels. Advances in this technology are helping to increase overall operational efficiency.

In refinement, target temperatures can be reached faster and with less energy by leveraging electric power.

This means that more crude oil components can be separated and refined, generating more products faster, and at a lower operational cost.

Furthermore, these technologies have simpler designs than those using combustible fuels. As a result, their maintenance is simpler and less frequent. They also have longer lifespans and maintain their efficiency for longer, which results in lower repair/replacement costs and fewer breakdowns that interrupt operations.

Investing in and deploying battery technologies The adoption of electricity for oil refining, storage and transportation is helping to reduce costs, increase efficiency and decrease carbon footprint. However, in some instances, it is not the most practical solution.

Remote areas without (or with limited/unreliable) access to the electric power grid can be a problem. They need to supply their own power, supplement it, or at least have a backup power generation option. Because of its portability and lack of reliance on a grid, fossil fuels have long filled this role.

However, today’s batteries are increasingly capable of delivering high-capacity energy and reliability. This can allow operations without (or with interrupted) access to the grid to function at full capacity. Furthermore, batteries are well-suited to working with higher-efficiency electric downstream oil and gas processing technologies.

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Increasing use of renewable energy While the world still needs oil and gas, the downstream process is becoming less reliant on this energy source to refine it. Instead, the industry is beginning to refine its own approach by increasing the use of alternative energy.

Solar and wind energy have undergone significant improvement over the last couple of decades, not only increasing their output but also becoming more affordable.

Now, in the right environment, they can be the ideal power source. In hot climates with long hours of sunlight and mild/short winters, solar panels can be the most cost-effective power option.

The incorporation of electric and battery technologies is also solving key renewable issues. When there is insufficient wind or light to generate alternative energy, operations used to have to switch back to fossil fuel or electric power. Any energy that was not used or sold back to the grid was lost. Now, these technologies allow for better storage, increasing the capabilities of renewable power sources. As such, they have become a more practical solution than they once were.

Decarbonisation Some of the biggest movers and shakers in the oil and gas industry are looking to decarbonise their operations.

ExxonMobil has one of the largest downstream businesses in the world for fuels and lubricants. Recently, it announced a plan to cut its greenhouse gas emissions by 15 – 20%.

Occidental Petroleum, which has significant downstream and midstream assets, is also looking to decarbonise its operations. To accomplish this, it has built a plant to capture 500 000 tpy of CO2.

Leaders in the downstream oil and gas industry have taken note of the need for change. To this end, they have begun the first steps in an energy transition that can protect the industry while meeting changing policies and social/political and/or environmental pressures that it faces.

Fred J. Gossen, Jr, Hallwood Modular, USA, discusses the importance of facility siting in order to ensure worker safety in high-risk environments.

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or high-risk environments such as petrochemical and chemical operations; natural gas liquids extraction plants; natural gas liquefaction plants; and refineries, the placement of occupied buildings or facility siting is an important issue. Within such plants, facility siting is a process that assesses occupied buildings that have potential exposure to an explosion, fire and toxic hazards. It is a continuous process that begins with an initial study and is revalidated with any changes to the facility.

The Occupational Safety and Health Administration (OSHA) 29 CFR Part 1910 standard is a requirement for

Process Safety Management (PSM) that governs facility siting. In addition, the American Petroleum Institute (API) has issued guidance and recommended practices for facility siting in the following publications: n API RP 752, Management of Hazards Associated with Location of Process Plant Permanent Buildings, Third Edition, 2009. n API RP 753, Management of Hazards Associated with Location of Process Plant Portable Buildings, First Edition, 2007. n API RP 756, Management of Hazards Associated with Location of Process Plant Tents, First Edition, 2014.

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Facility siting checklist for temporary projects In 2019, Engineering Stack published a bulletin and project checklist entitled ‘Siting or relocating temporary structures for use during construction or facility turnarounds’.1 The bulletin contains facility siting requirements for occupied temporary structures situated in a location with the potential

Figure 1. Top: a two-story blast-resistant structure

includes a lunchroom, meeting rooms, and supervisor offices in the work zone/process area. Bottom: lunch tent and soft-sided supervisor trailers outside the work zone/process area.

for fires, explosions or toxic release. It includes a checklist that should be initiated, completed, routed and approved by line management, at a minimum. Team members should include an area process hazard analyses leader or resource; a facility siting review team member; an area production or maintenance manager or superintendent; and at least one occupant of the proposed temporary structure/portable building. The checklist is aimed at collecting the following information: nn Type of temporary structure. nn Purpose of structure. nn Proposed location of the structure. nn Estimated time that the structure will be present at the location. nn Estimated occupancy rates (hr/week). nn Potential hazards – fire, vapour cloud explosion, toxic materials, dust, and other. nn Whether the proposed location has an overpressure at or above 1.0 psi. If so, additional explanation and risk analysis is required. nn Whether temporary structure connects to – and its occupants can hear – site and unit/area emergency alarms and public address system messages. nn Temporary structure’s visibility to local windsocks or similar methods to detect wind direction. nn Location of designated muster point for accounting; location of designated ‘safe haven’ (if applicable); special PPE requirements (e.g. number of staged emergency escape breathing devices); special controls (e.g. electrical classification, lighting, detectors).

The team members are then required to note whether the proposed temporary structure location is acceptable or not, based on this checklist information and facility siting analysis.

Building assessment

Figure 2. Depiction of interior layout and design optionality/limitations based on interior columns.

Top: BRM multiplex designed around a single column.

Bottom: BRM multiplex designed around multiple columns.

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Buildings should meet local building-code regulations and applicable company design standards, and comply with the relevant regulations of the National Fire Protection Association - Life Safety Code. Buildings that are intended to house personnel or critical functions within fire hazard zones should be fire-resistant. Exterior walls facing the fire hazard and building roof should have a fire-resistance rating of at least 30 minutes. Door exits should be positioned sufficiently to permit occupants to evacuate from the fire hazard and move to a safe location.

For buildings situated in border areas or different production areas, coordination between departments is necessary to ensure all potential hazards and siting requirements are properly assessed. The proposed location of the temporary structure should be identified on a site map and attached to the checklist mentioned above during the review and approval process. All relevant information should be obtained and provided in this same checklist before final review and approval.

Risk management Risk management is the process of identifying, assessing and controlling threats to an organisation’s capital and earnings.

These threats or risks come in many forms.

Industry guidelines and checklists aid in risk management decision making, however the ultimate decision on safely and efficiently planning a turnaround project is still subjective and somewhat complex.

Christopher V. Bacon, a labour and employment attorney with Vinson & Elkins, states: “experts will often disagree about the appropriate methodology for predicting structural damage to buildings or the probability of a particular hazard affecting a facility’s employees. OSHA will often ‘second-guess’ an employer’s response to its facility siting analysis and challenge an employer’s ‘prioritisation’ of some facility siting issues over others.”

It is important to note that the standard used in facility siting analysis ensures that workers’ risk inside a particular building is not greater than that of workers outside of it. The risk of injury or death during an explosion should be neutral, whether inside or outside a building. This neutral risk is required for occupied structures within the plant and is the standard led by the 2014 API RP756 to address process plants tents. Blast tents are designed to prevent injury of the occupants during an explosion but are not intended to protect occupants from pressure, fire, projectiles, toxic release, etc.

C ATA LY S T S

Beyond neutral risk to occupant safety Since 1999, blast-resistant buildings (BRMs) have provided workers with protection on temporary projects. However, the question remains: what degree of protection?

Although two BRMs might look identical and have the same blast rating, the occupants may have vastly different experiences post-incident, as they are not all equal. Some are built to the neutral risk standard, and some exceed it.

Engineering calculations have risk factors that can vary and explain why some BRMs use more structural steel and thicker steel members. All things being equal, the more structural steel and the thicker the members, the heavier the building will be, offering more protection in a blast.

However, deciding which BRM to utilise is often limited to comparing pricing and delivery, based on a structure’s blast rating.

For the sake of this article, it is assumed that all available blast-rated buildings are compliant with engineering standards – including ASCE guidelines entitled ‘Design of Blast Resistant Buildings in Petrochemical Facilities’.

Some companies require the review and approval of the engineering calculations and data books before accepting BRMs onsite. Whilst a building’s blast rating is a necessary consideration, there are numerous other factors to consider when weighing up occupant safety and project productivity.

Productivity considerations

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This macro assessment is sometimes skewed based on past limitations on modular blast building layouts and designs.

In recent years, tremendous advances have led to large, stackable complexes with sizeable free-span areas for short-term projects. The first floor is often designed for a lunch room and meeting areas, whereas the second floor provides offices for supervisors and coordinators. A project of this scope for a temporary project was unheard of just several years ago.

Door placement on a building is a safety factor that also impacts productivity. Some companies design their units to have door openings on various walls, which aids workflow design.

Open layouts

Another feature that impacts both productivity and safety is interior layouts. Working in a high-risk facility brings a unique set of challenges, including heightened anxiety, stress and even claustrophobia. As such, some companies design the interior of their buildings to be open and spacious, with minimal interior columns. A building with a single interior column has an entirely different feeling to one with four or five interior columns. Not only is it more spacious and aesthetically pleasing, but it also enables more customised workspace options designed to increase efficiency and productivity, and reduce employee stress levels.

Occupant safety considerations Biodynamic impacts

BRMs are designed to either slide during a blast or be anchored to a foundation. Rental BRMs are rarely, if ever, secured to a foundation. Some BRM companies have engineering analyses and perform actual tests to measure the degree to which its building slides at certain blast levels, and the biodynamic effects on the building’s occupants. BRMs do not defy physics: the more a structure weighs, the less it will slide during a blast, and the safer it will be for its occupants.

Projectile risks

Figure 3. Items placed on or against the interior wall can become projectiles during a blast. Some BRMs mitigate this risk, but some do not.

When the blast wave meets the exterior steel wall, it will absorb the blast and momentarily deflect or flex inwardly. If there is insufficient spacing between the external steel wall and the interior wall, items placed against the wall can become projectiles during an explosion. Such items, such as desks, cabinets, appliances, computer monitors, placards, fire extinguishers, etc., can cause serious harm to its occupants. Some BRM designs take this issue into account, providing a chase wall that mitigates projectiles’ risks to their occupants.

Interior construction methods

The method of constructing interior walls and ceilings will determine their ability to remain in place during and after an explosion. If not correctly fastened, the walls or ceilings could fall, risking injury and impeding occupants’ ability to access exterior doors or perform other safety measures. Some BRM companies have performed tests on various interior fastening systems and designed buildings accordingly in order to mitigate such risks.

Interior blast pressure

Figure 4. Left: after a blast with non-blast rated stair scaffolding. Right: after a blast with a blast-rated stair system.

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Aside from the risk of external physical trauma, internal blast pressures within the building can result in injury.

Limiting the pressure wave that can enter the structure by openings from the windows, doors and heating, ventilation and air conditioning (HVAC) will determine the internal pressure. Some BRM companies have quantified the interior pressure ratings during various blast loads and designed their structures to minimise internal pressure during a blast.

Conclusion

Toxic releases

A blast may release poisonous gases into the environment that would harm workers. Depending on the prevailing winds, the explosion may not even be within a particular plant, but rather miles away.

Workers often consider BRMs within the plants to be a place of refuge. However, general-purpose BRMs lack the required features that constitute a ‘safe haven’.

The buildings should be adequately marked and workers informed of the difference.

Certain BRM companies have introduced safety measures within their general-purpose buildings to mitigate outside air from entering its structures. A BRM can serve a dual purpose as an office, lunchroom, etc., that protects against specific toxic releases.

Post incident – ingress/egress As companies realise the benefits of safely housing personnel near the worksite, stackable BRMs are becoming commonplace, with stair scaffolding used to access the second floor. Stair scaffolding is not blast-resistant, which may limit ingress/egress to the second-floor post-incident.

One BRM company had a blast-rated stair system designed to securely enable access to and from the second floor post-incident.

Hallwood_09.pdf

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27/01/2022

Safety is a buzzword to some, while to others it is a belief system ingrained in their culture that emanates from their workers in the field and the products they design. Safety has a price, and it also has a cost.

Depending upon particular perspectives, one could say that the added cost to safety is not justified, whereas another might view the increased price as added value.

Hallwood Modular concentrates solely on designing, producing and renting purpose-built BRMs and other protective buildings.

Buildings from two different companies may appear identical, but safety is often not readily visible. There is a reason that one module may be heavier than the other, may use more (thicker) bolts, have fewer columns, have a chase wall, etc.

When choosing BRMs, it is important to carry out research and ask the following questions: what building would you want to be in during a blast? What building would help you to be more productive, without compromising safety?

Reference 1.

‘Siting or relocating temporary structures for use during construction or facility turnarounds’, EngStack, (7 October 2019), https://www.engstack.com/blog/siting-or-relocating-temporarystructures-use-during-construction-or-facility-turnarounds/

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Sam Miorelli, Siemens Energy, USA, presents a simplified, four-step approach to stronger cybersecurity in downstream operations.

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everal years ago, while hosting a cybersecurity panel discussion as part of an industry automation conference, a colleague began the session with a telling exercise that revealed how vulnerable unprotected industrial control systems (ICSs) can be. He opened a port on a web server installed on his laptop that was connected to the conference hotel’s internet, and then started the panel discussion. One hour later, after the Q&A, he checked the web server’s firewall log and counted 35 different attempts to penetrate it.

Today, such an exercise would likely have found many more times that number of attack attempts in an hour. In fact, in summer 2021, cybersecurity researchers set up a honeypot experiment with 320 nodes globally. It consisted of purposely misconfigured cloud services – remote desktop protocols (RDP) and secure shell (SSH) protocols among them – as well as several accounts with weak passwords. The researchers found that 80% of the nodes were compromised within 24 hours (many within minutes), and all were penetrated within a week.1

Energy: a top target for cyberattacks Of course, if the world’s energy industry needed an object lesson in why cybersecurity matters, it receieved a big one in May 2021, as this was when a ransomware attack shut down the 5500-mile Colonial Pipeline in the US for six days, disrupting fuel supplies throughout the East Coast. The collective economic disruption in the region certainly dwarfed the US$4.4 million ransom that the pipeline’s owner reportedly paid the hackers.2 This attack dramatically changed risk assessment of the energy industry – and cyber professionals’ perceptions of that risk. According to a 2021 SANS survey on the state of cybersecurity for operational technology (OT) and ICS, the energy sector is now seen as the most at-risk industry for cyberattacks.3 The survey’s report echoes Siemens Energy’s experience advising and providing OT cybersecurity services to companies across the energy industry’s value stream. It found that the top challenges facing industrial companies in securing their operations are:3 n Technical integration of legacy and ageing OT technology with modern IT systems: 59.4%. n Insufficient labour resources to implement existing security plans: 56.0%. n IT staff lacking understanding of OT operational requirements: 52.2%. n Traditional IT security technologies that are too complex to implement and maintain in an OT environment: 39.6%.

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Yet, despite these obstacles to plugging vulnerability gaps, a common excuse is that budgets to strengthen cyber defenses are constrained in an industry that has under invested in these protections for decades, or are only available if requested in once-annual budget cycles.

Some firms find themselves at a loss for where to start, let alone how to build a budget request to their board or senior management to fund better OT cybersecurity.

Cybersecurity is not rocket science Certainly, these challenges can be formidable. However, they are not insurmountable, nor are they rocket science to solve. The good news is that downstream oil and gas companies can adopt the straightforward, four-step approach that Siemens Energy’s cybersecurity experts and managed services team have successfully used to close vulnerability gaps for customers worldwide in recent years.

This approach is used to turn the unknowns and uncontrolled risks into a change management project – one involving a nexus of technology, people, and processes – that any organisation familiar with the operational rigours of the oil and gas industry can implement successfully. The four steps are: nn Identify and design. nn Acquire. nn Deploy. nn Operate and transition.

Because OT cybersecurity requirements differ significantly from IT needs, this approach is necessarily OT-oriented. OT environments are deterministic, requiring minimal latencies so that automation commands can be communicated and executed in their often millisecond timeframes, which precludes most forms of active scanning. If those commands are not performed in their specified timeframes – so a valve does not open, or a pump does not start – plant operations can be disrupted, potentially at significant cost to production or even risking environmental, health, or safety dangers.

Other challenges facing OT environments with many different ICSs operating in a highly-engineered and orchestrated synchronisation, which are typical of downstream production plants, include the following: nn Avoiding or minimising plant disruptions during the deployment of security controls. nn Supporting legacy automation equipment and software, given the sunk capital investments and long lifespans of such assets. nn Avoiding violating vendor service agreements while deploying third-party security software. nn Testing security controls thoroughly to avoid compatibility issues. nn Prioritising worker and plant safety, environmental compliance, and asset availability.

This article will now take a closer look at each of the four steps in the recommended approach.

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Step one – identify and design This phase is critical. It is where the need to mitigate or remediate what could be a currently unknown or unquantified cybersecurity risk must be identified and prioritised to define the right amount of investment and the timing of that investment. As with any risk management exercise, some are more critical than others, and prioritisation guides a logical cybersecurity journey.

Business leaders can often be caught unprepared during the later stages of operating an OT security program due to a lack of proper upfront planning and designing. Given the volume and relevance of this investment – vs a compliance-driven, minimum security investment approach – Siemens Energy recommends a joint discovery process that brings its experts and their OT and IT teams together.

Siemens Energy starts by identifying the company’s strategic security goals. This avoids ‘one-size-fits-all’ plans and helps to define each plant’s proper cybersecurity journey. The following are examples of tasks performed in this phase: nn Conducting a detailed review of what is motivating the cybersecurity investment (e.g. audit results, past incidents, risk assessment results). nn Understanding existing industrial automation assets and security safeguards, especially off-the-shelf security tools, and their ages and current operating conditions. nn Identifying constraints such as lack of vendor support and compatibility for third-party security tools. nn Analysing in detail the requirements for each currently operating security control and its minimum technology features available for use in an upgraded security framework. nn Creating a detailed logical and physical network design that considers the impact of the target security architecture and new services to be included. nn Aligning with the company’s enterprise IT security strategy and interfaces to avoid overlaps and allow for an optimal detection and response strategy going forward. nn Creating a new security management system governance framework – policies, procedures, and standards – aligned with the company’s future state vision with accommodations for the particular requirements for every plant. nn Developing a detailed project plan, incorporating the governance framework, and with clearly written goals, strategies, objectives, tactics, metrics, timelines, responsibilities, and budgets. All stakeholders need to participate in its development, and executive management must sign off on it.

Step two – acquire This step involves selecting the right providers to meet the defined quality, budget, and time constraints identified in step one. It can be a big challenge for companies operating multiple downstream production facilities, especially if those plants are located in different regions of the world.

This is where a partner with global reach and a vendor-agnostic approach helps. While Siemens Energy has a rich legacy in original equipment manufacturer (OEM)

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execute within the outage schedule afforded by the customer’s ongoing operations. This keeps onsite changes and the potential for adverse impacts to a minimum.

Notably, the proper backup will be executed in collaboration with the customer’s OT/IT teams before significant changes, with detailed rollback plans drafted and ready for use in each case. The following summarises these and other tasks to Figure 1. Siemens Energy has successfully developed a four-step approach be performed: n Planning and designing system to close vulnerability gaps for customers worldwide in recent years (image courtesy of Siemens Energy). and network configuration for every cybersecurity safeguard to be deployed (e.g. design of target hardening industrial controls, its cybersecurity work is aggressively policies). vendor-agnostic both in securing control systems and the n Thorough testing with representative equipment with tools used to provide that security. In addition, target system configurations. vendor-agnostic solution integrators have the advantage of nn Creating detailed rollout and rollback plans to maintaining many relationships across the industry, which augment and include the overall plan. lets them offer the most appropriate tools even as things nn Coordinating, aligning, planning and monitoring of change at extraordinary speed. Typically, this step will tasks to be performed by third-party participants in require: the new security system’s deployment. nn Drafting detailed request for proposals (RFPs) and nn Conducting pre-rollout site visits and rehearsing the coordinating subcontractor and vendor execution of rollout tasks. communications. nn Monitoring the availability of all assets involved in the nn Qualifying, selecting and overseeing a plan’s execution security system migration (before, during and after with the chosen third-party providers. changes). nn Monitoring the shipping and receipt of hardware and nn Executing other change-management-related practices software while filling in any gaps or inconsistencies in (e.g. change requests, communications, monitoring, their order fulfillment. awareness, etc). nn Detailed coordination with plant operators during nn Updating existing documentation or creating new planned plant maintenance and outages when new documentation as needed (e.g. updated logical and security system safeguards will be installed and physical network diagrams, IP numbering commissioned, and when new network segmentations standard/procedures) to create a single as-built are done. documentation resource for future consultation and nn Planning and documenting the deployment of new updating as updates and upgrades are made. cybersecurity measures, including personnel training, nn Provisioning a rollout service desk with engineers altered management communications, adoption available to address any adverse impacts on operating monitoring, and safety hazard assessments where assets affected by the migration to the new security applicable. system.

Step three – deploy

This phase involves installing and commissioning the designed security controls for each cybersecurity risk mitigation. It should include detailed configuration design and testing either in a laboratory, factory acceptance testing (FAT), or site acceptance testing (SAT). The idea is to identify and resolve compatibility issues as much as possible before onsite installation and commissioning occur. This helps to reduce risk during a planned outage and ensure that the plant can resume operations within the allotted timeframe.

Typically, Siemens Energy’s engineers are onsite to perform integration testing and refine the rollout plans based on the outcome of the laboratory/FAT tests. To further minimise execution time during the deployment, migrations to the new security system will be planned and grouped together based on similarity and the ability to March 2022 64 HYDROCARBON ENGINEERING

Step four – operate and transition In this phase, the customer’s OT/IT teams (and, if applicable, contracted third-party outsourcing providers) will properly operate the newly-deployed security system to its maximum potential. This phase also provides the training that the automation and operations teams will require to learn how to operate the plant in the new security environment, which will likely include new host-based security agents; prohibited and therefore blocked communications that may have been previously considered routine, especially with external parties; and the operation of new security appliances and tools. This will ensure a smooth transition that minimises post-rollout service desk requests related to the change. The following provides a summary of these and other tasks to be performed: nn Evaluating operational impacts with the additional security tools, processes and procedures.

nn Designing the target operations model, as well as its workload and workforce requirements, to properly sustain the change. nn Recommending adjustments in the organisational structure, roles and responsibilities to fit the defined ‘responsible, accountable, consulted and informed’ (RACI) model. nn Defining target service-level agreements (SLAs) for deployed security services. nn Defining the best sourcing strategy for select services across a customer’s different host countries, if applicable. nn Supporting the selection of qualified managed service providers, if needed. nn Supporting the transition of service and knowledge transfer to the operations provider.

Conclusion The four steps described herein can help plant operators make cost-effective step changes to close cybersecurity gaps in their operations. This is true even if they currently have little or no knowledge of the topic or find it overwhelming in the context of their highly complex plant operations.

In many cases, especially in sovereign-owned national plant operations, the local hiring of highly-qualified security talent can be difficult because of its scarcity. To prevent this from becoming a critical path item in developing and enacting more robust cyber safeguards, Siemens Energy usually recommends outsourcing to an OT-managed security services provider for immediate needs, either as a bridge to self-operations or a long-term solution to global cybersecurity staffing shortfalls.

As part of step four, Siemens Energy helps its customers adopt the ‘ADKAR’ approach in order to achieve the needed cultural change. ADKAR – awareness, desire, knowledge, ability and reinforcement – are the five changes that need to happen for a change to be successful. After all, an organisational change can only happen when individuals change, and more robust cybersecurity for downstream oil and gas operations is undoubtedly worth the effort and investment.

Finally, the deployment of a comprehensive, updated cybersecurity system with a mature governance framework must include a high level of OT/IT collaboration, as well as executive management support behind it all – whether the system is deployed across a single plant or multiple plants.

Even then, for it to succeed, operational personnel from the front office to the back office and everywhere in between need to be aware of the changes, know their responsibilities for supporting those changes (e.g. not opening unsolicited emails or attachments), and learn what, if anything, they might have to do differently in their day-to-day jobs. In practice, plant cybersecurity is everyone’s responsibility, just like plant safety.

References 1.

2.

3.

CHEN, J., ‘Observing Attacks Against Hundreds of Exposed Services in Public Clouds’, Palo Alto Networks, (22 November 2021), https://unit42. paloaltonetworks.com/exposed-services-public-clouds/ EATON, C., and VOLZ, D., ‘Colonial Pipeline CEO Tells Why He Paid Hackers a $4.4 Million Ransom’, The Wall Street Journal, (19 May 2021).

BRISTOW, M., ‘A SANS 2021 Survey: OT/ICS Cybersecurity’, SANS Institute, (August 2021), pp. 5 – 7.

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March 2022 66 HYDROCARBON ENGINEERING

Samuli Bergman, NAPCON, Finland, explains how machine learning can aid operators of oil refineries and petrochemical facilities.

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achine learning has the capacity to be a very efficient tool for oil refinery and petrochemical facility operators, where the requirements of end products can change at short notice, and the quality of feedstock can vary widely. Because information is constantly gathered from different stages of the process, there are millions of process values – historical and ongoing – that can be compiled into a machine learning model that predicts process behaviour and provides accurate operation suggestions to operators.

An oil refinery operates constantly, and though the process is highly-automised, there are many process variables for operators to supervise at the

different process steps. This task is particularly challenging, as product quality requirements can vary with short intervals, which in turn requires a lot of changed process parameters.

A human operator is simply not able to carefully watch every monitor and follow all important process variables simultaneously, which means that digital assistance makes it possible to operate a process with increased efficiency. To address this problem, Neste Engineering Solutions began to develop an AI-based solution built on a machine learning model that demonstrates what happens chemically and physically inside reactors, pipes and columns. The model also covers the automation’s effects on the factory.

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Making changes At all chemical processing plants, huge amounts of data are constantly collected regarding flow, temperature, pressure, and other process variables. In addition, there are large amounts of historical data that has been collected over a long period that can be used to teach the machine learning model what a well-functioning process should look like.

The core of machine learning is that the more material that is fed into the system, the more the AI learns about how the factory behaves under different circumstances. When fully trained, the digital assistant can predict how the process will behave during certain hours, for example. Operators can also consult the digital assistant if help with the settings is required.

The next development step could be a verbal interface such as Siri, Google Assistant or Alexa, but the fully-developed system is yet to be completed.

Within chemical processes, there are both slowly changing phenomena (such as when the process equipment wears and gets dirty on the inside or when the catalysts in the reactor slowly fade) and fast events (such as when new batches of

feedstock are fed into the process, which must be changed accordingly). Process units must adapt to these changes, and it is here that a digital assistant could shine, as it can be used to calculate how the process could be optimised, and instruct operators as to how to reach the goal.

Prolonged service intervals Because a digital assistant carries out the calculations continuously, the machine learning model is constantly changing and evolving. The advice applies mainly to factors such as temperature and pressure, and the idea is that the operator implements the advice by changing the set points in the process control system.

Of course, it is the operator’s normal job to handle these factors, but by using the digital assistant’s advice, the measures can be scheduled more precisely in difficult situations. It is also more likely that the setting values are correct, as the AI model can sort out enormous amounts of data in a fraction of a second, and apply this wisdom to aid the operator.

AI can also be used to extend the lifetime of the process equipment, which can result in prolonged service intervals and smoother running processes. If, for example, the wrong temperature or pressure is used, the components of the plant wear faster, but for a digital assistant, it is not difficult to always find the optimal value at different stages of the process. This could mean that a production shutdown for service can be postponed, which in turn corresponds to better earnings.

The digital advisor’s situation-specific optimisation also helps to reach the true limits of a plant, whether there is a need to reduce carbon emissions, optimise utilities, or maximise certain yields.

Inside information Neste is the one of world’s largest producers of renewable diesel, but the company also has a subdivision, Neste Engineering Solutions, which implements Neste’s Figure 1. The Advisor and/or Phenomena Indicator innovations on an industrial-scale; carries out major industrial create dynamic models of an oil refinery process or a investment projects; and helps its customers in the process petrochemicals unit to optimise process conditions, industry to continuously develop their production and to meet production objectives, or detect malfunctions. optimise their processes. One of Neste Engineering’s units, NAPCON, specialises in the development of solutions to help companies in the process industry to streamline their processes.

Many of NAPCON’s solutions are tried and tested at Neste’s refinery in Porvoo, Finland, but the company also sells its expertise to third parties that want to have better control over their processes.

Figure 2. A digital operator assistant predicts the dynamic behaviour of process variables; The digital assistant, creates what-if scenarios to allow operators to test various operative scenarios; and NAPCON Advisor, and suggests what changes should be made in order to meet operation objectives. the soft sensor, March 2022 68 HYDROCARBON ENGINEERING

Figure 3. Seamless cooperation between process and operation experts and machine learning specialists is the key to success in an implementation project for a digital operator assistant. A typical project starts with a workshop where the potential and benefits of a digital operator assistant are identified.

NAPCON Phenomena Indicator, are the latest additions to the company’s product portfolio. Both are based on machine learning and AI. These products are an example of how data analysts and machine learning experts have entered the oil refining and petrochemical industry, which until recently has made slow progress when it comes to AI and machine learning.

The products work in real time and use the same data, but from the operator’s perspective they are two completely different products. Where Advisor predicts how the process will behave up to six hours ahead, Phenomena Indicator usually predicts just one variable, mostly for which there is no hard or correct information that can be measured in traditional terms.

Complex problems require complex solutions A typical example of the need for a soft sensor is when a product must meet a particular quality requirement, but can only do so with expensive additives. If more additives are used

than are needed, it is just a waste of money. However, with traditional measuring methods it is difficult to continuously estimate certain phenomena during the process because of the many factors affecting the production line. One factor is that the crude oil may come from different batches. As such, the recipe for a certain product can vary hugely at short notice, which is why a phenomena indicator using the same data as the digital assistant is needed.

The term ‘soft sensor’ is nothing new in the process industry, but until recently, it has not been based on machine learning. The big difference is that the machine learning model makes it possible to estimate much more complicated things than before. Therefore, an AI-driven soft sensor enables the continuous adjustment of the process so that the product meets the specification, but does not overdo it.

Ecologically, this is also the soundest solution because the process uses just the amount of energy needed and no more.

Additionally, it is also possible to use cheaper raw materials, as

operators have better control over the process.

With a digital advisor and an AI-driven soft sensor rendering the forecasting of what will happen within a few hours possible – as well as the analysis of what happens in the process under different conditions – oil refineries can make big strides. As huge amounts of data are collected every day at a chemical processing plant, man power is unable to keep up with this volume of information, but a digital assistant can continuously suggest effective means of optimisation.

The value of digital assistance

Figure 4. Digital operator assistants are a means to increase situational awareness. There are other important data analytics applications, such as dashboards and other visualisations, that can be implemented on various levels – production line, site and enterprise.

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Many of the experienced operators in the process industry will soon retire and be substituted with younger operators that lack the same experience but who are born into the digital world. This means that a digital assistant can secure competence and support new operators.

With the help of a digital assistant, which constantly analyses the process and makes forecasts based on the readings, it is significantly easier for inexperienced operators to run a plant under varying circumstances.

Phil Millette, Honeywell Process Solutions, UK, discusses how timely technology upgrades extended the life of critical assets at Petroleum Development Oman’s government gas plant.

A

s a major oil and gas industry operator, Petroleum Development Oman (PDO) required a proven solution to upgrade existing process automation systems (PAS) and other automation assets, without the risk of costly downtime or the loss of valuable intellectual property.

Background PDO is the leading exploration and production company in the Sultanate of Oman. The company delivers the majority of the country’s crude oil production and natural gas supply. It is jointly owned by the government of Oman, Royal Dutch Shell, Total and Partex. PDO’s first economic oil find was made in 1962, and the first oil consignment was exported in 1967. Its government gas plant (GGP) was established in 1978 in northern Oman.

The facility has been the main gas operation for the Sultanate of Oman, finding gas fields and developing them into producing assets on behalf of the government.

GGP was originally constructed by PDO at its Yibal field to process as much as 2 million m3/d of gas, most of it to be delivered to the Al Ghubrah Power and Desalination Plant in Muscat via a 20 in. pipeline. Since then, the demand for gas in Oman has increased at a steady pace, calling for PDO to progressively expand the GGP, as well as the pipelines and associated pressure-limiting and valve stations of its gas transportation system.

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Moreover, there was a need to upgrade the PAS to the latest technology to meet the life cycle demands.

Challenges Gas processing facilities strive to optimise production throughput and minimise downtime and operational costs, while maintaining safe operation. To meet these objectives, their automation systems and related technology assets must meet stringent process control requirements, and be both reliable and scalable.

As with other major petroleum industry organisations, PDO has a critical need to address the following: nn Reduce the risk of unplanned downtime.

nn Increase the efficiency and reliability of processes. nn Ensure consistent gas quality. nn Achieve greater throughput with existing equipment.

At the GGP facility, engineers sought to optimise the footprint of various control system components, including controllers and cabinets. They also wanted to upgrade all legacy Honeywell High-Performance Process Managers (HPMs) to Experion® PKS C300 controllers and enhance the capacity of the plant’s fault-tolerant Ethernet network infrastructure.

Over the years, the GGP facility had progressed from a TDC 3000 control system with Advanced Process Managers to the TotalPlantTM Solution platform with C200s and FailSafe Controllers (FSCs®), then to Experion PKS with C300 controllers, and finally to the Enhanced High-Performance Process Manager and Enhanced Universal Control Network solutions. In 2019, the GGP upgraded all of its FSCs to the new Safety Manager (SM) system.

Due to the increasing gas demand in Oman, PDO sought more sustainable operations and a better process control environment at the GGP facility. The specific goals for technology upgrades were to improve operational efficiency while retaining valuable intellectual property and enhancing life cycle planning.

However, the company’s project team faced several engineering, planning and execution challenges in undertaking technology upgrades. The duration of an operational shutdown for the modernisation tasks was critical. Engineering work for outdated auxiliary control room assets would prove to be complicated. Moving operator workstations and transitioning networks to a new standard would also be difficult. Wiring and loop checks for thousands of control loops would present significant risks.

In addition to the above, an overarching challenge for the entire GGP upgrade project was the limitation of resources imposed by the COVID-19 pandemic.

Solution Figure 1. Design of an ICR.

Figure 2. PDO’s upgraded system architecture.

March 2022 72 HYDROCARBON ENGINEERING

PDO developed a technology rejuvenation strategy to improve the GGP’s ability to operate at higher availability and efficiency levels. This far-reaching project addressed numerous production assets across the company’s large gas processing operation.

Based on the findings from a baseline assessment; fire, gas dispersion and explosion assessment; and quantitative risk assessment, PDO decided to relocate the GGP’s central control building (CCB) and auxiliary buildings to a safer location, away from the facility’s existing export line. The plan was to build a new integrated control room (ICR)

with the latest recommended ergonomic features, in accordance with the human factors engineering standards.

PDO’s modernisation efforts would also be aimed at addressing 30-year-old legacy panels and the lack of updated data, as well as the legacy network between safety systems. The company wanted to enhance operator effectiveness and improve its ability to make faster and smarter decisions by integrating crucial operations. Finally, plant management required a capacity increase to support various field control panels/projects.

Prior to the control technology modernisation, the automation architecture at the GGP facility incorporated 16 controllers, 13 redundant FSCs, four redundant HPMs, and 22 C300s with HART and FOUNDATION Fieldbus modules.

On level two, there were a number of different servers and engineering and operator workstations. These included one Experion Server-TPS, one redundant Experion Server, and one redundant OPC/Honeywell Field Device Manager (FDM) server. All of these nodes were connected by 22 backbone old switches and associated routers and firewalls.

The proposed scope of the overall technology upgrade was to move all of the HPMs to C300s and replace FSCs with SMs while keeping the same I/O modules. The work also focused on transitioning the plant’s supervisory control level to the latest software release, along with a hardware refresh. The result would be a standardised system architecture supporting continuous improvement opportunities while providing a smaller footprint.

SEEING IS

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In addition, the technology upgrade project involved the deployment of new RS485-type interfaces with low-voltage switchgear and the installation of heating, ventilation and air conditioning; uninterruptible power system; and CCTV equipment.

A phased approach was employed for the automation technology and control room upgrades to minimise disruptions to normal plant operations and ensure efficient execution of the various project steps. Activities ranged from shifting the control supervisory level to the ICR – including servers and operator/engineering workstations – to introducing a new fire and gas zone and idle air control. Important aspects of the project were implementing the new ergonomic control environment and shifting more than 30 CCTV cameras from the CCB to the ICR. Project team members also upgraded Experion software from R450 to R500.

Results Thanks to its modernisation efforts, PDO achieved a standardised control and safety system architecture with a reduced hardware footprint, fewer operator screens, and integrated C300 and SM controllers. The company also implemented the Honeywell Trace solution for better monitoring of critical control assets. The technology upgrades improved network and control capacity by moving the legacy system to a new, advanced automation platform.

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Gil Cohen and Abishek Mukund, Imubit, outline the requirements to automate key operating strategies in closed-loop to achieve optimal plant profitability.

O

ne of the key objectives of those who manage or work at a refinery or chemical plant is to improve plant profitability.

Profitability improvement is manifested by how well a plant is run through a set of 10 – 15 operating strategies. The way those operating strategies are executed makes or breaks a plant’s profitability.

Key business objectives may include maximising production of some products over others, building specific product inventories, or reducing carbon footprint while maximising throughput. A corporate planning and scheduling group translates key business priorities into high-valued operating strategies, encompassing major units, cross-unit interactions, and long-time dynamics. Such strategies typically manipulate upstream units to maximise downstream units. This list of operating strategies is tailored to a site’s specific configuration, current process unit condition, local supply chain considerations, and regional market conditions.

Operating strategy execution at plants today Key strategies follow a cycle of events. First, the site’s planning and economics group embed the strategies into their linear programme (LP) model and run through numerous steady-state cases offline to try to define a list of operating orders for the operations group. These include desired feed rates, conversion or reactor temperature targets, and product quality goals. The LP is typically run on a weekly basis and the operating orders are expected to be executed throughout the week, and then delivered to operations through meetings, spreadsheets and other means of communication.

While the LP model is based on a static, steady-state analysis of the plant, the reality of the plant is quite dynamic, as major process disturbances occur several times per day. Once the directive is received, operations must plan their own journey of implementing the operating orders. Operations begin with intermediate changes and wait for the process to ‘settle out’, often waiting for new daily lab samples, to then HYDROCARBON 75

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reevaluate the system’s state prior to the next change. Not having models to predict how changes will impact the plant, operations rely heavily on process feedback and experience, all of which takes days. Naturally, as different units are a part of the operating strategies, operations will manually coordinate between their team members to steadily push the site towards the operating orders. Process engineers help to accelerate this cycle, using heuristic-based spreadsheets and first principle simulations, by helping to relieve local constraints and projecting system impacts to build operator confidence.

Another critical aspect of executing the operating strategies is process control. Once operations decide on the process moves, they implement those moves by defining process control targets through the use of regulatory control, Advanced Process Controls (APC), or a combination. Operators change process control constraint values or variable goals, which then allow process control to drive to the specified targets while respecting

the unit limits. Process control engineers work with offline models and tuning applications to help ensure that the process control solution is best set up to drive to operations’ targets. This may be as simple as altering proportional integrative derivative (PID) loops, or as complex as modifying APC models to ensure maximisation or minimisation of key handles up to operating constraints. The regulatory controls and/or APC then drives the process via setpoints cascaded down to process unit valve positions. Each controller, whether a PID loop or APC multivariate controller, is isolated from the others, forcing operators and process engineers to manage the coordination between units while executing the operating orders.

After waiting for the plant to arrive at ‘steady-state’, re-evaluations of the execution of the operating orders take place. Due to the ever-disturbed process dynamics of the plant, process control targets are set away from the original operating orders. This is due to new constraints or unplanned disturbances all changing the plant continuously, which forces operations to be conservative in their abilities to meet operating orders. The weekend is never a good time to make process changes with minimal engineering support, and even Friday is sometimes labelled a ‘read-only day’ to denote a stability-first mindset and to prepare for a quiet weekend. A week on from when the operating orders were given, the plant state remains suboptimal due to the inability to execute the key optimisation strategies with accuracy and speed. The cycle restarts on a weekly basis, and time away from the optimal state far surpasses the time spent at the optimal state, reducing plant profitability as a result.

Figure 1. Current execution cycle of operating strategies. This cycle, involving different teams and different tools, takes about a week to complete.

Figure 2. Time series plots showing the downstream constraint that needs to be maximised to execute the operating strategy. Key handles 1 and 2 are on another unit, upstream from the constraint. Handles are moved at a low frequency over a two-week period, leading to lost opportunity while executing the operating strategy.

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Traditional process control and optimisation challenges While process control and optimisation technologies have greatly improved over the last several decades, they provide value to each of the individual groups, but unfortunately do not shorten the operating strategy execution cycle.

Firstly, current planning and economics optimisation technologies do not adequately model the dynamic state of the plant. Plant-wide optimisers typically use linear assumptions or first principal models that, without proper manual reconciliation, do not reflect the conditions of the plant.

Additionally, such models require the input of unmeasured disturbances such as feed qualities, which are measured by infrequent lab samples at best. The effort and cost required to consistently reconcile optimisation models is high. In addition, these plant-wide optimisers solve on a steady-state basis, taking a static look at the plant once a week. Between outdated

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models, simplified assumptions, and static optimisation, the solution defines an ‘optimal’ for a single state, but unfortunately the plant functions in many different states. As such, current LP optimisation remains an open-loop function defining relative direction, but is unreliable for dynamic closed-loop control.

Secondly, existing process control technologies also face challenges. APC and advanced regulatory control have made significant improvements to unit-specific control and stability.

However, modelling site-wide dynamics and non-linear interactions with linear tools significantly reduces the ability to accurately coordinate between process units. In addition, existing process control and optimisation models require significant and continual maintenance efforts as the plant regime changes and market conditions become increasingly volatile. The traditional vision of optimisation and controls through a system of stacked control layers seems even more infeasible. It is extremely rare for all of the models in the stack to be functioning properly to enable closed-loop control and optimisation. With control layers compounding linear errors and first principal assumptions, closed-loop process optimisation – which automatically executes operating strategies – is simply not a reality. This is a pain felt by various plants who have attempted it.

The third and biggest reason why current process control and optimisation technologies cannot shorten the operating strategy execution cycle is people. Each plant domain expertise is siloed from the other domain expertise, resulting in the largest inefficiency of the execution cycle. Planning and economics groups run the LP independently, to then convey operating orders. Operations and process groups, who then run different offline tools and use heuristics and experience, determine how to best execute the operating orders.

Next, independently-defined process control targets are implemented into process control technologies which have predefined directives to meet the targets.

Additionally, all of the tools, heuristics and experience are applied with different personal lenses of the plant. Operations and process engineering groups view plant dynamics on the scale of minutes, and focus on execution based on isolated unit boundaries. Process control engineers view the plant in terms of linear and first principal assumptions focused on controlling unit boundaries. Finally, planning and economics make linear and first principal assumptions while viewing the plant on a steady-state timescale.

Automation is not connecting existing systems

As artificial intelligence (AI) gains popularity in the refining and chemical processing space, multiple vendors are attempting to connect existing technologies used by the different groups with the introduction of AI. While AI helps each individual group, it will not bridge the gap between people, methodologies and cultures. Adding it into the existing set of technologies and models does not enable the automation of the strategy execution cycle.

AI is introduced into offline tools, rendering the maintenance of LP more feasible, as well as alleviating simplified assumptions with more data-driven modelling. AI in process simulators helps to recreate unit simulations to better match reality. It also helps with more data-driven models of APC and other process control technologies, relieving some of the burden surrounding maintenance and lack of model-reality fit.

The main challenge with connecting existing technologies of the different groups is that each group has built its own methodology and culture around its systems and models. Their part in the current execution cycle includes tools and technologies, as well as insights and human decisions. Those decisions are based on years of personal experience at the plant.

In fact, many human decisions are made to compensate for the lack of data that some models require, or certain context that the computerised systems do not have or are not able to deduce from the data to make the correct decision as part of the execution cycle.

For example, as online feed composition data is not typically available to feed into a predictive model, a process engineer operating that model must make an educated decision as to how to adjust the output of the predictive model before making the formal decision that will drive operator actions and process control changes. Connecting those existing systems and technologies will inevitably require human intervention at every part of the execution cycle, thereby preventing its full automation.

In some cases, which represent a very small subset of the plant’s execution strategies where multi-unit dynamics do not play a significant role (e.g. blending), it is technically possible to connect simplified Figure 3. A closed-loop neural network platform links plant teams under a LP models and APC. The challenge remains central model. Now, all domain expertise can translate their perspectives cultural in such cases, as these efforts are with the common objective of executing operating strategies efficiently. usually driven by the process control group March 2022 78 HYDROCARBON ENGINEERING

and not strategically adopted by planning and economics, operations, and process engineering.

A unified model for closed-loop execution

planning and economics use when taking the current state of the process, market prices, and other parameters, and using them to convert the operating strategy into operating orders.

The same single closed-loop neural network must also represent the considerations and decisions made by operations as they look at the dynamic state of the process, observed and unobserved disturbances, and convert the operating orders into process control targets.

Additionally, it must understand how the process control – whether PIDs or APCs – operates, and how the instructions it will provide will translate to measured process variables. All of these aspects are manifested in a deep neural network that is able to capture all of these complexities in a single model, tailored for a specific operating strategy.

Secondly, the closed-loop neural network can compensate for certain missing data by learning patterns from historical process data. A key example of missing data that is required to make decisions as part of the operating strategy execution cycle is feedstock composition, which many models require in order

A next generation of process control and optimisation solutions is required to not only bridge technology barriers, but also bridge the people barriers. One universal model is required to represent the considerations and decisions made by planning and economics, operations, process engineering, and process control as part of their contribution to the operating strategy execution cycle. Such a universal model must be strategy-specific in order to be realistic and feasible.

It is impossible, even with today’s computing capabilities, to build one universal model for all of the groups and all of the strategies. This universal model must understand the decisions made by each of the groups. In addition, it must be able to compensate for the lack of data that each group humanly handles today, and be able to leverage historical process data to synthetically generate the experience required to make decisions based on partial data.

Critically, for this universal model to significantly shorten the strategy execution cycle, full automation is required, which means that the universal model must execute process control moves in a closed loop, within minutes. This model cannot just provide open-loop recommendations to operations or engineering and cannot be integrated into one of the group’s existing tools, such as an LP or APC model.

For this universal model to be feasible, it cannot be an ensemble of layers or components, each maintained by a different group. Rather, it must be a single unified Figure 4. The conventional approach is moving towards using a neural model that is internally complex enough to network process model and allowing a solver algorithm to go closed-loop. capture multi-unit, nonlinear dynamics, and it However, only use of a neural net controller, as used in the closed-loop must jointly model the global relationships of neural net, enables true automation of operating strategies as it gains statistical experience through reinforcement training. the plant and the local dynamic process subtleties.

A closed-loop neural network There is only one technology that meets the requirements of this universal model: a closed-loop neural network. Closed-loop neural networks have been proven across the refining and chemical processing industry in recent years. They are not simply a neural network that is integrated into a process control and optimisation solution. To meet the requirements mentioned above, this neural network must also meet several requirements.

Firstly, it must fully model the process that is operated under the specific operating strategy. This may include one process unit or multiple process units. This single neural network includes the considerations that

Figure 5. Left: significant lost opportunity exists through the typical plant operating strategy execution cycle. Right: closed-loop neural network executing plant operating strategies continuously in closed-loop, keeping plant objective function at optimum.

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at a different time and under different randomised market conditions, and the closed-loop neural network tries to respect constraints and drive objectives. At the end of each iteration, minor tweaks are carried out to the millions of neural net weights, and on to the next iteration. The end result of this virtual training provides the closed-loop neural network with the equivalent of thousands of years of decision-making experience.

The closed-loop neural network controller decisions allow for a smooth, continuous solution without artificial limits, and much less reliance on perfectly accurate predictions. Offline decisions and experience supplemented by plant domain experts are now embedded into the automation solution, allowing for an accepted closed-loop solution. Only an experience-based controller can ensure the stability, reliability and predictability of a control scheme over such a complex nonlinear process model.

to accurately predict certain process variables. In reality, most plants do not have continuously-available feed composition measurements. The closed-loop neural network can relate certain pressures, temperatures, flows and qualities in and upstream of the relevant process units to predicted variables, implicitly inferring the feed composition, even without lab samples to train on.

While having an accurate nonlinear process model is critical, it is not enough to just use this process model with a control algorithm. The neural network process model is complex but imperfect, as all models have errors, especially nonlinear models.

Using a traditional solver on top of a highly nonlinear model will lead to unstable and infeasible solutions. This is one of the reasons for which Real-Time Optimisation (RTO) has not succeeded at scale. Real-time control with a nonlinear model has always missed that ‘operator feel’. Constraining a complicated control algorithm with complex rules and edge cases (as a nonlinear model requires) will not be successful, as all groups at the plant will fail to understand and accept these complicated control laws. The control scheme must be smooth, intuitive, and leverage ‘experience’.

The closed-loop neural network does not control with a solving algorithm. It is trained over millions of iterations, where it gains experience in executing the operating strategy using the nonlinear process model over the equivalent of millions of simulated hours. Just as a child learns to walk via trial and error, the closed-loop neural network learns how to execute the operating strategy via virtual trial and error. Each iteration starts

Conclusion In many plants, it takes a week to execute a cycle of key operating strategies. That is because different teams view the plant through different lenses, using different offline tools.

Improvements can be made to process control and optimisation that aid individual teams but do not provide a global change.

However, various plants have already adopted a closed-loop neural network – a universal model owned by all team members that is able to automate the operating strategy execution cycle and shorten it from one week to one minute. The result is that a plant’s key performance indicators (KPIs) are consistently closer to their optimum, thereby achieving company business goals.

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March 2022 80 HYDROCARBON ENGINEERING

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

FFCs slurry oils sell for just a few hundred dollars/ton, but when converted into Carbon Black – a key component in high-end plastics, tire manufacturing, and other rubber-based components – they can reach a market price of $2,500 USD/ton.

ET Black™: the industry technology of choice Eurotecnica’s modified furnace black process, ET Black™, efficiently converts slurry oils into a wide range of carbon black grades, giving you access to an exciting and fast-growing industry.

With guaranteed operating flexibility and reliability, easy maintenance, and a low CAPEX, ET Black™ has become the technology of choice for industry leaders like ADNOC Refining.

Contact us at www.igoforETBLACK.com to find out more.