Hydrocarbon Engineering - May - 2024

03 Comment

05 World news

08 Asia’s appetite for oil not slowing

If oil demand is peaking, why are China and India still investing? Ng Weng Hoong, Contributing Editor, investigates.

16 Get connected

Industrial operators that take advantage of the latest digital and automation asset performance management (APM) tools can look forward to improved operational efficiency, reduced downtime, and a proactive maintenance culture. Stacey Jones, ABB Energy Industries, explains.

20 The digital factory

Nienke Gerridzen, Yokogawa, explores how companies can maximise the impact of digitalisation in a VUCA world.

23 The value of accessible asset data

Andy Phillips, Tracerco, UK, explains the important role of actionable data in providing efficient and insightful refinery column scans.

27 Refinery CO2 reduction: proven performance

Mateus Camparotto, Alkegen, South America, presents the results of a study undertaken to evaluate insulation alternatives for the convection section of petrochemical furnaces.

33 Improving the mechanical integrity of a facility’s assets

Corrosion under insulation is a common issue that can lead to significant problems at industrial facilities. Fred Addington, Pinnacle, USA, explains how it can be tackled.

37 Specialist solvent selection

Ashraf Abufaris, BASF Middle East Chemicals LLC and Blake Morell, BASF Corp., USA, consider how use of a highly H2S selective solvent can help to optimise capital investment and reduce operating costs.

43 Dual measurement solutions

Airat Amerov, AMETEK Process Instruments, USA, details the importance of measuring and controlling both hydrogen and water concentrations in the catalytic reforming process.

49 Critical measurements

Rhys Jenkins, Servomex, UK, explains why measuring water impurities in ethylene dichloride and other key hydrocarbon processing applications is crucial.

51 Mastering the art of sampling gases and volatile liquids

Understanding the challenges facing gas grab sampling technicians and overcoming them is essential in building an effective sampling system. Matt Dixon, Swagelok, USA, explains best practices.

57 High speed balancing

Brian Hantz, Qingyu Wang and Brian Pettinato, Ebara Elliott Energy, consider API acceptance criteria for the high-speed balancing of turbomachinery rotors.

61 Detection and protection

Nabil Abu-Khader, Compressor Controls Corp. (CCC), UAE, considers best practice for preventing compressor damage caused by surge. Alkegen creates high performance specialty materials used in advanced applications including electric vehicles, energy storage, filtration, fire protection and high-temperature insulation, among many others. Employing a vertically integrated approach across its broad array of technology platforms, Alkegen is committed to achieving energy efficiency, pollution reduction, and enhanced safety for individuals, structures, and equipment.

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COM MENT

CONTACT INFO

MANAGING EDITOR James Little james.little@palladianpublications.com

SENIOR EDITOR Callum O'Reilly callum.oreilly@palladianpublications.com

EDITORIAL ASSISTANT Poppy Clements poppy.clements@palladianpublications.com

SALES DIRECTOR Rod Hardy rod.hardy@palladianpublications.com

SALES MANAGER Chris Atkin chris.atkin@palladianpublications.com

SALES EXECUTIVE Sophie Birss sophie.birss@palladianpublications.com

PRODUCTION MANAGER Kyla Waller kyla.waller@palladianpublications.com

EVENTS MANAGER Louise Cameron louise.cameron@palladianpublications.com

DIGITAL EVENTS COORDINATOR Merili Jurivete merili.jurivete@palladianpublications.com

DIGITAL CONTENT ASSISTANT Kristian Ilasko kristian.ilasko@palladianpublications.com

DIGITAL ADMINISTRATOR Nicole Harman-Smith nicole.harman-smith@palladianpublications.com

ADMIN MANAGER Laura White laura.white@palladianpublications.com

CALLUM O'REILLY SENIOR EDITOR

As brighter days and sunny skies start to emerge in the Northern Hemisphere, many of us will be undertaking a dose of spring cleaning. While this annual ritual is now seen as an opportunity to give our homes a thorough tidy, declutter our wardrobes, and perhaps carry out a bit of DIY, the origins of spring cleaning actually date back to the 19th Century, when the practice was absolutely essential. According to the Washington Post, following a long winter where homes used to be lit with whale oil or kerosene, and heated with wood or coal, every room used to be covered in a layer of soot and grime.1 The arrival of spring signalled the perfect opportunity to throw open windows and doors, and get to work on a deep clean of the home.

Spring is also one of the key seasons for maintenance and turnarounds within the refining sector. In fact, this could be one of the heaviest turnaround seasons on record. As Argus Media’s Senior Correspondent, Nathan Risser, explained in an episode of the company’s ‘Driving discussions’ podcast earlier this year, the backlog of work can be directly attributed to the fallout from the COVID-19 pandemic: “US refiners were pretty reluctant to spend money on maintenance when faced with narrow refining margins during the COVID-19 pandemic, and then [they did not want to] take facilities offline during the post-COVID boom.”2 At the time of recording the podcast, Argus Media forecast that turnarounds were planned at 13 US refineries, totalling up to 3.4 million bpd of capacity in the first half of the year.

Turnarounds extend far beyond the routine maintenance that refineries undergo on a daily basis when they are in operation. They are enormous undertakings that can involve extensive maintenance, renovation and capital investment over a period of weeks or months. They also require extensive planning, with turnaround teams often beginning their work years ahead of when the turnaround actually takes place. This meticulous attention to detail is crucial to ensure that any potential disruptions to consumers and fuel supplies is limited while facilities are offline.

In a recent ‘Refinery Turnarounds 101’ blog posted on its website, the AFPM emphasised that there is a limited pool of highly specialised workers that are available to staff refinery turnarounds, including external consultants and crews that perform work across the industry.3 I’d like to pay special tribute to all of these workers who are currently going about their vitally important work, ensuring that our refineries continue to operate as efficiently and safely as possible.

I’d also like to take this opportunity to thank our very own maintenance specialist here at Palladian Publications, Richard Hancock, who is retiring after over 17 years of dedicated service. Although his name might not feature in the contact information section of this magazine, Richard has been a key part of the Hydrocarbon Engineering team, brightening up the working day whenever he is in the office. And he has also been an ever reliable (and often harsh) critic of the content that appears on this particular page of the magazine. Cheers Richard, this one is for you!

1. ‘Spring cleaning is based on practices from generations ago’, Washington Post, (25 March 2010).

2. ‘Driving Discussions: US Spring Refinery Turnaround’, Argus Media, https://www.argusmedia. com/en/news-and-insights/energy-and-commodity-podcasts/driving-discussions-us-springrefinery-turnaround

3. ‘Refinery turnarounds 101: What are turnarounds and why do we need them?’, American Fuel & Petrochemical Manufacturers (AFPM), (17 October 2023).

SBW Group

SBW Group Seven Decades of Progress

Seven Decades of Progress

In 1960, SBW manufactured their first own-design centrifugal compressor in the original Shenyang factory (background image).

In 1960, SBW manufactured their first own-design centrifugal compressor in the original Shenyang factory (background image).

New milestones regularly followed, across key process sectors . . .

1979 – Olefin plant compressors (115 000 tpy)

1979 – Olefin plant compressors (115 000 tpy)

1982 – Ammonia/urea plant (520 000 tpy)

1982 – Ammonia/urea plant (520 000 tpy)

New milestones regularly followed, across key process sectors . . .

1989 – Hydrocracker compressor (800 000 tpy)

1989 – Hydrocracker compressor (800 000 tpy)

2003 – Axial/centrifugal ASU compressor (40 000 nm3/hr oxygen)

2003 – Axial/centrifugal ASU compressor (40 000 nm3/hr oxygen)

2010 – First PTA plant compressor (600 000 tpy)

2010 – First PTA plant compressor (600 000 tpy)

2011 – High-thrust reciprocating compressor (125 t thrust)

2011 – High-thrust reciprocating compressor (125 t thrust)

2017 – Air separation for 100 000 nm3/hr oxygen

2017 – Air separation for 100 000 nm3/hr oxygen

2021 – PDH plant, 900 000 tpy (world’s largest using Lummus-process) DMCL1706+2MCL1707

2021 – PDH plant, 900 000 tpy (world’s largest using Lummus-process) DMCL1706+2MCL1707

2021 – first 1.4 million tpy Olefin plant (74 MW cracked gas; 39 MW propylene;

2021 – first 1.4 million tpy Olefin plant (74 MW cracked gas; 39 MW propylene; 24 MW ethylene) CNPC Guangdong

MW ethylene) CNPC Guangdong

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Head office & Manufacturing: Shenyang, China www.sbw-turbo.com

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qiming.chen@sbw-turbo.com (Europe & Middle East) Abu Dhabi, UAE tony.parish@sbw-turbo.com (Europe & Middle East) London, UK anding.xiang@sbw-turbo.com (USA & Americas) Charlotte (NC), USA

Europe: tony.parish@sbw-intl.com ; USA/Americas: anding.xiang@sbw-intl.com

Middle East: yang.yang@sbw-intl.com ; India & S. Asia: liusong@sbw-intl.com

qiming.chen@sbw-turbo.com (Europe & Middle East) Abu Dhabi, UAE tony.parish@sbw-turbo.com (Europe & Middle East) London, UK anding.xiang@sbw-turbo.com (USA & Americas) Charlotte (NC), USA

24

Oman | TotalEnergies launches Marsa LNG project

TotalEnergies and OQ, the Oman National Oil Company, have announced the final investment decision for the Marsa LNG project.

The LNG plant will be 100% electrically driven and supplied with solar power, positioning the site as one of the lowest greenhouse gas (GHG) emissions intensity LNG plants ever built worldwide.

The main engineering, procurement and construction contracts have been awarded to Technip Energies for the LNG plant and to CB&I for the 165 000 m3 LNG tank.

The Marsa LNG project aims to serve as the first LNG bunkering hub in the Middle East, showcasing an alternative marine fuel to reduce the shipping industry’s emissions.

Finland | Neste concludes first processing run with pyrolysis oil from discarded tyres

Neste has successfully conducted its first processing trial run with liquefied discarded tyres.

In the processing run, Neste produced high-quality raw material for new plastics and chemicals. For the run, Neste sourced pyrolysis oil derived from discarded vehicle tyres by Scandinavian Enviro Systems, a Swedish company.

The goal of the pilot run was to evaluate the potential of chemical recycling beyond plastic waste to potentially broaden the pool of

waste streams that could be processed into high-quality products.

In the past, Neste has successfully concluded several processing runs with liquefied waste plastic. These runs built the basis for the company’s decision to invest into large-scale capacities for chemical recycling at the company’s site in Porvoo, Finland.

The facilities being built are expected to be finished in the course of 2025 and will be able to process 150 000 tpy of liquefied waste plastic.

Germany | First large-scale electrically heated steam cracking furnace starts up

BASF, SABIC, and Linde have inaugurated the world’s first demonstration plant for large-scale electrically heated steam cracking furnaces.

Following three years of development, engineering, and construction work, the regular operation of the demonstration plant is now ready to start at BASF’s Verbund site in Ludwigshafen, Germany.

The demonstration plant, which produces olefins, such as ethylene, propylene, and possibly also higher olefins from saturated hydrocarbon feedstock, is fully integrated into the existing steam crackers in Ludwigshafen. The upcoming operation serves the goal of gathering data and experiences about material behaviour and processes under commercial operating conditions for the final development of this innovative technology to industrial market maturity.

France | Rhône Energies enters negotiations for acquisition of Esso Fos-sur-Mer refinery

Rhône Energies has entered into exclusive negotiations to acquire the Fos-sur-Mer refinery and the Toulouse and Villette de Vienne terminals from Esso.

The proposed acquisition is subject to a formal information and consultation procedure with employee representative bodies. Its completion is subject to regulatory approvals and is expected by the end of 2024. The financial terms of the proposed transaction are confidential.

Rhône Energies was formed by Entara and Trafigura to combine the strengths of a proven refinery operator with a global market leader in energy and commodities. Entara was established by former executives of Crossbridge Energy who have a track record of managing and optimising refinery assets, including at the Fredericia refinery in Denmark. Entara will manage the Fos-sur-Mer asset, overseeing operations, maintenance, asset integrity,

commercial, health, safety and environmental performance.

“We would be delighted to acquire and assume stewardship of the Esso’s Fos-sur-Mer refinery operations and look forward to engaging with the operational management, employee representatives and government stakeholders over the coming weeks and months to confirm our commitment to the operation and our plans for the future,” said Entara’s CEO, Nicholas Myerson.

WORLD NEWS

DIARY DATES

10 - 14 June 2024

ACHEMA

Frankfurt, Germany www.achema.de/en

11 - 13 June 2024

Global Energy Show Canada

Calgary, Alberta, Canada www.globalenergyshow.com

26 - 27 June 2024

Downstream USA

Galveston, Texas, USA events.reutersevents.com/petchem/downstream-usa

20 - 22 August 2024

Turbomachinery & Pump Symposia

Houston, Texas, USA tps.tamu.edu

17 - 20 September 2024

Gastech

Houston, Texas, USA www.gastechevent.com

22 - 25 September 2024

GPA Midstream Convention

San Antonio, Texas, USA www.gpamidstreamconvention.org

24 - 25 September 2024

IDW – Downstream Conference

Warsaw, Poland www.europetro.com/idw

15 - 17 October 2024

AFPM Summit

New Orleans Louisiana,, USA summit.afpm.org

04 - 06 November 2024

Sulphur + Sulphuric Acid 2024

Barcelona, Spain www.events.crugroup.com/sulphur

04 - 07 November 2024

ADIPEC

Abu Dhabi, UAE www.adipec.com

11 - 14 November 2024

ERTC

Lisbon, Portugal www.worldrefiningassociation.com/event-events/ ertc

USA | EIA: US ethane production set new records in 2023

US ethane production, consumption, and exports established new record highs in 2023, according to data from the US Energy Information Administration (EIA)’s ‘Petroleum Supply Monthly.’ Continued growth in ethane consumption in the global petrochemical sector and rising ethane recovery associated with natural gas production drove these increases.

US ethane production rose 9% to average 2.6 million bpd in 2023, driven by record natural gas production.

The Texas Inland and New Mexico refining districts, which span the Permian Basin, accounted for 61% of all US ethane production in 2023.

Domestic ethane consumption, measured as product supplied, rose 5% in 2023 to 2.1 million bpd. Two new petrochemical crackers, located in Port Arthur, Texas, and in Monaca, Pennsylvania, ramped up operations in 2023 after coming on line in late 2022.

US ethane exports averaged a record 471 000 bpd during 2023, a 57 000 bbl increase from the previous record set the year before.

Canada | Black & Veatch receives full notice to proceed for FLNG project

Black & Veatch, in partnership with Samsung Heavy Industries (SHI), has received full notice to proceed from Cedar LNG LP partners to begin constructing Cedar LNG’s floating liquefaction facility to be located in Kitimat, British Columbia, Canada.

Black & Veatch will be responsible for complete topside design and equipment supply, including its PRICO® technology. SHI will be providing the hull with the containment system, and

fabrication and integration of all topsides modules.

Cedar LNG is strategically positioned to leverage Canada’s abundant natural gas supply and British Columbia’s growing LNG infrastructure to produce low-carbon and cost-competitive LNG for overseas markets.

The near-shore export facility will feature electric-driven equipment powered by renewable energy.

India | IOCL selects Lummus’ cumene technology

Lummus Technology has announced that IndianOil Corp. Ltd (IOCL) has selected the Lummus/Versalis cumene technology for a 440 000 tpy unit in Paradip, India.

The new cumene unit is part of a grassroots petrochemical and polymers expansion at IndianOil’s complex.

Lummus’ scope includes the technology license for the cumene technology, basic design engineering,

proprietary catalyst, site services, advisory services, and training.

IndianOil has licensed multiple Lummus technologies, including naphtha cracker, INDMAX FCC and polypropylene technologies at complexes across India.

The cumene process is a liquid-phase alkylation technology using a proprietary zeolite catalyst and is characterised by a very high cumene yield, ultra-high purity cumene product and a long catalyst run length.

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If oil demand is peaking, why are China and India still investing? Ng Weng Hoong, Contributing Editor, investigates.

Chinese state firms have joined the bandwagon predicting an impeding end to growth in the world’s demand for oil.

Since late last year, CNOOC, Sinopec and CNPC have made separate comments supporting the view that environmental consciousness and the growing electrification of transportation will soon restrain further increases in global oil demand.

The end-of-growth scenario was the headline-making thesis in the International Energy Agency (IEA)’s five-year forecast published in its ‘Oil 2023’ report last June: “We estimate that global oil demand reaches 105.7 million bpd in 2028, up 5.9 million bpd compared with 2022 levels,” the IEA predicted.

“Crucially, demand for oil from combustible fossil fuels – which excludes biofuels, petrochemical feedstocks and other non-energy uses – is on course to peak at 81.6 million bpd in 2028, the final year of our forecast. Growth is set to reverse after 2023 for gasoline and after 2026 for transport fuels overall.

“These trends are the result of a pivot towards lower-emission sources triggered by the global energy crisis, as well as policy emphasis on energy efficiency improvements and the rapid growth in electric vehicle (EV) sales.”

The Organization of Petroleum Exporting Countries (OPEC) took the opposite view as the world’s two leading energy agencies openly clashed on the outlook for oil.

Who will prevail?

Asian countries, ever worried about energy security, may have to look closer to home for a better reading of the markets.

The debate will likely be settled in Asia by Asia, led by its two largest developing economies.

For a start, both China and India have largely paid lip service to reducing carbon emissions as they continue to invest heavily in their fossil fuels industries.

Action matters, not words

With Beijing’s encouragement, China’s oil industry has stuck resolutely on its path of expansion. The pledges by both its upstream and downstream companies to slow down obscure their real agendas for long-term expansion.

China’s refining capacity expanded by more than 9% last year, taking it past the US’ to become the world’s largest. Astonishingly, the sector kept up a rapid expansion programme during the COVID-19 years when the Chinese economy, along with the rest of the world’s, had slumped. From 2019 to 2023, Chinese oil firms boosted their refining capacity by more than 16% to a record total of 18.85 million bpd.

They are far from finished. China’s growing bilateral ties with Saudi Arabia and Russia necessitate further investments in domestic mid- and downstream infrastructure to absorb increasing oil flows from its two largest suppliers.

China’s continuing development of its refining, storage, piping, and retail facilities are geared unwaveringly toward one long-term objective: energy security.

The same can be said of India, which has become the world’s fastest growing major economy, having recently taken that title off China.

Both countries require growing inputs of fossil fuels every year to meet the needs of their combined massive populations of 2.8 billion, equal to 35% of the world’s total.

China’s push to transition to cleaner energy will not be rapid enough to temper its appetite for oil. Even the IEA acknowledges that China will remain a substantial oil, gas and coal consumer through 2050.

For its part, India has found a new lucrative role as an international refining hub, due in large part to the wars in Ukraine and Gaza. The West, ironically, will ensure that India remains a long way from reaching peak oil demand. Without the refineries of China and India, fuel prices would have surged in the US and Europe, ensuring inflation stays high for years to come.

China has been on a two-decade programme to beef up its strategic petroleum stockpile with virtually no end in sight. India has joined the race to expand its oil refining and storage facilities to catch up with China.

Rising geopolitical tensions are perhaps the biggest factor underpinning the continuing growth in the world’s oil consumption. The modern wars cannot be fought with solar and wind power, nor will generals be too concerned about carbon emissions.

Oil steady as Middle East wars escalate

Meanwhile, the oil markets continue to confound with another laidback response to the widening war in the Middle East.

Counterintuitively, Brent crude closed lower on 2 February 2024 after the US launched airtstrikes in Iraq and

Syria. Brent has traded around the US$80 range through most of 2024, down from US$88 when the Israel-Hamas war began on 7 October 2023.

Instead of heading for the US$100 - 150 range targeted by speculators booking large options positions, Brent has been in steady decline since hitting a post-war high of US$94 on 13 October 2023. The markets have also not been spooked by Yemen’s Houthis attacking oil tankers in the Red Sea, the drone strikes on a US military base in Jordan on 22 January 2024, and the US’ retaliatory airstrikes on pro-Iranian forces.

Asia remains vulnerable to supply disruptions

Yet, Asia’s nerves were rattled when a Singapore-operated tanker carrying Russian fuel was hit by a ballistic missile in the Gulf of Aden off Yemen on 26 January 2024.

Heavily dependent on imported oil and gas, Asia’s economies will be among the hardest hit if wars in the Middle East continue to intensify and expand.

The US military central command was quick to blame the Houthis for the attack.

The United Nations trade agency (UNCTAD) said weekly tanker transits and gas carriers have seen “significant declines” since November 2023 when Houthi militias began targeting traffic into the Red Sea.

BP, Shell, QatarEnergy, and many shippers have halted transit through the Suez Canal, with some shippers re-routing around Africa, said the US ratings agency, Fitch. But it does not “anticipate any material impact on prices”, as the re-routing may “marginally tighten the oil and gas markets” only temporarily.

Fitch said the world markets remain well-supplied for 2024 and has the comfort of more than 5 million bpd of OPEC and spare production capacity on call. “This will cushion any impact from potentially protracted or escalated disruptions,” it said, adding that China’s weak economy will translate into the country’s slower oil consumption growth.

However, Fitch said the scenario could change dramatically if the war engulfs the Straits of Hormuz which shipped 20.5 million bpd of oil in 1H23. That equals to 27% of the world’s seaborne oil trade delivering the bulk of Asia’s oil needs.

China’s oil risk is contained

Analysts expect China’s economy to grow at a slower rate in 2024 after expanding by 5% last year.

Citing ‘structural constraints’, the World Bank sees the Chinese economic growth slowing to 4.5% in 2024 while US ratings agency Moody’s pegs it at 4%.

“The outlook is clouded by continued weakness in the real estate sector and persistently tepid global demand in the short-term, as well as structural constraints to growth, including high debt levels, population ageing, and slower productivity growth than in the past,” said the World Bank.

Agreeing with the bank, Moody’s said China’s economic prospects will be dampened by its declining labour productivity and population, and high level of debt.

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While inflation has cooled across the world, Moody’s said it remains at risk of a resurgence from the volatile commodities markets.

For China, energy is the key source of risk.

“We expect oil prices to remain volatile in the US$80 - $90 per barrel range over the next three to six months,” said Moody’s.

While conflicts in the Middle East could push prices above the US$90 level, Moody’s said it expects that the war between Israel and Hamas will remain contained.

India’s rise as a global oil player

India has emerged as a global oil trading and supply hub. Add to that its position as the world’s fastest-growing major oil consumer, it now has a pivotal role in the global energy markets.

In a landmark report, the IEA predicts the country’s continuing expansive, disruptive impact on the energy markets: “Healthy economic expansion, combined with dynamic population, urbanisation and industrialisation growth, will see India’s role in global oil markets rapidly increase towards 2030, with significant implications for its oil trade balances, climate ambitions and energy security goals.”

The country’s ambitious oil refiners are leading the charge. Their capacity is expected to more than triple over the first three decades of this century, entrenching their importance in the global flow of crude and oil products.

India’s refining capacity doubled from around 2.2 million bpd at the start of the century to just over 4.3 million bpd in 2014, and to 5.8 million bpd at the end of 2023.

The IEA expects it to reach 6.8 million bpd by the end of this decade, making it the world’s third largest after the US and China.

India’s role in the energy economy

India’s refiners played an important role in stabilising the oil markets following the outbreak of the wars in Ukraine and Gaza.

When oil prices surged on trade sanctions against Russia for invading Ukraine in February 2022, India stepped in to supply diesel, kerosene and gasoline to consumers in the US and Europe. For importing Russian crude at big discounts, India’s refiners were initially blasted for undermining the US-led sanctions that were aimed at crippling Moscow’s war machine. The Indian government countered that the refiners processed the crude into products to meet the needs of Western and Asian consumers who were reeling from rising inflation.

In 2023, India exported 1.2 million bpd of refined products, making it the world’s sixth largest supplier.

“India’s role as a global swing supplier has risen since 2022 as the loss of Russian product exports to European markets has increased the pull of Asian diesel and jet fuel westward,” said the IEA.

It expects India to maintain its position as an important supplier of transportation fuels to markets in Asia and the Atlantic Basin.

“Continued investment in refining capacity and complexity will boost light and middle distillate production,

even as the industry pivots further towards heavier and more sour crudes,” said the Paris-based agency.

Domestic demand

Much of India’s new refining capacity will also be directed to meet the growing needs of its domestic consumers.

The IEA is forecasting India to overtake China as the single largest source of global oil demand growth from 2023 to 2030. Indian oil demand will rise by almost 1.2 million bpd to account for more than one-third of the world’s projected 3.2 million bpd in new consumption.

In 2023, India consumed more than 5.2 million bpd, making it the world’s third largest market after the US and China.

Petrochemicals production will be the main driver of India’s oil demand growth through 2030.

“We estimate that a combination of new plants and incremental expansions will see Indian feedstock demand rise by about 210 000 bpd over the period. Of this growth, 120 000 bpd is additional naphtha input to steam crackers and for aromatics production, and 90 000 bpd is LPG and ethane used in steam crackers and propane dehydrogenation (PDH) plants.”

Road and air transportation will be driver for India’s oil market.

Following an eightfold increase from 2000 levels, India today has around 58 million vehicles. In describing this as being ‘comparatively limited,’ the IEA suggests India’s car ownership could be on the verge of explosive growth.

India is on the verge of developing an appetite for air travel. “At just 180 000 bpd, jet/kerosene accounted for only 3.4% of Indian oil demand in 2023, less than half of the global average (7.3%). This reflects the fact that air travel is strongly correlated to income,” said the IEA.

“India’s total aviation activity and jet fuel requirements were roughly equal to those of France, leaving substantial potential for growth.”

India’s concerns

India’s emergence as a global oil refining hub has a downside: an increased exposure to the Middle East’s politics. India’s 5.2 million bpd of refining capacity has become an important source of supply for Europe’s diesel market, which became off limits to Russia since its invasion of Ukraine in February 2022.

But since November 2023, Indian refiners have been stung by the rising cost of shipping refined products to Europe.

According to intelligence provider, Vortexa, 43% of European diesel imports in 2023 were delivered through the Red Sea, supplied almost entirely by East of Suez refiners. One of them is India’s leading privately owned refiner, Reliance Industries, which owns the world’s largest standalone 1.4 million bpd refinery in Gujarat state. Reliance has joined Shell, QatarEnergy and other international firms in avoiding shipping oil through the Red Sea. According to S&P Global Commodities, Reliance did not export any diesel to Europe in the first two weeks of January 2024.1

In taking the longer route around Africa to Europe, tanker owners and operators are charging much higher

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chartering rates. As a result, Indian newspapers report that the country’s diesel exports fell sharply in January 2024.

Sri Lanka welcomes China’s proposed US$4.5 billion refinery

Chinese state firm, Sinopec, is becoming Sri Lanka’s most important investor with the planned addition of a US$4.5 billion oil refinery to its growing portfolio in the South Asian nation.

The company is already the owner of an oil storage terminal and the operator of a bunker fuel business in the strategic port of Hambantota serving shipping traffic in the Indian Ocean.

For Sri Lanka, the proposed refinery starting with a 100 000 bpd unit will solve two major challenges: energy security and the generation of much-needed export earnings for its bankrupt economy.

In 2022, Sri Lanka experienced political and economic collapse as the people, hurting from years of government corruption and mismanagement, took to the streets and forced President Gotabaya Rajapaksa to flee the country. Sri Lankans suffered severe fuel and food shortages after the government defaulted on international loans as it racked up record debt and budget deficits.

In the depth of Sri Lanka’s pessimism, Sinopec’s decision to build a new refinery will provide a huge boost of confidence for the hyperinflation-ravaged economy which has scared off investors.

The bolt of good news announced in November 2023 by Sri Lanka’s Power and Energy Minister, Kanchana Wijesekera, contributed to a 3.4% rise in the country’s stock market over a 10 day period.

According to Sri Lanka’s Sunday Times, Sinopec has agreed to set aside 20% of the plant’s products output for the country’s domestic consumption.

The company’s subsidiary, Sinopec Fuel Oil, is the operator of Hambantota’s 140 000 m3 storage terminal to support the port’s bunker and LPG supply services.

Hambantota International Port Group (HIPG), which operates the port, is a private limited liability company jointly owned by the Sri Lankan government and China Merchants Port Holdings (CMPort).

Rongsheng, Aramco deal

China’s Rongsheng Petrochemicals and Saudi Arabia’s Aramco are in talks to buy into each other’s units as ties between the two countries deepen.

According to a recently-signed MoU, Rongsheng will buy a 50% stake in Aramco’s Jubail Refinery Company, SASREF, while the Saudi giant will acquire half of the Chinese firm’s Ningbo Zhongjin Petrochemical subsidiary. The partners will look to upgrade Ningbo Zhongjin’s existing facilities as well as jointly develop a project in Zhoushan prefecture in Zhejiang province.

In March 2023, Saudi Aramco announced plans to acquire a 10% stake in Rongsheng Petrochemical that included a 20 year agreement to supply crude oil to the Chinese firm’s subsidiary, Zhejiang Petrochemical Corp.

The Rongsheng deals mark Aramco’s continuing expansion into Asia, particularly in China where it owns large

stakes in refining and petrochemical plants, and is competing against Russia to supply oil to the world’s second largest economy.

In September 2023, Aramco became a strategic investor in privately-held Jiangsu Shenghong Petrochemical, which operates a 320 000 bpd refinery and petrochemical complex in Jiangsu province.

Saudi Arabia exported 647 million bbl of crude oil to China in 2023, behind Russia which supplied 786 million bbl. Aramco lost its position as China’s largest oil supplier when Russia began offering significant discounts to offload its crude which was hit by international sanctions following President Putin’s war on Ukraine in February 2022.

Pakistan expects more Aramco investment

Saudi Arabia’s energy giant Aramco is laying the foundation for business expansion in Pakistan with its planned acquisition of a 40% stake in a local downstream fuels, lubricants and convenience stores firm.

Aramco expects to soon complete its investment in Gas & Oil Pakistan Ltd (GO), which is one of the country’s largest retail and storage companies. The transaction is subject to regulatory approvals.

The Saudi state firm said the venture represents its entry into Pakistan’s 500 000 bpd oil market. While Pakistan’s fuel demand is small by Asian standards, the country has a large population of over 230 million and occupies a strategic location between the Middle East, Central Asia, and East Asia.

In July 2023, Aramco signed an MoU with four Pakistani state companies to explore the construction of a US$10 billion greenfield oil refinery in Gwadar port in Balochistan province. The port, located at the mouth of Persian Gulf just outside the Straits of Hormuz, is being developed and operated by the China Overseas Port Holding Co.

Sinopec could be offered a role in the proposed refinery, according to Pakistan’s Business Recorder newspaper.

While financial viability remains the primary consideration, the project is also being driven by geopolitical concerns. Saudi Arabia and China are tightening their political and economic relationship as part of their challenge to the US-led global order.

Fitch affirms Malaysia’s Petronas credit rating with a warning

Malaysia’s state-owned energy firm, Petronas, has been given a BBB+ credit rating of ‘adequate’ with low expectations for a default risk by Fitch Ratings.

While considered a ‘good credit quality’, the rating also carries a warning about Petronas’ finances. The company will have to look to the government for support if it is to avoid a default in the event of ‘adverse business or economic conditions.’

Petronas is Malaysia’s most important business entity as it is the government’s main source of revenue. In 2022, the company, which owns the country’s oil and gas resources, accounted for 31.6% of the state’s revenue, up from more

than the average annual of over 20% in the preceding four years.

Fitch said it rates Petronas’ credit standing “stronger than that of its shareholder”, the government. The company’s strength stems largely from its oil and gas assets, including its proved reserve life of 11 years as of 1 January 2023, based on the 2022 production of 1.68 million boe/d. In 2021, the company produced 1.57 million boe/d.

Petronas has been cash-positive since 2006, thanks to the health of its diverse upstream and downstream operations. As of end-September 2023, Petronas had a net cash position of 112.6 billion ringgit (US$1 = 4.73 ringgit).

“We expect Petronas to remain in a net cash position after dividends and CAPEX over the medium-term, supported by our expectations of strong operating cash flow,” said Fitch. “Its debt maturity schedule is spread out, with maturity (excluding leases) of around 8 billion ringgit in the next 12 months as of end-September 2023 and around 25 billion ringgit over the next four years.”

Political turmoil

Despite Fitch’s affirmation of Petronas’ financial standing, the company faces dark clouds overhanging the Malaysian economy.

Fitch warned that Malaysia would face ‘very strong’ socio-political backlash in the event of a Petronas credit default that would also ‘severely disrupt’ the country’s energy security.

“A default would jeopardise Petronas’ ability to undertake upstream oil and gas production, refining, retail distribution of fuel, and gas supply to the power and other industries,” the US firm said.

“The financial implications of a default are ‘very strong’, as the company accounts for a large share of government revenue and investors see Petronas bonds as a proxy for sovereign bonds.”

Malaysia has probably Southeast Asia’s worst-performing economy over the past decade owing to the country’s increasingly unstable political situation. It has had five prime ministers in that period. The ringgit recently plunged to a record low of RM 4.8 to the US dollar, with expectations it might breach RM 5 as pessimism looms over the economy.

Malaysia is also facing a brewing separatist movement in the energy-rich states of Sabah and Sarawak on Borneo Island. The two states receive only 5% of Malaysia’s oil and gas royalties although they produce 68% of its oil and 74% of its natural gas. They are also among Malaysia’s poorest states, fuelling angry demands from local politicians for a greater share of national resources.

Reference

1. ‘Shell, Reliance seen diverting tankers from Red Sea as Houthi attacks continue’, S&P Global Commodity Insights, https:// www.spglobal.com/commodityinsights/en/market-insights/ latest-news/oil/011624-shell-reliance-divert-tankers-fromred-sea-as-houthi-attacks-continue#:~:text=S%26P%20 Global%20Commodities%20at%20Sea,a%20halt%20 in%20recent%20days.

Like most aspects of modern industrial production, asset performance management (APM) has been transformed by a new generation of digital and automation tools. Industry 4.0 solutions like artificial intelligence (AI), machine learning (ML) and data analytics can now be easily integrated into established operational technology (OT) and information technology (IT) environments, giving operators unprecedented visualisation and control of critical assets.

Central to this revolution is real-time IT and OT data gathered in the operational domain by wired and wireless sensors and then analysed to accurately assess the health of equipment, enabling personnel to make informed decisions around maintenance and repair to drive efficiencies and avoid costly downtime.

‘APM 4.0’ can be of particular value in large resource and emission-heavy facilities housing multiple devices, often in remote or hazardous environments. For example,

a condition monitoring solution and sensors for rotating equipment can be deployed through a Bluetooth network: personnel are given an overview of the health of plant assets via a user-friendly dashboard, including proactive alerts of potential issues, avoiding the common problem of applications and data running in silos.

The overarching goal of APM 4.0, of course, is to help customers predict process failures way before they occur, thus improving the reliability, availability and maintainability of their critical equipment.

This article will explore the added-value elements of APM 4.0 in terms of sustainability, long-term reliability and costs, and company culture; the evolution of condition monitoring, from time or usage-based strategies to today’s quantitative risk analysis and current-state-of-machine solutions; and how ABB’s APM solutions are helping to modernise a refinery in Kazakhstan.

Industrial operators that take advantage of the latest digital and automation asset performance management (APM) tools can look forward to improved operational efficiency, reduced downtime, and a proactive maintenance culture. Stacey Jones, ABB Energy Industries, explains.

Wake up to the benefits of APM 4.0

Despite the many benefits of ‘APM 4.0’, there remains a lack of traction for APM in many industries, for a variety of reasons. One is the misconception that asset failures are ‘rare’ events, when in fact they happen on a regular basis, with 82% of asset failures actually taking place at random intervals.1

This leaves many companies in an unfortunate position: the unlikely nature of these events does not incentivise capital investments in continuous condition monitoring, while time-based maintenance does not catch all potential problems. There is also the cost factor, of course, with many operators believing that new-generation wireless sensors are still more expensive than their traditional wired counterparts. In reality, the recent decrease in the cost of technology that uses connection protocols such as Bluetooth or WirelessHart means that adding the ability to continuously monitor

industrial assets has finally become a cost-effective alternative to manual, infrequent condition monitoring.

Despite this, maintenance continues to be done on a fixed time interval or through machine hours rather than based on current data, leading to higher maintenance costs: maintaining assets only when needed can decrease maintenance costs by 20 - 30%, and machine downtime by 20 - 50%.2

The current standard for most small-to-medium sized rotating equipment, therefore, is little to no condition monitoring. For equipment deemed medium to high risk, vibration monitoring is carried out using manual techniques during regular operating rounds. The data may be discarded once the values are deemed to be within ‘normal’ range, preventing the ability to trend and learn from it.

Shockingly, less than 20% of data generated by industrial companies is actually utilised – even less is

analysed. This means that up to 80% of what is arguably a company’s most precious resource is lost.

A new era of data-driven APM

Thankfully, the Industrial Internet of Things (IIoT) is changing this. As mentioned, APM has evolved in the past two to three decades from run-to-failure reactive – meaning equipment had to be shut down at short notice for unplanned maintenance –to today’s advanced data-driven technologies.

The next step up from reactive APM was usage or time-based maintenance, where a schedule was used to assess when equipment was about to fail with a view to addressing the issue before it had occurred; however, this failed to take into account that industrial assets are of varying importance leading to high maintenance backlogs with varying return on investment (ROI).

Next was risk-based maintenance, which uses innovations such as failure modes and effects analysis (FMEA) and reliability-centred maintenance (RCM) to prioritise critical assets. While this constituted a significant step forward, it too had its limitations in that maintenance is based on how an asset has behaved in the past, rather than using real-time data to prevent assets from failing across the board.

Let us use the analogy of a doctor’s examination. If the physician only asks how the patient is feeling rather than taking their temperature and blood pressure, etc, that is only half the picture. With more quantitative information comes better decision making – and, ultimately, a more accurate diagnosis.

Enter APM 4.0, which employs data-driven and statistical models including AI and ML techniques – algorithms are taught what optimum asset performance is across multiple variables – and then sends an alert when equipment, machinery or instrumentation violates these conditions.

A layered, hybrid, standardised approach

ABB adopts a pragmatic, layered approach to APM, in recognition of the fact that its customers are at different stages of their digital journey, and may therefore benefit from a hybrid APM solution.

This simply means that less critical assets may only need rules-based, or derived or calculated, monitoring: this may be a

sensor that sends a notification if the temperature or pressure exceeds a pre-defined threshold. An example is taking raw vibration data and calculating the root mean square (RMS) velocity (how the vibration is increasing over time). This is a baseline layer of APM protection.

However, there are more complex layers that can be deployed to maximise protection around the asset using physics and engineering design-based ‘first principles’ models that tell the company how a specific piece of equipment performs. In addition, pure data-driven models leveraging AL/ML can also be deployed to create a nonparallel level of protection for the most critical assets.

ABB also operates a standardised or ‘data agnostic’ strategy whereby all assets – electrical, rotating, instrumentation, IT, and fixed equipment, etc – are combined. Using adapters to convert data from non-ABB historian and computerised maintenance management systems (CMMS) so that it can be understood by ABB technology and brought together in one location, ready for analysis using advanced APM tools.

Case study: Shymkent oil refinery, Kazakhstan

In Kazakhstan, the ABB AbilityTM platform − a unified, cross-digital offering comprising software, hardware and services – was deployed to help modernise a major oil refinery.

The Shymkent site was commissioned in 1970 and it is located in the Sayramskiy region of Kazakhstan Shymkent. It is operated by PetroKazakhstan Oil Products (PKOP), a joint venture (JV) between the China National Petroleum Corp. and KazMunayGas, the national oil and gas company of Kazakhstan.

Sensors, data and advanced analytics all monitor and assess the health of the refinery’s assets in real time, providing PKOP with critical, real-time insights into equipment and production processes. At Shymkent, digital transformation is expected to increase productivity and lower operational costs, empowering staff to make better-informed decisions based on accurate and live data and reporting.

The project is a compelling example of how the benefits of integrating Industry 4.0 technologies into existing operations can form part of a company’s or country’s wider digital transition – in this case the government-led ‘Digital Kazakhstan’ programme, which focuses on accelerating growth and elevating economic sectors such as oil, gas and chemicals throughout the Republic using digitalisation, with a goal of creating a sophisticated digital economy.

PKOP’s maintenance strategy has evolved from an hourly-based system to a prescriptive or predictive-based one. ABB extended the maintenance annual turnaround intervals at the refinery to a three-year plan to ensure early identification of when assets might need repair or replacement – supporting operators to prioritise maintenance based on actionable insights.

ABB provides a business consultancy service to PKOP to support the project lifecycle and promote culture change in adopting digital practices at the Shymkent plant. This includes assessing current work processes, leveraging opportunities to increase efficiency and resilience, recommending improvements, and providing expert staff training.

Figure 1. Minimise on-site personnel and safety risks by reviewing machine health remotely from a computer or mobile device.

Valued-added benefits

The residual benefits of effective APM are also important. Implementing data-driven rather than reactive condition monitoring helps to establish a robust reliability culture, where personnel are empowered to take control of asset health, instead of simply reacting to failures after the event. Maintaining equipment and machinery in peak condition also helps reduce asset life cycle costs.

Using ABB’s APM application, for example, key data, along with information gathered from other rotating, electrical, instrumentation and IT equipment, can be monitored in a single location. This enables operators to prepare interventions, short and long-term planning and predictive maintenance, maximising asset usage in terms of productivity, safety, quality, efficiency and cost optimisation.

In addition, this information can also be utilised further by enterprise resource planning (ERP) tools and CMMS, avoiding the need for manual interventions, facilitating integration with existing service scheduling, including the replacement of equipment, and ultimately contributing to an autonomous business process. APM can also contribute directly to improve sustainability, since critical assets in large, resource-heavy industry sectors tend to be the largest consumers of energy.

In summary, APM 4.0, including innovations such as AI, ML and advanced analytics, represents a unique opportunity for oil and gas operators to take full control of asset health and maintenance, improving production efficiency and sustainability, limiting unplanned or forced downtime, fostering

a proactive maintenance and repair culture – and helping them maintain competitive advantage.

References

1. ‘What is Asset Performance Management?’, ARC Advisory Group, https://www.arcweb.com/technologies/asset-performancemanagement

2. ‘The future of maintenance for distributed fixed assets’, McKinsey & Co., (5 June 2020), https://www.mckinsey.com/ capabilities/operations/our-insights/the-future-of-maintenance-fordistributed-fixed-assets.

Figure 2. ABB APM 4.0 technology proactively alerts users of potential issues, and on-site maintenance personnel can be deployed ahead of unplanned downtime.

Nienke Gerridzen, Yokogawa, explores how companies can maximise the impact of digitalisation in a VUCA world.

When diving into Meta platforms, LinkedIn, or X, one cannot help but be swept away by a tidal wave of buzzwords and acronyms. Linguistic titbits such as ML, LM, AI, RUPT, TUNA, VUCA, and BANI sketch the tapestry of today’s digital ecosystem.1 But what lies beneath the jargon sea? And more intriguingly, how do these concepts forecast the trajectory of assets in relation to digitisation? Today, we are confronted with a world that is often described as VUCA (volatile, uncertain, complex, and ambiguous). This term has been around for quite some time now and is known beyond the boardroom of the big oil and gas majors and consultancy firms. More recently, the terminology of BANI (brittle, anxious, non-linear, incomprehensible) has been introduced by Jamais Cascio (American anthropologist, author, and futurist), used more specifically for technology and innovation and is seen as the replacement for VUCA. BANI has emerged as a new framework for explaining the challenges of the digital era.

The need and impact of digitalisation

A commonality can be spotted among all projects and initiatives to cope with the VUCA and BANI environment: the imperative need for agility and resilience in decision-making processes. There is a clear need for digitalisation to deal with the impact of the following:

n Retirement: not only to cover for the coming ‘brain drain’, but also to adapt to the challenges of the young digital natives entering the workforce.

n Competitiveness: introducing less labour-intensive ways of working and realising maximisation of production potential.

n Integration: stand-alone systems need to be ‘talking’ with their environment to adapt end-to-end by the flick of a button on the enterprise level.

n Switch from on-prem to the cloud in case of autonomous operations (operate from anywhere strategies).

As well as the transformation of control rooms, digitalisation trends can be seen on a more personal scale, such as the transformation of desktop computers to laptops, tablets, wearables, and the future of augmented reality goggles. Digitalisation is here to stay.

Digital strategy through collaboration and integration

When discussing integration and digitalisation, Yokogawa refers to a digital factory as a highly automated and interconnected facility within the industrial ecosystem that leverages digital technologies such as artificial intelligence (AI), Internet of Things (IoT), and data analytics to optimise operations, enhance productivity, and enable real-time decision-making.

While a lot of companies are installing their decarbonisation/sustainability managers to bundle initiatives and cope with (upcoming) major changes on a centralised level, Yokogawa sees that the responsibility for digitalisation continues to be spread around the IT and OT organisation.

Currently, Yokogawa is working with industrial majors and start-ups toward decarbonisation and has found that working towards a commonly understood concept of the future ‘digital factory’ is key to successfully maximising the impact of digitalisation for all types of organisations and respective maturity levels.

Prior to outlining any strategic approach, it is essential to ascertain the baseline maturity level, setting the stage for informed, targeted planning. Yokogawa’s analysis reveals some key challenges, such as scattered data, islands of information, inconsistent processes, and outdated technology. Collaboration between IT and OT also sheds light on where a company stands. Despite each company’s uniqueness, many face similar hurdles in managing complexity and shared duties while keeping operations smooth

and safe. A tailored digitalisation plan, shaped by diverse expertise, can address these issues. However, the task is too vast for a single integrator; a collective effort from partners and the entire value chain is crucial for success.

Recently, the Port of Rotterdam (the Netherlands) – home to more than 200 industrial companies in Europe’s largest port – started a collaboration study to increase energy and resource efficiency across industries. It is here where the approach of collaborating with the entire value chain and Yokogawa’s ideas about the future digital factory (especially the interconnected requirements) can be seen in effect. In this case, digitalisation will be the enabler for the realisation of up to 5% improvements in efficiencies – from better alignment of the use of electricity, heat, steam, and feedstocks such as water and industrial gases, resulting in lower costs and a reduced carbon footprint, according to the pre-feasibility study. The study also indicated that deeper integration and optimisation could yield savings as high as 10%. Again, integration can only be realised by digitalisation and is subject to the security and robustness of the digital architecture amongst companies.

How digitalisation can improve business models

Not only in brownfield situations, the future digital factory can bring a digitalisation approach between the IT and OT environments. Especially in the case of greenfield situations, a digital-first approach can enable improvements to the business model and predictability in the longer term:

n Full autonomous operations require a digital strategy to orchestrate in a safe and efficient way.

n Modelling the future optimisation – how can the plant be operated to maximise results, and what changes are required in the architecture to realise these?

n Imagine the potential of the use of robotics for inspections or even interchanging valves in the future – how can this fleet be managed? And are pathways designed for non-human access?

n Full integration of a digital twin in all layers (sensors up until the enterprise level) in a cyber-secure way.

Theory meets practicality

In a true theory-meets-practicality scenario, imagine how your robotics fleet and platform are seamlessly integrated into a digital-first strategy, with your asset primed for drone docking

and charging located on Jurong Island, Singapore. But have you considered the increasing number of thundery showers on a yearly basis risking the availability of the drone services? Despite our digital advancements, the invaluable insights of day-to-day information and lessons learned from real-world applications remain indispensable.

The management of Orlen in Poland is adopting a digital twin first strategy; an integrated management solution to produce synthetic fuels will be the basis of the facility, which will be constructed by the end of 2030. In Orlen’s view, this digital-first strategy is allowing the company to realise frontrunner status on the production of sustainable aviation fuel (SAF) on an industrial scale (70 000 tpy from 2030). Moreover, tight end-to-end tracking through the whole value chain of the production site will allow Orlen to meet requirements for Renewable Fuels of Non-biological Origin (RFNBO) set by the EU in the RED-III directive, which aims to increase the share of renewable energy in the EU’s overall energy consumption to 45% by 2030.

A similar approach can be seen in the Holland Hydrogen I project of Shell, which will be one of the biggest green hydrogen factories in the world (Figure 1). It is there that Yokogawa and other suppliers have been challenged to create the ‘asset of the future’ and bring the operation philosophy ‘decision integrator (3rd level)’ to life. Integrated data sources and common platforms merge with progressive processes and task automation that change the work performed by people. People make decisions using real-time information at their fingertips with recommendations provided by machines.

Considerations

The above-mentioned cases show an entrepreneurial mindset to invest in a digital-first strategy for both brownfield and greenfield situations in a volatile market. Moreover, it depicts high-level ideations. But what about the details and how to get started on those after deciding maturity level and design/roadmap? Here are some important early structural considerations:

n What is your operator strategy? And chosen level of autonomy?

n The use of on-prem/public and/or private cloud. As security and control continue to be crucial, these architectural choices need to be made early in the process.

n Will the use of open platform communications (OPC) unified architecture support you in the future, and is applying this of future benefit for the operability of your plant?

Based on current economic conditions, it can be expected that Europe and the rest of the world will experience continuous volatility and ambiguity for some years to come. However, there are many coping strategies for both brown and greenfield projects to digitise, maximising current production capacity and increasing interoperability whilst setting the standard for the new world we are facing.

Note

1. ML (machine learning), LM (language model), RUPT (rapid, unpredictable, paradoxical, and tangled), TUNA (turbulent, uncertain, novel, ambiguous).

Figure 1. Holland Hydrogen I (source: Kraaijvanger Architects).

These are challenging times for refineries. The energy transition, demand for cleaner fuels and speciality products, coupled with the pressure to increase efficiencies and profitability, is driving innovative developments to meet these challenges.

Committed to creating customer-centric solutions, a digital innovation project by Tracerco’s diagnostics team has identified two key areas for improvement that can tackle these challenges, making verified asset data accessible and reducing production downtime.

Andy Phillips, Tracerco, UK, explains the important role of actionable data in providing efficient and insightful refinery column scans.

The consequences of any given refining production shutdown are significant. From the fiscal impact of downtime, and the increased safety and technical risks of startup, to the ripple effect on the supply chain, enabling an operator to safely reduce shutdown frequency and duration is essential for sustainability, commerciality and security of supply.

It is worth noting that in the US alone, 2023 witnessed an 11% increase in offline capacity compared to 2022, with an estimated reduction in refining capacity of 2.5 million bpd.1

As complex interconnected facilities, refineries convert raw hydrocarbons into the fuel, plastics, and chemicals used across our everyday lives. Refining columns (towers) are central to the process, and it is these columns that have been the focus of the digital development by Tracerco – designed to create efficiencies and enhance safety through improving the accessibility of verified, actionable data.

While the scanning of refining columns while in operation already created significant efficiencies in

shutdown planning, insights and early detection of potential problems, Tracerco’s diagnostics team identified that, in order to increase the value to customers, the scan report format and delivery time needed to be addressed and the process streamlined.

The existing methodology

Column scans are used to evaluate operational integrity and performance. Whilst baseline scans provide a valuable historical reference point for analysis, scans are also used for maintenance planning and for providing the essential data to inform decision making.

To conduct a vertical column scan while it is still operational, a small, sealed gamma-ray-emitting radiation source on one side of the column is deployed. A sensitive electronic radiation detector is used on the opposite side to measure radiation transmission. The synchronised movement of the source and detector, incrementally lowered over a predetermined vertical range, captures critical data, for example, the count rate of radiation received by the detector which allows an interpretation of the inside of the column to be built up. This data is then analysed and included in a comprehensive report in PDF format with an approximate delivery time of three weeks.

Through the ability to scan, analyse and report while the asset remains operational, efficiencies had already been created through effective shutdown and turnaround planning. Ensuring the right equipment, replacement parts and technical personnel are available and coordinated makes for first time right success and a slicker workflow. Additionally, customer feedback confirmed that making the report more user-friendly, agile and available faster created even greater value.

Challenge(s) accepted

Involving customers – the end users of these solutions – in technological development ensures that real-world tangible solutions are created, which can be readily adopted within their own processes.

The outcome of this project was the creation of a customer portal to enable rapid access to tower-scan information, automated data visualisation and shared responsibility for reports across the organisation. The design sprint yielded a prototype by day four, with customer feedback incorporated by day five.

A series of development cycles followed, involving customers at every stage, enabling them to shape the solution and transform the prototype into a phase one production-ready system. An internal hackathon shaped the interface and second phase established a same day reporting system, providing customers with complete control, customisable views, and interactivity with Tracerco’s engineers and technical experts.

Infrastructure

User collaboration and participation in testing was essential for defining the infrastructure of the TracercoTM Insights Platform. By hosting using Microsoft Azure, high availability, scalability, and built-in security was provided. Azure seamlessly integrates with the existing technology

Figure 1. Insights Platform showing the different reports available for a customer’s tower.

Figure 2. Customer’s interactive report.

Figure 3. Customer’s dashboard.

Gain greater process clarity

It’s time to optimise your processes

Tracerco uses innovative technology to provide critical insights into what’s going on inside your processes. Our insights let you optimise efficiencies, increase productivity and troubleshoot production problems, at a time when you need it most.

And you’ll be in the safest of hands – we provide the widest range of scanning and tracer services on the market. With over 65 years’ experience, we’ve saved companies around the world billions.

Scan the QR code to find out how we can help you gain greater process clarity.

tracerco@tracerco.com tracerco.com

stack, using .NET for the backend API services and Angular for front-end web applications.

Angular, supported by Typescript, a Microsoft technology, allows the development team to work with familiar technologies. It is a mature framework of enabling the building of performant, modern front-end web applications quickly without reinventing the wheel. Regular updates provide performance and security improvements, keeping the platform in sync with browser updates.

D3 was chosen for graph plotting due to its framework designed for bespoke graph creation and its fast render time when filtering on the column, allowing for an interactive version of older PDF reports. Third-party components – modified by the development team –enable quick prototyping and feature addition throughout the development lifecycle.

Outcome

It is nearly 20 years since British mathematician, Clive Humby, coined the now infamous phrase that ‘data is the new oil’. In the interceding years, this quote has often lost its meaning in its frequent citation. However, what Humby was saying was that, like oil in its raw state, data has potential only if it is refined to be of value.

It is possible to access this value through platforms that provide access to vertical scan data in multiple formats and automated data visualisation, enabling

shared responsibility for reports. Users can compare historic and current data and interact with technical experts within the portal. This has eradicated the wait for scan reporting and enabled same-day access to verified data – the critical insights, to make highly informed decisions quickly.

Such platforms enable data to be consumed in an easier way, and it is also possible to integrate/drill down into the data, zooming into areas of the column. It is also possible to customise the view of the report so that operators can see the relevant data that they need (such as viewing froth heights or viewing the scanline orientation). Scan lines can also be toggled to see the area of the column that operators are interested in.

Conclusion

The development of the Tracerco Insights Platform, combined with innovative scanning technology, has ushered in a new era of efficient, and insightful scanning of refining columns.

This was only achievable by engaging with customers, listening to their preferences, expectations and needs, learning from their experience, and involving them in the testing phases as the ultimate end users of the portal.

Reference

1. https://www.bloomberg.com/news/articles/2023-10-02/ us-refiners-gear-up-for-heaviest-fall-refinery-maintenanceseason-since-2019?embedded-checkout=true

Mateus Camparotto, Alkegen, South America, presents the results of a study undertaken to evaluate insulation alternatives for the convection section of petrochemical furnaces.

In the dynamic realm of industrial processes, the quest to reduce carbon emissions and cut down energy costs has never been more crucial. Recognising the pivotal role of heat as a critical resource, each step towards improved furnace performance translates into not just cost savings, but a substantial decrease in carbon footprint.

When it comes to furnace efficiency, strategic solutions are available that can help to enable a world

where industrial furnaces become champions of energy conservation, significantly lowering operational costs while embracing a sustainable ethos. Petrochemical sites, with their inherent challenges, provide fertile ground for the application of such solutions. During maintenance shutdowns – where every move is strategic – products that confidently navigate the labyrinth of confined spaces and ease of installation offer advantages. Beyond addressing critical safety risks,

they guarantee a secure pathway to operational excellence, minimising downtime and advancing the pursuit of carbon neutrality.

The critical role that the convection section plays in heat capture

In a typical reformer furnace, natural gas is turned into hydrogen gas through a multi-step process. First, the gas is passed through tubes filled with a catalyst and water vapour. This mixture is then transformed into hydrogen gas and sent to other processes in the unit.

When the product is being processed, the catalyst tubes are heated by radiation to around 700°C (1300°F). The heat generated also passes through a section called the convection section. In this part, the heated gases are used to generate steam and warm up the product load and air for the radiant section. The convection section has a metal casing with insulating material, and within it, tubes are arranged to

let the combustion gases preheat the fluid through heat exchangers.

Traditional approaches

Traditional refractory uses castable, insulating firebricks (IFB), or refractory ceramic fibre insulation that are anchored to the walls of the convection section. The maintenance of these walls is extremely challenging. It is often necessary to remove the piping to allow free access to the lining, causing damage to the surrounding lining. The removal process and potential damage becomes a critical path in the downtime of the unit and can result in long delays and increased cost expenditures.

Important considerations in insulation project design

Designing thermal insulation in the convection section requires detailed analysis and consideration of many factors. Maximising the thermal effectiveness of the system requires the selection of materials with low thermal conductivity properties while maintaining mechanical stability.

The insulating material must exhibit resistance to the maximum temperature required by the process along with erosion and thermal variations. The overall installed system, including anchoring, must maintain mechanical stability during service, resisting all chemical components present in the process, without disassociation, degradation, or disintegration.

Emerging solutions

Alkegen’s ceramic fibre Carbowall TM addresses the challenges presented in traditional refractory through its rigid monolithic design. Its sections are engineered through vacuum forming of ceramic fibre and binders.

Figure 2. Carbowall is a pre-molded, high-density ceramic fibre system comprised of rigid, mullite-based coated panels and beams that incorporate the anchoring mechanism.

Figure 1. Downtime reduction would amount to 11 days for the Carbowall system and five days for insulating brick, both in comparison to castable.

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The parts are shaped into an engineered design based on the furnace lining needs and engineered to minimise installation time (the area of just one rigid shape is approximately equivalent to the area of 18 insulating bricks). The manufacturing process allows the density of the material to be adjusted depending on the operating conditions of the equipment, meeting the three main requirements of refractory products: mechanical resistance, refractoriness, and thermal insulation.

To minimise downtime, these individual components are designed for ease of installation and worker ergonomics for safe and efficient application. Carbowall can be installed from the outside of the furnace, eliminating the need to remove the piping or the process fluids, resulting in a reduction of downtime and improved energy savings during service.

It can also be installed at the end user location or at external sites. It is applicable to oil heater reformers and pyrolysis furnaces, in both new unit installation and during any planned maintenance.

Typical application of preformed shapes in the convection section

To remove the old lining and install the new Carbowall system, only the metal plates that form the side casing of the convection section are removed, exposing the old lining from the outside. Structural supports and beams are not affected during this process and the process tubes remain intact. Once lining removal and clean-up is completed, the pre-molded high-density ceramic fibre beams are installed. The beams are used to support the rigid insulating panels.

Carbowall panels are supplied with corbels designed into the shapes, following the design of the furnace. The arrangement of ceramic fibre panels can be installed in a horizontal or vertical manner, depending on access for the project. The design geometry of the panels is engineered to ensure that they are fully supported by each other and locked together to prevent any potential for hot gas bypass.

Installing the ceramic fibre backup blankets

To ensure the integrity of the insulation in this system and provide lighter insulation, a ceramic fibre blanket is applied to the cold face of the panels. The blanket is positioned between the face of the panel and the external metal sheeting, so that, when

Figure 3. The actual measurements taken from the refinery show the increased energy efficiency of the equipment, including the reduction in CO2 emissions.

Figure 4. Cold face temperatures are lower for Carbowall, meaning they are excellent at minimising heat transfer. This property helps to maintain lower external temperatures and reduce energy loss in high-temperature environments.

Figure 5. Carbowall is designed to provide maximum thermal insulation and reduce heat loss, helping to improve the efficiency of the furnace and reduce energy consumption.

Carbon reduction: what does 1 t of CO2 look like?

In the application outlined in this article, carbon emissions were estimated at 158 892 kg/d. After installing Carbowall, CO2 levels fell by 12 649 tpd. If carbon was reduced by 12 tpd for 365 days, that would equal 4380 t of CO2 reduction in a single year.

compressed, it presses and seals the panels against the support beams, creating a thermal barrier and ensuring the integrity of the system.

After placing the blankets, the external metal sheeting is replaced on the structural beams by welding, or, if desired, bolted-on to allow easy access for pipe maintenance.

Easy installation

Carbowall is suitable for external installation. Assembling furnace insulation from the outside not only accelerates project timelines (Figure 1) but can result in positive changes including a significant reduction in the duration the furnaces are offline and improved working conditions through the elimination of work in confined spaces.

Installation time

Based on the estimated installation comparison of the characteristics of each system (Table 1), the Carbowall system exhibited lower installation time, weight, and overall cost in comparison to conventional systems.

Reductions in heat loss and CO2

Minimising heat loss contributes to improved furnace efficiency and a substantial reduction in carbon dioxide (CO 2 ) emissions. Carbowall measured cold face temperatures that were 51% lower than insulating castables and 38% lower than insulating brick. This resulted in a 4.09% overall increase in efficiency.

* Carbowall is supplied with built-in anchoring

Figure 6. To withstand the severity of the furnace environment, Carbowall panels receive a mullite-based coating. This coating enables the panels to resist the high gas velocity inherent in this area, and withstand abrasion caused by soot or the velocity of steam injected to clean the pipes.

Carbowall presented a heat loss reduction of 71% compared to insulating castables and 57% compared to insulating brick. Overall, CO 2 emissions fell by 12 649 tpd.

Conclusion

This article has presented an innovative and efficient solution for thermally insulating the convection section of industrial furnaces. The results from the study outlined represent a significant advance in the search for more efficient, sustainable, and safer processes.

Table 1. Carbowall utilises rigid monolithic parts formed through vacuum forming of ceramic fibre and binders. The parts are shaped into an engineered design based on the furnace lining needs and engineered to minimise installation time

Corrosion under insulation is a common issue that can lead to significant problems at industrial facilities. Fred Addington, Pinnacle, USA, explains how it can be tackled.

In industrial facilities where piping, vessels, and equipment are exposed to harsh environments, corrosion is an ever-present threat. Corrosion under insulation (CUI) is particularly challenging because it often remains undetected until significant damage has occurred and is a threat to the mechanical integrity of a

facility’s assets. CUI is such a common issue that the American Petroleum Institute (API) has created a recommended practice, API RP 583, for guidance on managing it.

However, CUI is preventable if insulation is installed and maintained properly. This article will outline the intricacies of CUI, common issues

associated with it, and opportunities to prevent it in industrial settings.

Common issues seen with CUI at industrial facilities

Insulation degradation

One of the primary concerns with CUI is the degradation of insulation materials. Moisture infiltration compromises the integrity of the insulation, rendering it less effective in providing thermal protection. This leads to increased energy consumption and decreased process efficiency. This is common in situations where insulation is installed in conjunction with heat tracing on an asset. Degradation does not just affect the insulation itself, but can also include the sealants, coatings, and metal casings that protect the insulation and asset from outside exposure.

Accelerated corrosion

CUI significantly accelerates the rate of corrosion compared to that of uninsulated piping. The trapped moisture creates a corrosive environment by forming an electrolyte between the metal surface and the insulation material. This electrolyte, coupled with oxygen availability, promotes rapid corrosion. Corrosion products, such as rust, can accumulate and further contribute to the deterioration of the metal substrate.

Equipment failure

CUI can result in severe structural damage and ultimately lead to equipment failure. As corrosion progresses, it

weakens the metal, compromising its structural integrity. This can have serious consequences, including leaks, spills, and potentially catastrophic failures, depending on the equipment involved. Such failures can result in safety hazards, production disruptions, and costly repairs.

Inspection challenges

Detecting and monitoring CUI presents a significant challenge for facility operators. The insulation layer conceals the underlying corrosion, making visual inspection ineffective, but visual inspection can still be used to identify potential damage areas or degrading caulk/sealant. Traditional inspection methods such as ultrasonic thickness measurement or radiography may not provide accurate results due to the presence of insulation. Consequently, identifying and assessing the extent of CUI often requires more advanced inspection techniques, such as specialised sensors or thermal imaging.

Maintenance and repair costs

Addressing CUI-related issues necessitates regular inspection, maintenance, and repair activities. Detecting and remediating CUI at an advanced stage can be considerably more expensive and time-consuming than preventive measures. The costs associated with shutting down equipment, removing and replacing insulation, and repairing or replacing corroded components can be substantial. Additionally, indirect costs arising from production losses and environmental impacts can further escalate the financial burden.

Accidental damage

There are many situations where insulation can be damaged by various types of personnel interaction. A common issue occurs when a thickness inspection is required, but insulation is not fully removed, leading to an inspection port being cut. If that port is not plugged and sealed properly, moisture can make its way to the asset, initiating degradation.

Case study

A chemical facility in south Texas, US, capable of producing over 11 million lb/d of ethylene, embarked on a Retro Positive Material Identification (RPMI) project in a strategic partnership with Pinnacle. The initial field work evaluation scope was limited to piping operating below 750°F for safety and PMI test instrumentation exposure purposes. While stripping and testing a piping system susceptible to high temperature hydrogen attack (HTHA) damage, the RPMI team encountered CUI damage in addition to significant insulation damage. The facility operates on a time-based approach (TBA) and during previous damage mechanism assignments, these line numbers had not been identified as susceptible to the CUI damage mechanism based on the assigned temperature and environment.

The damage to the piping was so significant that the RPMI inspection could not be completed without additional preparation, and the findings were reported back to the facility. Through an investigation completed by the site’s

Figure 1. Nozzle with visual damage identified as a result of insulation stripping for RPMI.

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reliability team, it was determined that the system was considered a cyclical service and operated at different temperatures for significant periods of time. When damage mechanisms were originally assigned, they were done so based on the operating conditions associated with a potential HTHA (high temperature) failure due to the associated consequence of failure (COF). However, the site is situated in a coastal region that is highly susceptible to CUI when operating at a lower temperature range, and by only focusing on one set of operating conditions, the site ignored the potential additional damage mechanisms, putting it at unknown risk. This example highlights the importance and risks associated with proper data collection and reliability modelling. If the pipe had failed and released the HTHA service to the atmosphere, there is a high chance that it would have auto-ignited and the consequences would have been catastrophic, leading to tens of millions of dollars in damage. This unit also provides feed to another local facility and would have impacted their operations as well.

Preventing and managing CUI

Preventing CUI requires a proactive approach that involves multiple strategies aimed at mitigating moisture ingress and creating a protective barrier for the underlying metal surfaces. The following are some effective measures to prevent CUI from occurring.

Selection of appropriate insulation materials

Choosing insulation materials with low water absorption and permeability characteristics can reduce the risk of CUI. Insulation materials such as closed-cell foams, vapour barriers, or hydrophobic coatings can help reduce moisture intrusion.

Proper design and installation

Ensure that insulation is installed correctly, paying attention to proper weatherproofing measures. Use appropriate sealants, gaskets, and vapour retarders to minimise the potential for moisture penetration.

Insulation maintenance

Regularly inspect insulation for any signs of damage or deterioration. Replace damaged or compromised insulation promptly to prevent moisture from reaching the metal substrate.

Moisture control

Implement measures to control moisture ingress. This includes managing condensation by insulating cold surfaces to prevent dew point temperature variations and addressing potential sources of leaks or water intrusion in the facility.

Protective coatings

Consider applying corrosion inhibitors or protective coatings to the metal surfaces before installing insulation. These coatings provide an additional layer of protection against moisture and corrosive agents. It is important to

note that these coatings have a shelf life and should be inspected and reapplied as needed.

Quality control

Ensure that insulation installation and maintenance activities adhere to industry standards and best practices. Conduct regular quality control checks to verify that insulation systems are properly installed and functioning as intended.

Advanced inspection techniques

Utilise advanced inspection techniques designed specifically for CUI detection. These can include non-destructive testing methods like specialised sensors, thermal imaging, or guided wave ultrasonics that can identify hidden corrosion beneath the insulation.

Education and training

Provide comprehensive training to facility operators, maintenance personnel, and inspectors regarding the risks associated with CUI and the importance of preventive measures. Educating staff on early warning signs, proper maintenance practices, and inspection techniques can help identify and address potential CUI issues in a timely manner. It is important to educate on how CUI occurs and emphasise how easily insulation and other weather barriers, such as sealants, can be damaged or lead to CUI if not installed or taken care of properly.

Risk assessment and management

Conduct regular risk assessments to identify areas prone to CUI and prioritise preventive measures accordingly. Focus on high-risk areas such as equipment operating at elevated temperatures that are still below boiling point, locations with frequent insulation maintenance, or regions with high humidity.

Continuous monitoring

Implement a system for continuous monitoring of CUI-prone areas, such as temperature and moisture sensors, to detect any deviations from normal conditions. This allows for early detection of potential CUI risks and enables prompt action.

Material selection

One option to eliminate unnecessary CUI risks is to replace or install caging in lieu of insulation as personnel protection.

Conclusion

Ultimately, CUI only occurs when insulation and inhibitors have not been installed or maintained properly. CUI programmes can be time-consuming and expensive, and by adopting a comprehensive approach that includes proper insulation selection, installation, maintenance, and proactive monitoring, industrial facilities can significantly reduce the occurrence of CUI and safeguard their equipment and infrastructure from the detrimental effects of corrosion.

Ashraf Abufaris, BASF Middle East Chemicals LLC and Blake Morell, BASF Corp., USA, consider how use of a highly H2S selective solvent can help to optimise capital investment and reduce operating costs.

Selective removal of hydrogen sulfide (H2S) has become an important topic over the last two decades. Selective designs are tailored either on maximum or controlled H2S selectivity depending on the application. This article will focus on highly selective designs in low-pressure tail gas treating units (TGTUs) using BASF’s OASE® yellow technology in comparison to generic based methyldiethanolamine (MDEA) solutions.

The reaction equilibrium prevents the complete conversion of the sulfur species in the feed gas to elemental sulfur in

sulfur recovery units (SRU or Claus section) to elemental sulfur. Typically, an SRU with two to three Claus reactors is only able to achieve 93 - 98% sulfur recovery efficiency. However, higher recoveries of 99.8% and above are achievable if the remaining sulfur compounds in the SRU tail gas are hydrogenated to H2S, which is then consequently removed in a selective amine unit (TGTU).

The selection of the proper amine technology for the TGTU is essential to make these projects economically and environmentally viable. Use of a highly H2S selective solvent, such as OASE yellow, can provide benefits by optimising the capital investment or reducing the operating cost.

During the design phase there are various parameters to influence the H2S selectivity (and consequently the CO2 slip) in TGTUs, such as: absorber height, amine circulation rate and absorber internals in the mass transfer zone. However, one of the most effective levers is the amine temperature itself. The H2S selectivity of generic solvents rapidly deteriorates once the amine temperature exceeds 45°C. A key benefit of the OASE yellow selective solvent is a maintained H2S selectivity, even in high ambient temperature environments and subsequent high lean amine temperatures of up to 50°C. This avoids installing/operating costly chillers for solvent cooling and makes the design reliable, robust, and flexible for various operational scenarios.

This article will discuss the key parameters for these selective designs followed by real operational start-up data from OASE yellow solvent swaps.

Design options to influence H2S selectivity

There are a number of factors that influence H2S removal in the presence of CO2. Adjusting these parameters plays a critical role in unit optimisation throughout the design, commissioning, start-up, and operation phases.

Type of amine

Historically, MDEA has been widely used in H2S selective applications in the industry. However, recent stricter SO2 emission targets that meet the World Bank standard of 150 mg/Nm3 often require additional chemistry to further boost the performance of MDEA and other amines to achieve tight treated gas H2S specifications. Besides the performance related characteristics, properties such as volatility, stability, acid gas loading capacity and commercial aspects are important selection criteria.

Lean amine temperature

Selective treatment with amine-based solvents generally takes advantage of the rapid reaction of H2S compared to the kinetically hindered reaction of CO2: CO2 first must react with water to form carbonic acid before the solvent can absorb the CO2. Thus, tertiary amines such as MDEA are often used for selective applications as they are not able to form carbamates (the only fast reaction with CO2).

The following reactions of tertiary amines take place in aqueous solutions:

Reaction of water and amine (fast):

R1R2R3N + H2O ⇄ R1R2R3NH+ + OHˉ

2 H2O ⇄ H3O+ + OHˉ

H2S reaction (fast):

H2S + H2O ⇄ HSˉ + H3O+

CO2 reactions (overall reaction: slow):

CO2 + 2H2O ⇄ HCO3ˉ + H3O+ (slow)

HCO3ˉ + OHˉ ⇄ H2O + CO32- (fast)

In this reaction system, the CO2 co-absorption and, therefore, H2S selectivity is heavily influenced by reaction conditions. This means higher pressure and temperature, as well as a higher CO2/H2S ratio in the feed gas, favours the CO2 co-absorption and lowers the H2S selectivity. Especially at lean amine temperatures above 50°C, which are typical for the Middle East region, the CO2 reaction accelerates and strongly competes with the H2S reaction. As a result, a cooling system/chiller is often part of the design in these climates to achieve H2S selectivity with a MDEA/acidified MDEA solution.

Mass transfer

Besides lean amine temperature and feed gas pressure (partial pressure), the absorber internals, the column height and the liquid/gas (solvent/feed gas) ratio all strongly affect the total mass transfer of the individual components from the gas into the liquid phase. While the mass transfer of H2S is predominantly gas phase driven, the CO2 reaction kinetics are mostly related to resistance in the liquid phase. The absorber height and mass transfer surface determine vapour/liquid contact, which directly impacts the reaction selectivity. The liquid/gas (solvent/feed gas) ratio itself not only impacts the mass transfer, but also influences the temperature profile within the absorber impacting reaction kinetics.

Selecting the right solvent

While designing a TGTU, one of the most important decisions is selecting the type of amine.

A typical gas sweetening amine unit with primary or secondary amines such as MEA or DEA would require a very high amine circulation rate, as these solvents absorb both H2S and CO2 almost

Figure 1. Selective solvent performance comparison.

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without any selectivity towards H2S. For this reason, a more H2S selective amine must be considered to reduce solvent circulation/inventory, the amount of CO2 recycled to the SRU, and reboiler duty.

Figure 1 illustrates a comparison between generic amines such as MDEA and acidified MDEA against proprietary amines offered by BASF Gas Treating (OASE yellow and FLEXSORBTM SE PLUS).

OASE yellow was developed to enable the selective removal of H2S in both high (natural gas) and low-pressure applications (acid gas enrichment or tail gas treatment). The proprietary

combination of several amines and a promoter system provides higher acid gas capture capacity and enables lower achievable treated gas H2S specifications.

FLEXSORB SE Plus is a proprietary gas treating agent that was developed by ExxonMobil Research and Engineering Co., specifically for selective H2S removal. The FLEXSORB technology is well known in the industry for its high performance, even at high ambient temperatures. The selectivity advantage allows the unit to achieve H2S removal at lower solvent circulation rates, resulting in lower energy consumption compared to conventional processes. The reliable and simple to operate process is characterised by low corrosion and lower foaming compared to conventional gas treating solvents.

Both OASE yellow and FLEXSORB SE PLUS can achieve high treated gas purity to meet the stricter SO2 emission targets of the World Bank Standard. In addition, both solvents can maintain H2S selectivity at high lean amine temperatures (+50°C), which makes designs without an expensive chiller unit possible. On the contrary, generic amines would require high energy demand and lower lean amine temperature to achieve the required H2S selectivity which increases the unit’s costs significantly.

Case study 1

In this case study, a refinery located in Germany operated a TGTU with generic MDEA solvent which often limited the refinery operations. The feed gas to this unit includes 1.2 mol% H2S and 30 mol% CO2. The constraint encountered at the TGTU is the environmental permit limit for SO2 emissions from the thermal oxidiser. This environmental constraint typically occurred in the summer months due to an increase in the lean amine temperatures in the tail gas unit. As the lean amine temperature approached 37.8°C, the amount of H2S that slipped to the thermal oxidiser increased significantly, resulting in increased SO2 emissions. To mitigate increased emissions during the summer, the overall SRU capacity needed to be limited even with the use of rented chillers.

These factors warranted a review of alternative technologies and a solvent changeover. However, the refinery already passed the turnaround period, and the operation team had a challenge to changeover the solvent while the unit operated ‘on the fly’.

As part of this evaluation, BASF was requested to analyse the possibility of utilising OASE yellow in this unit to reduce the treated gas H2S content during the summer from 90 ppmv to 35 ppmv. OASE connect, an in-house rate-based model simulator, was used to assess the possibility to meet this target without any mechanical modifications to the existing equipment.

Based on the simulation results, it was concluded that with the addition of OASE yellow enhancer system to the existing MDEA inventory, it was not only possible to meet the H2S target, but the unit could also reduce the solvent circulation rate to approximately 65% of the current operating level.

The switch increased the refinery’s annual average sulfur capacity, which allowed it to run additional sour crude. It was also no longer necessary to rent chillers to cool the lean amine, leading to considerable operating cost savings.

Figure 2 illustrates the actual performance test results collected from the unit during the 72 hour swap process. A noticeable decrease of the H2S at the outlet of the unit absorber (orange dots) was observed. The solvent circulation

Figure 2. Case study 1: OASE yellow conversion results.

Figure 3. Case study 2: OASE yellow conversion results.

Figure 4. Case study 2: optimisation.

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rate was able to be reduced at the same time, resulting in operational cost savings for the unit.

Case study 2

In this case study, a refinery located in South Korea operated a TGTU with acidified MDEA. The feed gas to this unit includes a higher H2S content compared to case study 1 with 6.8 mol% H2S and a lower CO2 content of 3.5 mol%. The objective of this study was to reduce the steam consumption while maintaining the environmental permit limit for SO2 emissions from the thermal oxidiser.

Similar to the previous unit, the changeover from acidified MDEA to OASE yellow had to be carried out during the unit operation without shutting down the process.

BASF completed a study considering the unit mechanical details and concluded that it was possible to reduce the H2S content from 150 ppmv to 25 ppmv, maintaining the current steam consumption to the unit. In turn, the steam consumption could be reduced by 35% while still meeting the unit’s environmental limits.

Figure 3 illustrates the first step of the conversion with the actual performance test results collected from the unit during the 26 hour swap process. As the OASE yellow enhancer system was added to the system, the treated gas H2S content decreased, even as the circulation rate was reduced by 25%.

In the second step, the steam consumption was reduced by 35%, allowing the H2S concentration to increase to the

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acceptable limit of 150 ppmv. This steam rate reduction resulted in an annual OPEX saving of approximately US$1 million for the unit.

Conclusion

The selective removal of H2S has become an important topic over the last 20 years. With dwindling sweet gas reserves, H2S selective gas treatment at low pressure (AGE, TGTU, or combinations of the two) has become a necessity to produce a high-quality Claus gas, enabling sulfur removal and monetisation of these gas fields.

Savings in energy and circulation rate (OPEX), as well as a reduction in equipment sizing (CAPEX) are the obvious benefits of enhanced H2S selective treatment. Many of the newest projects also require a high degree of operational flexibility combined with a robust operation in warm locations enabled by these technologies.

Capacity, operational flexibility, reliability, and the ability to achieve specifications are all considered during BASF’s technology selection process utilising the in-house simulation tool, OASE connect.

OASE yellow technology utilising the most common selective base amine, MDEA, allowed for smooth swaps from generic solutions to meet the stricter emission limits as well as optimise the unit operational costs. The technology can also be utilised in grassroots designs to achieve further savings on the capital investment of these projects, making them more economically attractive and feasible.

Airat Amerov, AMETEK Process Instruments, USA, details the importance of measuring and controlling both hydrogen and water concentrations in the catalytic reforming process.

Catalytic reforming is a chemical process used to convert petroleum refinery heavy naphtha, which has a relatively low octane value, into high-octane liquid products called reformates. Hydrogen is a by-product of the principal reactions of catalytic reforming and is a source for hydrotreating, hydrocracking, or hydro-refining processes at the refinery. The other by-products produced are relatively small amounts of methane, ethane, propane, and butane.

Produced in a catalytic reformer, hydrogen must be recycled and passed over the catalyst to reduce coke formation and extend catalyst activity time. Hydrogen recirculation is necessary to provide a reasonable hydrogen to hydrocarbons ratio, avoiding catalyst deactivation by coking. Hydrogen reacts with

coke precursors and removes them from the catalyst before they can form polycyclic aromatics, which ultimately deactivates the catalyst.

At the same time, the catalyst used in the reforming process can be deactivated by excessive water reacting with the catalyst chloride. Catalyst chloride concentration is critical to proper operation. Chloride alone takes a considerable amount of time to be removed from the catalyst, but the presence of water strips it rapidly. Water arrives at the reformer not only from the feedstock, where it is already reduced to a minimum level, but also from deliberate water injection. The precise level of water required is specified by the catalyst maker, however, typical levels correspond to approximately 10 - 30 ppmv. Once the

water level falls to about 5 ppmv, the chloride content in the catalyst results in hydrocracking, while too high a level washes chloride from the catalyst.

Therefore, it is very important to measure and to control both hydrogen and water concentrations in the catalytic reforming process to minimise catalyst replacement costs and to maintain yield from this process.

Measuring water vapour and hydrogen using tunable diode laser absorption spectroscopy (TDLAS)

Over the past years, near-infrared TDLAS has gained much attention for use in industrial applications. In comparison with already existing electrochemical sensors for hydrogen and moisture detectors, three key attributes make the TDLAS technique more attractive: specificity for the analyte, high sensitivity, and fast response.

Making this measurement with a TDLAS analyser, using one of the water-vapour absorption lines in the near-infrared range requires a means of compensating for the absorption spectrum of methane, which has overlapping with the water line.

Implementing a multivariate calibration in the TDLAS instrument makes it possible to accurately measure the water vapour concentration.

Measuring hydrogen becomes slightly more complex when using hydrogen recycle gas. Specifically, methane and ethane will contribute a small amount of background interference to the measurement, which if uncorrected, will produce a bias in the measurements.

Hydrogen is a relatively weak absorber, but a few hydrogen lines in the vicinity of 2 micrometres (mcm) can be selected for measurements. Wavelength selection for hydrogen measurements is dictated by the spectral position and intensity of the hydrogen absorption lines in the near-infrared range, the requirement of minimal spectral interference with other components of the gas stream, and by the availability of laser diodes.

Methane and ethane spectral interference can be compensated for by applying a multivariate approach to TDLAS measurements, enabling higher precision measurements of hydrogen by real-time compensation. Other hydrocarbons, such as propane and butane, do not have any significant absorption in the spectral range selected for measurements.

Hence, the simultaneous measurement of moisture and hydrogen in recycle gas was reduced to a relatively simple

multivariate analysis, with only a few species contributing to the spectral response.

Developing a dual-measurement solution

AMETEK Process Instruments provides a reliable and low-maintenance solution for this application, by adapting its proven 5100 HD TDLAS gas analyser. A schematic representation of the instrument is shown in Figure 1.

This optical set up was configured with distributed feedback (DFB) laser diodes for measurements of moisture and hydrogen content in the hydrogen recycle gas stream. DFB lasers were coupled with single mode optical fibres and gradient-index (GRIN) lenses were used as collimators of the beams.

With extractive sampling and multi-pass Herriott cells of different optical path lengths, the 5100 HD provides simultaneous measurements of moisture and hydrogen within the same hydrogen recycle process gas.

The outputs of both lasers were coupled into single-mode optical fibres, which in turn were connected to fibre-optic beam splitters. The splitters were used to divide the optical power in a 50/50 ratio for use in the sample and reference measurements, respectively.

Within the instrument, sealed reference cells are used in parallel with the sample cells to continuously control the performance of the analyser. The reference cell contains a known concentration of the analyte in a gas that is non-absorbing at the wavelength of interest, and this is used to lock the output radiation wavelength of the laser.

In contrast with the common practice of using second harmonic detection (2F), the detection/demodulation in this analyser was performed at the laser-modulation frequency (i.e., ‘1F’ detection). Using the 1F-detection scheme enabled the normalisation of the spectra, without the need for a separate measurement of the laser power. Specifically, the magnitude of the power envelope of the laser output is contained in the spectra produced by 1F demodulation. After 1F spectra were normalised, ‘2F’ spectra were calculated simply by taking the derivative of the 1F signal.

Results and discussion

Solving the multivariate problem was achieved with an inverse least squares regression (P-matrix calibration). The response variables used in the regression were the integrated values observed over three spectral bands in the 2F spectra. Specifically, a band centred at the peak in the carbon monoxide spectrum and two additional bands were used. All concentrations are cited by volume (i.e., ppm and %(V/V)), and the estimates were calculated as: Where Cj = concentration estimates for each component, aji = regression coefficients, and ri = integrated band intensities.

Examples of collected spectra are shown in Figure 2. Each of the spectra in Figure 2 covers a range of approximately 0.4 nm and is the average of 100 separate consequent scans. In this data, the peak amplitude and area of the 2F moisture and

Figure 1. Block diagram for TDLAS measurements.

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hydrogen signals were proportional to the concentration of moisture and hydrogen in the sample cells. With increasing concentrations of moisture, a peak at 1854 nm became more notable. Spectra recorded for two separate concentrations of moisture (50 and 100 ppm) and a methane spectra for concentration of 5% are shown in Figure 2A. The spectral interference of methane and water is clearly observed. This background spectrum of methane was significant in comparison with the absorbance of the moisture at these concentration levels and with 2F signal of nitrogen used as zero background gas. Hence, the spectra of the sample matrix components needed to be built into the calibration model. The regression vector that was calculated as a result of the inverse least squares regression is also shown in Figure 2A. The calculated regression vector is analyte specific and corresponds to regions where the analyte spectra are changing with concentration.

In Figure 2B, the 2F spectra recorded for hydrogen and background gas of the mix of 5% concentrations of methane and 5% concentration of ethane are presented. The hydrogen concentrations used to generate these spectra were 60 and 90%. In this data, the peak amplitude and area of the 2F hydrogen signal were proportional to the concentration of hydrogen in the sample cell. With increasing hydrogen concentration, a common peak position became more notable. Clearly from these data, a univariate approach to measuring hydrogen will fail, as each species provides a substantial amount of background interference to measuring the other. Hence, a multivariate analysis was required to provide accurate estimates of hydrogen. The regression vector for hydrogen was calculated in the same manner as that for moisture. The hydrogen regression vector is also shown in Figure 2B. The calibration procedure for the TDLAS instrument was conducted in two parts. In the first part, a multivariate calibration model for moisture measurement in hydrogen recycle gas was developed. In the second part, a multivariate calibration model for hydrogen measurements was built. Calibration of hydrogen was varied from zero to 90% in this model. All spectral data were recorded for gas samples under atmospheric pressure and a temperature of 60°C. The data shown in Figure 3 shows the responses of the instrument to a series of moisture and hydrogen challenges over the concentration range of 0 - 100 ppmv, and 60 - 90% correspondingly. The flowrate of 1 l/min was kept during this validation test. The duration for each challenge was approximately 5 - 10 minutes. Return to the background gas baseline was also tested before and after validation measurements. A methane-ethane-propane gas (5% each component) balanced hydrogen was used as zero gas for moisture measurements and methane-ethanepropane gas (5% each component) balanced nitrogen was used as zero gas for hydrogen measurements.

Table 1. Results of the moisture and hydrogen validation test

Figure 2. Measured 2F moisture (A) and hydrogen spectra (B).

Figure 3. Moisture and hydrogen readings. Response to a series of concentration challenges in the range of 0 - 100 ppmv for water (A) and 0 - 90% for hydrogen (B).

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The response time (T90) was measured to be 60 seconds for moisture measurement and 120 seconds for hydrogen measurements. It was limited by the volume of the sample cell used for hydrogen measurements and flowrate through the cells. The data acquisition rate was 2 seconds per measurement.

The results of the moisture and hydrogen validation test are summarised in Table 1. Repeatability was calculated using the standard deviation of the measurements. Accuracy was calculated as the difference between the actual analyte level and average of the readings on each selected concentration level. As shown in Figure 1, accuracy of moisture measurements was less than 1 ppmv on each tested concentration level and accuracy of hydrogen measurements was better than 1% for each tested level.

An example of the 24 hours instrumental drift is shown in Figure 4. During the drift test, nitrogen was run through the sample cell at a flow rate of 1 l/min.

No significant trends or correlations with environmental temperature or sample pressure were observed in the data. Over the 24-hour period, a mean value of 1.8 ppmv, with a standard deviation of 0.2 ppmv, was recorded for moisture channel of the analyser and mean value of 0% with standard deviation of 0.1% were recorded for hydrogen channel. The use of nitrogen instead of recycle background gases is the reason for the slight positive offset in drift readings during these tests for moisture.

Conclusion

In testing of the adapted 5100 HD, an accuracy of 2 ppmv for water vapour was demonstrated over the operating range of 0 - 100 ppmv. The measurement accuracy observed for hydrogen was 2% H2 over an operating range of 60 - 90%.

The performance of the analyser was evaluated under a variety of experimental conditions, including sample pressure and temperature, and variation of the background gas component concentration.

The response time (T90) was measured at 60 seconds for the moisture measurement and 120 seconds for hydrogen measurements. This was limited by the volume of the sample cell used for hydrogen measurements and flowrate through the cells. The data acquisition rate was 2 seconds per measurement.

The test results firmly established that TDLAS gas analysis provides a suitable dual-measurement solution for water vapour and hydrogen, delivering key measurements for refinery hydrogen recycle gas.

Figure 4. Instrumental drift for analyser calibrated for measurements of moisture and hydrogen.

Rhys Jenkins, Servomex, UK, explains why measuring water impurities in ethylene dichloride and other key hydrocarbon processing applications is crucial.

Ethylene dichloride (EDC) is a key intermediate in the polyvinyl chloride (PVC) production process, and requires accurate, reliable gas analysis to overcome process issues such as condensation and corrosion.

These measurements also help control the process to ensure efficiency, maintain product quality, and support process safety.

One of the most important and challenging measurements is for water (H2O), as its presence can increase damage from corrosion, affecting the quality of the process and the life of the plant equipment.

Therefore, alongside gas analysis, a resilient analyser that can make accurate water measurements in the liquid EDC stream is also required.

The EDC production process

To produce EDC, ethylene and chlorine are combined in a chlorination reactor. This creates a crude EDC stream which is sent to a clean-up fractionator, resulting in almost pure EDC.

Gas analysis is required throughout the process, most notably at the chlorination reactor where oxygen measurements are critical to ensure maximum process safety.

However, minimising trace amounts of water in EDC is also critical to the operation of the plant. As the thermal

cracking process produces large amounts of hydrogen chloride (HCl) and EDC, any residual water will greatly increase the corrosive nature of the process stream, causing damage to plant equipment. Therefore, the measurement of water in EDC is of critical importance.

The first point at which water measurements are required is where the pure EDC leaves the clean-up fractionator.

The EDC stream then undergoes pyrolysis to produce a combined vinyl chloride monomer (VCM) and HCl stream. Once again, it is crucial to monitor the water concentration to minimise corrosion before the stream is quenched and sent to the splitter.

The VCM is then sent for storage or immediate use in PVC manufacture, while the HCl is recycled back into the EDC process.

Other key applications for water measurements

While measuring water in EDC is a key process requirement, water monitoring is of great importance in other applications within the hydrocarbon processing sector.

For example, VCM is created from the reaction of hydrogen and chlorine (Cl2) to form hydrogen chloride (HCl), which in turn is combined with acetylene

to produce VCM. In this instance, it is important to monitor moisture in the Cl2 stream to avoid compressor corrosion.

Challenging process conditions – such as condensation and corrosion – can affect the monitoring equipment used in this process. Analytical systems must not only deliver reliable measurements for process control and safety, but they have to be able to do so without being impaired by the conditions themselves.

Infrared sensing for gas and liquid analysis

Infrared (IR) sensing is a flexible measurement technology based on the unique light-absorbing properties of some gases. It delivers a non-contact, real-time detection of a selected gas’ concentration in a mixture and is widely used in a range of industrial applications.

IR sensors focus an IR light source through a sample cell holding a continuously flowing sample of the gas mixture, and onto a detector after wavelength selection. The property of some gases to absorb unique light wavelengths can then be used to detect the concentration of a selected gas in a mixture.

For water measurements, a single beam dual wave (SBDW) IR sensor technology is commonly used. This often uses a pair of optical filters mounted on a rotating disc, which pass through a beam of IR light alternately. One filter (the measure filter) is chosen to pass light only at a wavelength that the gas to be measured absorbs, while the other filter (the reference filter) passes light at a wavelength unaffected by the gas to be measured, and the background gases that are also in the sample. The difference in absorbance is measured by the detector and provides a direct output of the gas concentration.

The technology works in exactly the same way for liquid samples, so there is no need for adaptations to be made to achieve an accurate measurement.

Compared to a gas sample, the key difference is that in a liquid sample the molecules are significantly closer together, so the required measurement path length is much smaller. This creates a challenge for accuracy as the mechanical tolerances and variations – which have a

minimal impact over longer path lengths – are more significant over a shorter measurement.

Analysers that are used for liquid measurements must, therefore, be designed in such a way as to negate these effects and deliver a stable measurement, even with variation in sample or ambient temperature.

A solution for liquid analysis of water in hydrocarbon processing applications

Servomex’s SERVOTOUGH SpectraExact 2500 analyser is designed to achieve trace water measurements in hazardous conditions. For water, it uses a single beam, dual wavelength non-dispersive infrared (NDIR) measurement technique which offers high performance, increased measurement sensitivity, and a high degree of stability.

This technique is virtually unaffected by contamination on the sample cell windows, since it influences both measure and reference wavelengths equally. A 50% loss of signal due to obscuration of the sample windows produces no more than a 3% FSD error in reading. Maintenance requirements are low, and the cells can be easily changed or cleaned.

The analyser has a rugged construction and is certified for use in hazardous areas and for the measurement of flammable samples. It has UKCA, CE, ATEX, UKEx, IECEx, and North American hazardous area approvals.

It uses special ultranarrow band pass measurement and reference IR filters, and a measurement cell designed to handle both gaseous and liquid samples.

Typically, measurement ranges down to 0 - 50 ppm H2O in EDC are achieved using quartz windows. The instrument is calibrated using the Karl-Fischer titration method, a standard laboratory technique for trace water determination.

Servomex also offers surrogate calibration using test gases which negates the requirement for laboratory analysis when the sample is particularly difficult to keep stable or safe outside of the process environment.

A special requirement in trace water measurement is the use of sample temperature compensation. Without compensation, the cell temperature must be maintained within ±0.5°C, as sample temperature fluctuations will produce errors in the measurements.

Digital communications enable the SpectraExact 2500 to be operated remotely and safely, with Modbus implemented through MODBUS TCP.

Conclusion

By monitoring liquid water in process gas streams, plant operators can ensure greater product quality while minimising the effects of corrosive damage caused by the water reacting with the other components present.

In the widely used EDC production process, this is essential to prevent damage to plant equipment, particularly where HCl is also present, creating a corrosive environment.

NDIR sensing is an effective and stable method of measuring liquid water concentrations within process streams, delivering the accuracy and reliability needed to achieve optimum process performance.

Figure 1. The measurement of water in EDC is critically important as the presence of water can increase damage from corrosion, affecting the quality of the process and the life of the plant equipment.

Understanding the challenges facing gas grab sampling technicians and overcoming them is essential in building an effective sampling system. Matt Dixon, Swagelok, USA, explains best practices.

Regularly testing industry fluids reduces chemical processing costs and maintains high end-product quality. In most facilities, technicians use grab sampling techniques to pull representative samples of the fluids for laboratory analysis. Also known as spot sampling, field sampling, or simply sampling, the process validates that appropriate conditions exist in the system and verifies that the end product meets internal or customer-based specifications. Grab sampling also provides validation that online analysers – an increasingly popular way to obtain real-time insights into a process – are functioning properly.

Though liquid grab sampling can be straightforward, sampling of gases is more complex. System designers must account for the challenges they may face during the process, so the results accurately reflect true process conditions (Figure 1). Understanding these challenges and knowing how to overcome them is critical to building a successful gas grab sampling process.

Sampling best practices

Before technicians collect gases and volatile liquids, they must have plans in place to keep them at ideal temperatures and pressures to optimise the accuracy of the tests. For example, if a liquid or gas changes phases, it can negatively influence the test results. Therefore, the following protocols must be kept in mind:

n The sample must represent the process. Use probes to draw samples from the middle of the process pipe and avoid phase changes during sample transportation.

n The sample must be timely. Minimise transport time from the sample tap to the laboratory to help ensure process conditions are accurately represented.

n The sample must be pure. Avoid dead legs upstream of the sample container and allow for adequate purging and flushing of the sampling system to minimise the potential for contamination.

n Sampling must be safe. Grab sampling inherently involves a human operator interacting with process fluids, which can be harmful if direct contact occurs. For this reason, following best practices and using well-designed sampling systems are essential not just to sample accuracy, but also to the operator’s safety (Figure 2).

Choosing the right cylinder

Instead of using less-expensive, unpressurised sample bottles for gases and volatile liquids, technicians should employ sample cylinders, which can help prevent phase changes that could lead to inaccurate results. Additionally, sample cylinders can help protect technicians and the environment from the accidental release of fumes or emissions of toxic gases.

Frequently, sample cylinders contain seamless tubing for consistent wall thickness, size, and capacity, but there are some variations depending on the application. A reliable cylinder supplier can provide guidance on which type will work best.

Some items to consider when choosing a cylinder include:

n Easily operable quick connects, allowing for efficient and safe connecting and disconnecting from the sampling point.

n A smooth internal neck transition, which can help eliminate trapped fluid and makes cylinders easy to clean and reuse.

n Overpressure protection, which can provide higher levels of operator safety. Rupture discs and relief valves are available in a tee or may be integral to the cylinder’s main valve.

n Proper material composition and finish, as special alloys or materials may be required depending upon the gas or volatile liquid being sampled.

n Incorporated bypass lines, which can be beneficial for purging toxic sample remnants and enhancing technician safety. A bypass line allows the purge fluid to flow through the quick connects, ensuring that if spillage occurs when the cylinder is disconnected, the spill is composed of purge fluid rather than potentially toxic sample.

n Durable design and construction, since sample cylinders must often be transported considerable distances for laboratory analysis.

Filling a cylinder correctly

For most applications, technicians should orient cylinders vertically during filling, meaning volatile liquids should fill sample cylinders from bottom to top. This allows excess gas to escape while an outage tube ensures some gas remains, forming an important vapour space (Figure 3). This is crucial to prevent cylinders from rupturing during a change in temperature. Conversely, gases should fill cylinders from top to bottom to flush any collected

Figure 1. Though industrial fluid grab sampling is frequently straightforward, gas grab sampling includes challenges that system designers must address.

Figure 2. During grab sampling, a human operator will typically draw process fluids at elevated temperatures for transport to a laboratory, making safety paramount to the process.

condensation from the line through the bottom of the cylinder.

Keeping sample cylinders in working order

To ensure proper functioning, industrial equipment must be maintained in working order. The same rules apply to sample cylinders, which may sustain damage during regular

operations. Such damage can cause the sample cylinders to malfunction and put technicians at risk. Additionally, it may affect the outcome of the tests. Countering this wear and tear with proactive sample cylinder maintenance relieves such concerns, especially if the operation is sampling-centric. Minimally, maintenance personnel should inspect the cylinders once a year and do a pressure test at the same time. Every five years, the cylinders should be recertified.

Between annual inspections, operators should watch for any of the following common issues:

n Leakage across key components, including valves and quick connects.

n Corrosion resulting from compatibility issues with the sample.

n Internal surface conditions and absorption.

n Improperly installed components.

Maintain a standard sampling process

The more complex an industrial fluid system is, the more sampling points are required. Written protocols can standardise sampling processes, and installing consistent grab sampling panels at each point can reduce errors. Consistency can make it easier for technicians to draw samples the same way at every point, especially when technicians have varying skill levels.

System engineers can promote such consistency by specifying the grab sampling panels in their drawings. Once organisations decide on which grab sampling panels to specify, they can maintain consistency beyond one plant, making it easier for global enterprises to build the most effective and efficient sampling systems possible. It also helps prevent regional differences from skewing the testing procedures and ensures everyone is working from the same sampling protocols across all locations.

Use well designed sampling panels

The engineering of grab sampling systems today makes sampling safer, simpler, and more repeatable than ever before. Plants that are using traditional grab sampling processes may want to consider what an updated sampling system could bring to their operations, including improved efficiency and accuracy.

For example, modern grab sampling panels are designed to make flushing and purging the lines easier, especially when those lines extend over long distances. They also prevent purged gases from returning to the system, where the gases could interfere with the functioning of the process fluid. While older systems may not have safeguards that keep purge gases in the sampling system, up-to-date systems do, making them a valuable investment for industrial facilities with high-volume sampling needs.

New sampling panels also better account for the needs of the operator. Modern systems involve geared valve assemblies, which ensure the valves used in getting samples, venting, flushing, and purging operate in the proper sequence. They minimise the possibility of human error by preventing valves from being activated out of the proper sequence.

Figure 3. When liquid samples are being captured, outage tubes prevent cylinders from overflowing.

Figure 4. Properly designed grab sampling systems for gas sampling should maintain proper cylinder orientation and allow for top-down sample collection.

Downstream’s

world is moving. Our customers are moving in terms what their expectations we don’t act now, if we start making changes to industry, we’re going to ourselves in a situation we no longer have an industry that’s going to be supported by our customers. Romain, SVP, General Counsel &

Downstream generated $613 billion of operating cashflow between 2021 and 2023. Yet CAPEX OPEX are normalizing at new lows, and supply chain issues and workforce shortages further hindering ROI. Despite the return cashflow, winning budget and delivering value creation is proving to be more challenging ever before.

To secure the budget that remains and produce reliable value creation, downstream decision makers must prioritize the most competitive work that also delivers on decarbonization goals, master the art of predictable cost control to ensure reliable ROI, become highly effective in data driven decision making to maximize asset utilization, meet the workforce crisis head to resource the needs of today’s downstream industry.

our industry, we’re going to find ourselves in a situation where we no longer have an industry that’s going to be

supported

by our customers.

Secretary, NOVA Chemicals

- Byron Romain, SVP, General Counsel & Corporate Secretary, NOVA Chemicals

To secure the budget that remains and produce reliable value creation, downstream decision must prioritize the most competitive work delivers on decarbonization goals, master predictable cost control to ensure reliable become highly effective in data driven decision making to maximize asset utilization, meet workforce crisis head to resource the needs downstream industry.

In our action-packed exhibition 3,500+ budget gatekeepers from across reliability, maintenance, turnarounds, capital projects, digitalization and decarbonization will explore 160 booths, expo tours, product demos, workforce development opportunities and much more. Attend FOR FREE to meet the innovators behind the latest solutions, tools, equipment and components to meet all your procurement needs and deadlines in 2024 and beyond.

investment insight

2024 keynote speakers revealing exclusive downstream investment insight

2024 keynote speakers

Venki Chandrashekar VP Research and Technology Chevron Phillips Chemical

Luiziana Ribeiro

Rebecca Rosas VP Strategic Planning Texmark Chemicals

Suresh Padmanabhan CTO, Polymers Indorama Ventrues

Katie Ellet President, Hydrogen Energy and Mobility Air Liquide

Suresh CTO, Indorama

Minimising human error

No matter how well trained a technician is, there is always the possibility that accidents can happen during grab sampling. Those mistakes can throw off the results of the testing and make it more difficult for the facility

individual technician to improperly draw the sample. The same can be said for a panel designed specifically for volatile liquid sampling.

Automation

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Brian Hantz, Qingyu Wang and Brian Pettinato, Ebara Elliott Energy, consider API acceptance criteria for the high-speed balancing of turbomachinery rotors.

During planned or unplanned maintenance, turbomachinery rotors are typically balanced at low speed before reinstallation. However, rotor repairs or replacement of rotor parts can cause changes to the rotor dynamics that are not detected during low-speed balance. At operating speed, dynamic unbalances can cause excessive rotor vibration. High-speed balancing can minimise rotor vibration throughout the entire speed range and relieve residual stresses introduced during the repair process. Operation in a high-speed balance facility can also be used to verify the unbalance response analysis, similar to a mechanical test.

Acceptance criteria for high-speed (i.e., at-speed or operating speed) balancing of turbomachinery rotors, as specified in API standards, are based on either pedestal velocity or shaft displacement.

During testing, rotor response is measured during acceleration to maximum speed and deceleration to minimum speed. Values are plotted on the same coordinates as for the rotor response analysis. The plot of shaft vibration and phase angle of unbalance vs shaft speed is called a Bode plot. Bode plots indicate the location of critical speeds, the change of shaft vibration with speed, and the phase angle of unbalance at any speed.

API balancing acceptance criteria

Table 1 summarises the high-speed balancing criteria from API standards. Abbreviations are as follows:

n API: maximum allowable low-speed residual unbalance specified as:

§ SI units: U = 6350 W/N (1)

§ USCS units: U = 4 W/N (2)

Where:

U = the residual unbalance measured in units of mass and distance (g-mm [oz-in]).

W = the bearing static load in kgf (lbf).

N = the maximum continuous speed in rpm.

n D1: the maximum allowable shaft vibration (1x filtered and runout compensated) shall not exceed 25.4 µm peak-to-peak at any response or 12.7 µm peak-to-peak over operating speed range for probes near the bearings.

n MA: mutually agreed.

n OEM: manufacturer’s standard balancing procedure.

n V1: for all speeds at or less than 3000 rpm, the pedestal vibration shall not exceed 2.5 mm/s root mean square (RMS).

For speeds above 3000 rpm, the pedestal vibration shall not exceed the calculated value of (7400/N) mm/s or 1 mm/s RMS, whichever is the greater, where N is the maximum continuous speed in rpm. The criterion applies to the major axis velocity.

n V2: velocity calculated such that the maximum allowable unbalance force at any journal at maximum continuous speed shall not exceed 10% of the static loading of that journal.

n V3: the acceptance criterion, only used in API 616, 5th edition, is a combination of residual unbalance and pedestal vibration.

In current low-speed balancing standards, Equation 1 (g-mm) or Equation 2 (oz-in) are predominant. ISO standards use Grade, which limits the velocity of the centre of gravity (cg) of the rotor, and they are essentially the same as the API standards. The limit of the unbalance amount (or eccentricity of cg) assumes that the rotor can be simplified as a single mass.

For high-speed balancing, limiting the unbalance amount cannot be used directly since the rotor cannot be simplified as a single mass. An alternative, the V2 method, limits the force induced by the unbalance by 10% of the static weight. The V1 method for high-speed balancing is only related to the operating speed, and may be significantly different as compared to the V2 method.

Figure 1 illustrates the relationship between V1 and V2 based on data from 723 Ebara Elliott Energy shop orders where the red line is the V1 method, and all the dots are calculated based on the V2 method (0.2 ‘g’, i.e. 10% static load per pedestal) using maximum continuous speed, rotor weight and pedestal stiffness. The stiffness values for the DH4 and DH7 pedestals were provided by the vendor: 560 N/µm for DH4 and 1334 N/µm for DH7.

Although both velocity and displacement measurements are available in balancing facilities, the velocity measurement is usually used for balancing and balancing criteria because of the relative stable situation: the velocimeters are built-in within the pedestals so the quality of measurement stays the same regardless the rotor being balanced. The eddy-current probes might be shifted depending on the rotor and bearing combination. Sometimes the probes might not even be at a burnished area.

If the probe location at the balancing facility is different from the actual machine location due to the

Table 1. API balancing criteria summary

Figure 1. Maximum continuous speed vs allowable velocity (shop order data).

bearing housing configuration, a multiplier can be used to adjust the acceptance criteria as suggested in ISO 11342, Section 8.2.5. The value of the multiplier can be derived through comparison of the vibration amplitudes at the two locations by performing rotordynamic analysis.

Pedestal dynamics

A pedestal model is generally needed for comparing the measured unbalance response to the predicted response. There are different ways to characterise pedestal dynamics. A simple way is to use mass and stiffness. Usually the original pedestal manufacturer (vendor) provides the values, and these values are used in the balancing criteria and rotordynamic analysis. Another way is to use frequency response functions (FRFs). Since it appears that using the pedestal FRFs would improve the rotordynamic predictions, Ebara Elliott Energy initiated a project to acquire accurate FRFs for the pedestals in the company’s balancing facility.

To obtain improved pedestal transfer functions, the company contracted with a consultant to perform modal tests. However, after repeating the tests with Ebara Elliott Energy equipment, the pedestal responses did not agree with expectations.

To determine the root cause of the discrepancies in the FRFs, the company performed a series of tests by moving pedestals, testing the rails, lifting and dropping the pedestals and retesting in the same location, adjusting pedestal bed bolt torque, and adjusting bearing cap bolt torque.

While there may be other contributing factors for inconsistent measurements, results indicated that the most important parameter for a consistent result is the torque of the bed bolts. Based on these results, the company conducted further tests and balancing using a pneumatic torque wrench with a bed bolt torque of 600 ft-lb (813 N-m) for all pedestals.

Test models included the single degree of freedom (SDOF) curve-fit model, the multiple degree of freedom (MDOF) curve-fit model, the vendor model, and the plug (added mass) model, where a known mass is added to the pedestal during measurement to characterise the dynamics.

An example plot showing the amplitude of the measured FRFs is provided in Figure 2. An example plot showing the measured FRFs and the identified models is provided in Figure 3.

From all the measured FRFs, the following observations can be made:

n The dynamics of different pedestals are largely different.

n The dynamics of the horizontal and vertical directions are different both in terms of peak locations and magnitude.

n The cross-coupling dynamics are at least a magnitude smaller than the principal dynamics in this instance.

For the models, the following observations can be made:

n The SDOF model, the vendor model, and the plug model are relatively close to each other.

n Different models usually have closer values in the Y (vertical) directions (2 - 27% from the vendor model stiffness). The discrepancies in the X (horizontal) direction are usually larger (14 - 88% from the vendor model stiffness).

Unbalance verification

After obtaining more accurate pedestal transfer functions as described above, Ebara Elliott Energy performed a rotordynamic analysis of an Elliott® 46MB rotor using the different types of pedestal test models. The rotor was balanced in the company’s balancing facility, and residual unbalance subtraction was used to perform the unbalance verification. The unbalance verification tests were performed with DH7 pedestals (stiffening on). The rotor was later assembled into the compressor and passed all tests on the test floor before being shipped to the field where it is running successfully.

The rotor, as shown in Figure 4, was approximately 1650 kg with 6 x 3 in. bearings. The company used standard bearing models (measured bearing clearances and oil inlet temperatures were used, but the oil lift grooves were not considered). The company analysed the system using different pedestal models

Figure 2. Measured FRFs for DH7 – pedestal 1 –stiffening off.

Figure 3. Measured vs identified models for DH7 – pedestal 1 –stiffening off - XX.

and included the mass of the bearing and bearing adapter in the analysis.

Results show that there are no significant differences in unbalance response between different pedestal models. Additionally, all models predict higher first critical speed than the measured value (~200 - 300 rpm higher, 7 - 20% above the measured first critical speed), and lower than the rigid support (~100 rpm lower) (Figure 5). The fact that there are no significant differences in unbalance response between the different

pedestal models is to be expected since the stiffness of the pedestals from all models is more than 3.5 times the maximum bearing stiffness for DH7 stiff in both X and Y directions. API 617 considers the supports to be essentially rigid when it is more than 3.5 times the maximum bearing stiffness. Therefore, the effect of the differences between models is not manifested in this particular case. However, for other cases where the bearing stiffness is higher relative to pedestal stiffness, large differences will show up.

The conflicting results between measurement and prediction in the balancing facility may be attributed to one measurement that was not taken previously: the actual bearing centreline locations after rotor installation. Unlike job bearing housings where the bearing locations are known, the bearing locations in the balancing facility are set by manually moving each pedestal with a hand crank in an attempt to line up the proximity proves with the burnished areas. This does not lend to high accuracy, and axial deviations of a few cm can be expected.

Although the actual bearing locations in the balancing facility are impossible to know now that the rotor has since been removed, the rotordynamic models can be modified to move the bearing locations. For the Elliott 46MB compressor rotor balanced in the DH7 pedestals, moving the bearings outboard as much as possible results in agreement within 5% between the predicted and measured critical speed as shown in Figure 6.

Recommendations

In conclusion, balancing in a high-speed balance facility provides a better balance than low-speed balancing.

Operation in a high-speed balance facility also provides the opportunity for unbalance response verification, which is not available from low-speed operation.

When performing unbalance response verification in a high-speed facility, the following should be considered:

n All bolts, including bed bolts and bearing cap bolts, should be tightened to proper values to provide consistent pedestal characteristics.

n Further refinement of the pedestal model would not provide a benefit unless the pedestal stiffness is below 3.5 times the maximum bearing stiffness. The vendor pedestal model was sufficient in this case, as all models used in the analysis yielded similar results.

n The relative vacuum conditions in the balancing facility have no discernable impact on the bearing dynamics and rotordynamic performance. Tests with and without vacuum conditions yielded nearly identical vibration plots.

n The relative inaccuracy inherent with rotor installation in a balancing facility can result in varying bearing spans and probe locations, which must be recorded and reflected in the rotor model.

Figure 4. Rotordynamic analysis model - 46MB rotor.

Figure 5. Balancing facility measurement vs prediction.

Figure 6. DH7 benchmark case with bearings shifted outboard in model.

Nabil Abu-Khader, Compressor Controls Corp. (CCC), UAE, considers best practice for preventing compressor damage caused by surge.

Surge is a highly transient process that creates high stresses in compressor vanes and blades, causes higher than design stresses on diaphragms, damages internal seals, and results in high impact loads on thrust bearings of centrifugal and axial flow compressors.1 Damage to centrifugal compressors usually results from repeated high energy surge cycles over a long period of time. High internal temperatures caused by repeated surge cycles can also lead to damage. Axial compressors have free-standing blades, and a low number of isolated surge cycles can initiate cracks.

To avoid damage caused by surge, an antisurge control system is used on all axial flow compressors and most centrifugal compressors. Because of compressor fouling, transmitter drift, or component failures, a compressor may experience a surge event (consisting of one or more surge cycles) even when equipped with adequate antisurge control.

The American Petroleum Institute (API) has mentioned best practices for such situations to ensure machinery protection.

Basic antisurge control system layout

Figure 1 shows a basic centrifugal compressor antisurge control system diagram.

Antisurge recycle valves and discharge check valves should be located as close as practical to the compressor. The discharge line should be designed such that the volume of gas in the line between the compressor flange and the antisurge valve and the discharge check valve does not exceed the compressor manufacturer’s design limit.2

Compressor surge cycle

Raising the output pressure beyond design limits (by discharge throttling or process obstruction) can result in surging of the compressor. Violent surging is detected by an audible thumping from the compressor, vibrations, large fluctuations in discharge pressure, or motor current and axial position of the rotor, and check valve banging. Violent surging may cause the thrust bearing to fail, as well as other potential damage.

Imagine that this system is operating at steady state with a flow and pressure corresponding to point A shown in Figure 2. If the discharge throttle valve were closed slightly, the downstream system resistance would effectively increase, the flow through the compressor would decrease, and the pressure at the compressor outlet would rise.

If the valve continues to be closed in small steps, the compressor reaches point B, where a further reduction in flow produces no increase in the final discharge pressure, as the operating point approaches the surge limit. Closing the valve further increases the discharge pressure above the maximum value that the compressor can sustain. At this point, the flow of gas leaving the compressor has insufficient energy to enter the discharge volute. The forward flow regime through the compressor collapses, typically reversing in approximately 20 - 80 ms. The flow reversal through the machine and through the discharge valve causes the discharge pressure to rapidly drop and forward flow is reestablished. This is a surge cycle. If flow is reestablished and the system resistance remains elevated, then the discharge pressure will rapidly reach the unstable point B again, and the surge cycle would repeat.*

Figure 3 shows these fluctuations as they might be measured during an actual compressor surge. As shown, a typical surge cycle will last only 1 - 2 sec. Depending on the application, other variables (such as speed, suction pressure, discharge temperature) may also fluctuate rapidly. The occurrence of a surge can be inferred from a rapid change in any one or more of such variables. Once induced, surge can continue indefinitely until the cause is removed. In the interim, the severe oscillations of flow and pressure create heavy thrust-bearing and impeller or blade loads, vibration, and rising gas temperatures.

Because of the reverse flow, the hot gas flows to the suction and is reheated in the next compression cycle. This cycle signifcantly increases the gas temperature. This high temperature may exceed the design limits of the compressor materials or reduce internal clearances. If more

Figure 1. Basic antisurge control system.

Figure 2. Compressor surge cycle.1

Figure 3. Pressure and flow variations during a typical surge.1

than a few cycles occur, severe compressor damage can result.

To prevent or stop surge, measures should immediately be taken to increase the flow through the compressor, usually by opening a valve to recycle some of the flow to the compressor inlet or (for an air compressor) to blow-off some of it to the atmosphere. A system that automatically takes action to prevent surge from occurring is an antisurge control system. These systems generally utilise sensors in the process (upstream and downstream of the compressor) and logic algorithms to determine the location of the operating point relative to the theoretical (or as tested) specific compressor surge limit line. If the operating point approaches the surge limit then the recycle or blow-off valves are opened to prevent reaching the predetermined surge point.

Surge detection system (SDS)

API-670 5th edition includes surge detection as a part of machinery protection. According to the standard, an SDS, independent from the antisurge control system, is required on axial compressors, and should be considered on centrifugal compressors. The SDS detects surge by monitoring rates of change of relevant compressor parameters (flow and/or pressure), counts the number of surge cycles, and provides a discrete output if the surge count exceeds a specified number within a specified time (e.g., 3 cycles in 10 sec).

Figure 4 represents one possible integration between the SDS and an antisurge control system, field devices, plant

BELIEVING SEEING IS

emergency shutdown (ESD) system and plant distributed control system (DCS) or trainview human machine interface (HMI).3

The electronic SDS is only one component in the compressor system. The SDS is comprised of sensors, transducers, logic solver, surge counter, and outputs that may be used by other logic and annunciating systems. Per API Standard 670, the architecture for the SDS shall follow the design shown in Figure 4. The purpose of the SDS is to protect the compressor from surge in the event of a failure of the antisurge control system. SDSs do not rely on determining the theoretical surge limit line or operating point

Figure 4. SDS integration with compressor control and ESD systems.

locations, but instead only rely on detecting the system response to an actual surge cycle.

If specified, the SDS shall be capable of initiating further actions such as fast opening of the antisurge valves or shutdown of the main driver. These actions may be initiated after a user-defined or machine vendor-defined number of surges has been detected within a user-defined or machine vendor-defined time window. Definition of the time window and number of surges before action is taken should be determined as part of a system evaluation and mutually agreed between the purchaser and vendor.1**

Even if a specific SDS is not justified, all process plant designs that incorporate centrifugal compressors should consider the possible consequences of damage associated with compressor surge. As a minimum, this should include detection and alerting of consequences such as: gas leak detection; high or low excursions of process pressures or temperatures; abnormal rotor axial position; high bearing temperatures; or high motor currents, etc. On detection and annunciation of such conditions, the operator can take action to shut down and bring the compressor to a safe state.1

Conclusion

The main purpose of an antisurge control system is to monitor compressor proximity to the surge control line and to open the antisurge valve in a controlled way to prevent compressor operating to the left of that line. Modern purpose-built antisurge control systems provide a set of

effective surge prevention functions, from simple proportional-integral-derivative (PID) control loops to open loop response, anticipative surge control line, and velocity-based surge prevention algorithms. A surge control system needs to be able to detect the occurrence of surge and minimise the number of surge cycles by adapting either the surge control line or the anti-surge valve position to where the compressor may operate safely. To prevent surge in case of antisurge control system failure and/or control system measurement or actuation devices malfunctioning, an independent SDS and protection system should be installed. Surge detection has been identified as a segregated safety function by the API Standard 670 5th edition.

Notes

*It is important to note that surge was caused here by closing a discharge valve; however, anything that increases system resistance, such as fouling of intercoolers or changes in process characteristics, can lead to surge.

** If the antisurge control system incorporates redundant transmitters and redundant controllers, the SDS may be included in the antisurge control system. If specified, the ESD may be combined with the SDS. The ESD shall be independent from the antisurge control system. Antisurge valves and their actuators may be shared for SDS and antisurge control.

References

1. API Standard 670, Machinery Protection Systems, Fifth Edition, (November 2014).

2. API Recommended Practice 686, Recommended Practice For Machinery Installation And Installation Design, Second Edition, (December 2009).

3. UM8405-V3, Guardian (SDS) – Surge Detection System (Operation Manual), CCC Publication Library, (October 2022).

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