Hydrocarbon Engineering November 2023

November 2023

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CONTENTS November 2023 Volume 28 Number 11 ISSN 1468-9340

05 Comment

39 A world of opportunities

07 World news 10 Europe: scrambling to adapt Gordon Cope, Contributing Editor, sheds light on the urgent need for European energy and petrochemical suppliers to adapt in the face of market upheaval.

15 Six things to know before launching an advanced recycling project Advanced recycling projects can provide solutions for petrochemical companies aiming to meet decarbonisation targets. Chris Ploetz and Kevin Syphard, Burns & McDonnell, USA, outline the most important factors to consider in order to achieve project success.

19 Chemical recycling through pyrolysis Dan Nienhauser, Stellar3, USA, explains how waste plastics can be transformed into valuable petrochemical outputs.

24 From nano-engineering to refinery results Jeff Pro and Johan P. Den Breejen, Shell Catalysts & Technologies, discuss how nano-engineered zeolite catalyst technology is unlocking value for modern hydrocrackers.

31 The key to crude oil to chemical conversion Hernando Salgado, Abdallah Al-Zyoud, Modesto Miranda, Emmanuel Smaragdis, Minwoo Kim and Corbett Senter, BASF, discuss how the FCC process, and associated catalyst technologies, are positioned to sustain the future refining-petrochemical business as it transitions to a more chemicals-oriented market.

Gabriel Buffin, Bijay Barik and Laurent Watripont, Axens, discuss how isomerisation can open up a world of opportunities for a more sustainable refining industry.

46 Supporting a clean fuels society Norbert Ringer and Christoph Krinninger, Clariant, introduce the company’s new catalytic solutions, which have the capacity to support green methanol production.

51 A safe and versatile option Piet Goemans and Oxana Voss, BUCHEN-ICS GmbH, Germany, illustrate the versatile applications of dense phase conveyors in the petrochemical industry.

54 From carbohydrates to hydrocarbons Philip Siu, EcoCeres, explains how agricultural waste can be converted into sustainable aviation fuel (SAF) and how companies can contribute towards the development of a clean aviation industry.

57 Digitalisation: the key to successful wastewater management Dr. Ipek Ozturk Ortalan, Kurita Europe GmbH, Germany, reveals how refineries and petrochemical companies can achieve sustainability goals and ensure efficient operation by using real-time wastewater monitoring and control systems.

61 Forecasting success Yon-Sing Simon Wong, DNV, Malaysia, explores how performance forecasting can help to optimise downstream oil and gas activities.

67 Apply logic, not intuition Monil Malhotra, Emerson, USA, discusses how state-based control eliminates inefficient processes, leading to more reliable, sustainable and profitable operations.

71 Maximising compressor performance Nabil Abu-Khader and Serge Staroselsky, Compressor Controls Corp. (CCC), explain how technology can be used to monitor, analyse and maximise compressor performance.

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CALLUM O'REILLY SENIOR EDITOR

T

he last couple of months has seen the publication of two ‘Energy Transition Outlook’ reports; one from Wood Mackenzie1 and the other from 2 DNV. Both reports provide a forecast to 2050, and both are downbeat about the prospect of hitting the Paris Agreement goal of limiting global warming to 1.5°C by mid-century. Wood Mackenzie believes that the world is currently on a 2.5°C warming trajectory by 2050, while DNV’s ‘most likely’ forecast translates to global warming of 2.2°C by the end of this century.

Both reports stress that while achieving the 1.5°C target is now extremely difficult, it is still possible, and actions taken in the next decade will determine whether the world can be at, or very near, net zero by mid-century.

For DNV, CO2 emissions would need to halve by 2030 in order to meet the 1.5°C target, but its current forecasts suggest that this will not even happen by 2050. According to Wood Mackenzie, a minimum investment of US$2.4 trillion/yr in renewables, infrastructure and energy transition technologies is required to achieve net zero by 2050.

The current geopolitical landscape has had a significant impact on both forecasts.

“The pathway to net zero was always going to be challenging, but Russia’s invasion of Ukraine has made it more difficult especially in the near term. The conflict quickly curtailed the global supply of energy and metals […] supply security fears increased around the world, and higher prices across energy and mining commodities have fuelled inflation,” explains Simon Flowers, Chairman and Chief Analyst at Wood Mackenzie.

The Ukraine conflict has seen greater emphasis placed on energy security, with a ‘grab for gas’ and a reversion to coal in some regions. Prakash Sharma, Vice President, Scenarios and Technologies Research at Wood Mackenzie, notes that oil and gas have a role to play as part of a managed energy transition: “There will be a natural depletion as low and zero carbon options develop but supply still needs to be replenished as we move towards net zero.” Wood Mackenzie’s ‘base case’ (its most likely forecast) suggests that fossil fuels will account for 69% of end-use energy demand in 2023, falling to 53% by 2050. DNV expects fossil fuels to be 48% of the primary energy mix by mid-century, with gas maintaining a high share of the primary energy supply mix throughout the forecast period. DNV also notes that the use of fossil fuels for non-energy purposes (e.g. as a feedstock in plastics, petrochemicals, etc.) will grow over the forecast period.

Both reports also point to the importance of emerging technologies, such as hydrogen and CCUS projects, which are moving out of the pilot phase and becoming mainstream. In DNV’s forecast, hydrogen must account for approximately 15% of the world’s energy demand by 2050 in order to meet the Paris Agreement targets, while Wood Mackenzie has this figure at 11%. Both report that global adoption of hydrogen is likely to fall significantly below these figures, with DNV projecting that it will stand at 5% in 2050, and Wood Mackenzie’s base case estimating 4%. Despite this, DNV notes that hydrogen will spur industry transforming changes, and expects developments in hydrogen technology and infrastructure to be significant over the next three decades.

If you’re interested in keeping up-to-date with the latest developments in the hydrogen sector, please register for a free subscription to our sister publication, Global Hydrogen Review, by visiting: www.globalhydrogenreview.com/magazine.

1.

2.

‘2023 Energy Transition Outlook’, Wood Mackenzie, (September 2023).

‘Energy Transition Outlook 2023’, DNV, (October 2023).

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WORLD NEWS USA | EIA: US natural gas exports set record in

1H23

T

he US exported more natural gas in the first half of 2023 (1H23) than it did in the same period of any previous year. Natural gas exports averaged 20.4 billion ft3/d, 4% (0.8 billion ft3/d) more than in 1H22, according to the US Energy Information Administration (EIA)’s ‘Natural Gas Monthly’.

In 1H23, US LNG exports averaged 11.6 billion ft3/d, making the US the world’s top LNG exporting country.

US LNG exports in 1H23 increased 4% (0.5 billion ft3/d) compared with the same period in 2022, despite declining in May and June.

During the period, US natural gas pipeline exports to Canada and Mexico increased 4% (0.3 billion ft3/d) compared with 1H22, averaging 8.8 billion ft3/d. Net natural gas exports by pipeline, particularly to Mexico, contributed to record-high natural gas exports.

Germany | JM and BP chosen by EDL to support

production of SAF

J

ohnson Matthey (JM) and BP have announced that EDL Anlagenbau Gesellschaft mbH (EDL) has selected their co-developed Fischer Tropsch (FT) CANSTM technology for EDL’s HyKero plant located in Böhlen-Lippendorf, south of Leipzig, Germany.

The HyKero plant is planned to produce 50 000 tpy of sustainable aviation fuel (SAF) when fully

operational, including eSAF from a power-to-liquids (PtL) route, and would be the first plant of its kind at commercial scale in Germany. The PtL route is the conversion of renewable electricity and carbon dioxide (CO2) into sustainable liquid fuels. Current international certification for this SAF requires a blend of up to 50% with fossil kerosene to create drop-in SAF.

Worldwide | Global oil

demand forecast to reach record levels in 2023

G

lobal oil demand will reach record levels in 2023, with demand expected to continue to grow each year and peak in 2035, according to Bloomberg Intelligence’s (BI) latest oil sector survey of energy-related investors.

Almost half (46%) of respondents think global demand will be between 101 and 102 million bpd on average in 2023, with a similar number (44%) believing it will be above 102 million bpd. This compares to the 99.9 million bpd seen in 2022, as cited by the International Energy Agency.

In comparison to BI’s 2022 survey, there has been a major shift in opinion related to the pace of green and energy-transition spending by European energy majors. 46% of respondents now believe ‘green’ CAPEX will never reach 50% or more of the overall annual capital outlay; this compares with 15% of respondents previously.

Qatar | CPChem and QatarEnergy secure financing on petrochemicals

project

R

as Laffan Petrochemicals, a joint venture (JV) company owned 30% by Chevron Phillips Chemical and 70% by QatarEnergy, has announced that it has secured US$4.4 billion to finance an integrated polymers facility to be located in Ras Laffan Industrial City, Qatar.

The project financing comprises commercial and Islamic lenders and a group of export credit agencies.

Securing the financing is a key milestone in the development of

the 435 acre petrochemical project, which will include the largest ethane cracker in the Middle East and one of the largest in the world. The facility will have a capacity of 2.1 million tpy of ethylene and will also include two high-density polyethylene derivative units with a total capacity of 1.7 million tpy.

The polyethylene units will use CPChem’s MarTechTM loop slurry process to produce high-density polyethylene for durable goods such as pipe for natural gas and

water delivery and packaging applications to protect and preserve food and keep medical supplies sterile.

CPChem and QatarEnergy reached positive final investment decision (FID) for the Ras Laffan petrochemicals project in January 2023, and startup of the facility is expected in late 2026.

The two companies are also constructing a JV integrated polymers facility on the Texas Gulf Coast, US, which is expected to be operational in 2026.

HYDROCARBON

ENGINEERING

7

November 2023

WORLD NEWS DIARY DATES 05 - 07 December 2023 16th Annual National Aboveground Storage Tank Conference & Trade Show The Woodlands, Texas, USA www.nistm.org

30 - 31 January 2024 NARTC Houston, Texas, USA www.worldrefiningassociation.com/event-events/ nartc

26 - 29 February 2024 Laurance Reid Gas Conditioning Conference Norman, Oklahoma, USA pacs.ou.edu/lrgcc

03 - 07 March 2024 AMPP Annual Conference + Expo New Orleans, Louisiana, USA ace.ampp.org

12 - 13 March 2024 StocExpo Rotterdam, the Netherlands www.stocexpo.com

29 April - 03 May 2024 RefComm Galveston, Texas, USA www.events.crugroup.com/refcomm

14 - 16 May 2024 Asia Turbomachinery & Pump Symposium Kuala Lumpur, Malaysia atps.tamu.edu

10 - 14 June 2024 ACHEMA Frankfurt, Germany www.achema.de/en

11 - 13 June 2024 Global Energy Show Calgary, Alberta, Canada www.globalenergyshow.com

26 - 27 June 2024 Downstream USA Galveston, Texas, USA events.reutersevents.com/petchem/downstream-usa

17 - 20 September 2024 Gastech Houston, Texas, USA www.gastechevent.com

November 2023

8

HYDROCARBON

ENGINEERING

China | Aramco assesses possible investments

A

ramco, Nanshan Group, Shandong Energy Group and Shandong Yulong Petrochemical have signed a Memorandum of Understanding (MoU) to facilitate discussions relating to the possible acquisition by Aramco of a 10% strategic equity interest in Shandong Yulong Petrochemical.

Shandong Yulong is currently in the process of completing the construction of a refining and petrochemicals complex that is designed to process around 400 000 bpd of crude oil and produce a large volume of petrochemicals and derivatives. The facilities are located at Longkou, Yantai City, in China’s

Shandong Province. As outlined in the MoU, Aramco would potentially supply Shandong Yulong with crude oil and other feedstock.

The MoU signing follows a recent announcement that Aramco had signed a cooperation framework agreement with Jiangsu Eastern Shenghong to also facilitate discussions relating to the possible acquisition by Aramco of a 10% strategic equity interest in Jiangsu Shenghong Petrochemical Industry Group, a wholly-owned subsidiary of Eastern Shenghong, subject to due diligence, negotiation of transaction documents and required regulatory clearance.

Indonesia | BP ships first cargo from Tangguh

LNG facility

B

P, on behalf of the Tangguh production sharing contract partners, has announced that the first cargo of LNG produced by the new third liquefaction train at the Tangguh LNG facility, in Papua Barat, Indonesia, has safely been loaded and sailed. It will be delivered to Indonesia’s state-owned power generator PT PLN (Persero).

This marks the start of full commercial operation of the expanded Tangguh LNG facility.

The start-up of Tangguh Train 3 will add 3.8 million tpy of LNG production capacity to the existing two-train facility, bringing total plant capacity to 11.4 million tpy. The Tangguh expansion is the third major project start-up for BP globally in 2023.

Belgium | BASF starts up expanded ethylene

oxide and derivatives complex

B

ASF has announced that it has expanded capacities for ethylene oxide and ethylene oxide derivatives at its Verbund site in Antwerp, Belgium.

The investment adds approximately 400 000 tpy to BASF’s production capacity for the corresponding products.

“With the new plants we are supporting the continuous growth of our customers and are enhancing our market position in Europe,” said Hartwig Michels, President, Petrochemicals, BASF. The investment,

exceeding €500 million, comprises a second world-scale ethylene oxide plant, including capacity for purified ethylene oxide.

In addition to ethylene oxide, the investment includes additional capacities for alkoxylates, which are derivatives of ethylene oxide and used in a wide range of applications such as in detergent and cleaning, automotive and the construction industry. The expanded ethylene oxide and derivatives complex is also a major investment for the site in Antwerp.

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Gordon Cope, Contributing Editor, sheds light on the urgent need for European energy and petrochemical suppliers to adapt in the face of market upheaval.

E

urope is facing the most comprehensive reorganisation of its energy sector in many decades, thanks to a combination of COVID-19, the conflict in Ukraine, environmental concerns, shifting consumption patterns and new fuel sources. Energy and petrochemical suppliers are scrambling to adapt.

Gas prices surge Without a doubt, the Ukraine war and the subsequent sanctions against Russia have had the most profound impact on natural gas. While resurgent demand after COVID-19 had already driven prices up to almost US$50 per thousand ft3 by late 2021, the invasion of Ukraine in February 2022 resulted in further turmoil, culminating in the sabotage and destruction of Nord Stream, a major conduit of natural gas from Russia to Europe.

The problem was exacerbated by a lack of storage. While North America has in excess of 5 trillion ft3 of natural gas, primarily in immense salt domes, Europe has been quietly closing storage over the last decade due to poor summer/winter price spreads. The UK, significantly, had only 10 days reserve capacity when the crisis hit.

European governments announced severe conservation efforts that saw major industrial users suspending capacity and citizens turning down the thermostat. Fortunately, a mild winter and conservation efforts resulted in a drop of almost 20% of average winter consumption, avoiding catastrophe.

Longer-term solutions are now underway. In 2017, Centrica closed the Rough gas storage facility in the North Sea (which held over 30 billion ft3), significantly paring the UK’s reserve capacity. In October 2022, it announced that it was reopening the facility and intended to fill most of the

HYDROCARBON 11

ENGINEERING

November 2023

capacity for the winter season. In June 2023, the company revealed that it planned to expand total capacity to over 50 billion ft3, which is sufficient to heat 2.4 million homes throughout the winter.

LNG LNG is also seen as a solution to shortages. Germany, which had relied on Russia for virtually all of its gas imports, rushed to install floating storage and regasification units (FSRUs). In early 2023, Germany welcomed its first LNG tanker at the Wilhelmshaven terminal, sent from the Calcasieu Pass export facility in the US Gulf Coast. Several weeks later, the Deutsche Ostsee terminal in Lubmin, located on the German Baltic Sea coast, began receiving LNG from TotalEnergies. In all, Germany has plans for 10 FSRUs, some of which will be replaced by onshore regasification facilities once they are built. Total installed capacity is expected to exceed 70 million tpy by 2030 (although there is a distinct possibility that several may be cancelled).

Refineries The European refining sector has been in turmoil for over a decade. In the early 2010s, the continent had approximately 16 million bpd of capacity. Since then, tight refining margins have eaten into capacity, reducing the total by over 10%.

With the advent of COVID-19, the pace accelerated; ExxonMobil permanently shuttered its Slagen refinery in Norway, Gunvor closed two crude processing units in Rotterdam, the Netherlands, and mothballed its refinery in Antwerp, Belgium, and Neste has discontinued operations at its Naantali refinery in Finland. Capacity now stands at around 14 million bpd.

Stringent rules regarding internal combustion engines (ICE) have also affected consumption in the EU. Currently, there are around 5 million electric vehicle (EV) cars in Europe; a directive to eliminate the sale of new ICE vehicles by 2035 could result in the number climbing to 100 million cars by 2040, eliminating roughly half of all diesel and petrol consumption on the continent.

European refiners have long relied on exports to North America and Africa to maintain capacity.

Unfortunately, the African market is being jeopardised by competition from new refineries in Asia and the Middle East, as well as belt-tightening in Nigeria. The West African nation’s output of refined products has lagged well behind consumption, resulting in significant imports. The government was spending up to US$10 billion annually in subsidies, contributing to a massive deficit. In July 2023, Nigeria cancelled the fuel subsidies, resulting in a 28% consumption slump and jeopardising a major European fossil fuel market.

All hope is not lost. Over the last decade, the EU has set ambitious targets for renewable fuels in transport (the Renewable Energy Directive [RED]), and is now doubling down since the conflict in Ukraine. So far, the refining sector has largely responded by shifting production toward biofuels. The majority of investment has been into fatty acid methyl esters (FAME) biodiesel, which is the transesterification of vegetable oils into fuel. FAME fuels have now reached production of approximately 14 million tpy, which is the current blending wall limit to what can be mixed into conventional diesel.

November 2023 12 HYDROCARBON ENGINEERING

Refiners are now investing in hydrotreated vegetable oils (HVOs), which can be interchanged with conventional diesel and have no blending walls. There is only so much vegetable oil and related fatty wastes available in the EU, however, and a longer-term solution is to use lignocellulosic feedstock (non-edible vegetable matter such as sawdust, corn stalks, etc.). Oil companies have announced investments in these advanced biofuels totalling almost €40 billion; the goal is to produce up to 29 million tpy of biofuels by 2030. Many of the processes for producing lignocellulosic-based biofuels mirror those used to produce conventional diesel, so most of the new production is expected to take place in existing plants. Total shut its crude processing at the Grandpuits refinery, converting it into a 400 000 tpy biofuel complex, and Eni, which has already converted two refineries to biofuel, is now evaluating its Livorno refinery with the aim of reaching 2 million tpy of bio-refining by 2024.

Petrochemicals Petrochemicals in Europe is an immense sector, encompassing almost 30 000 companies producing 17% of world output and achieving a turnover of €146 billion. Over the last several years, however, it has had to deal with supply chain disruptions, soaring natural gas and electricity costs, and market disruptions. Yara, a major producer of ammonia, temporarily shut down a significant portion of its European production in 2022. Other companies have had to ration resources in order to maintain operations.

The viability of the sector requires constant upgrading of assets with the latest, most efficient technologies in order to remain competitive. Strict EU environmental rules, however, are placing future investment in doubt. In 2020, INEOS, a UK-based chemicals company, announced a new, US$3.4 billion olefins complex for the port area of Antwerp.

“Our investment in a gas cracker and world-scale PDH unit is the largest of its kind in Europe for more than a generation and is an important development for the European petrochemical industry,” said Sir Jim Ratcliffe, Founder and Chairman of INEOS. “We believe this investment will reverse years of decline in the sector.”1 The project involves two major installations; a 1.54 million tpy ethane cracker and a propane dehydrogenation (PDH) module that will produce 750 000 tpy of propylene. The company claimed that the new facility would be climate-neutral within 10 years of its start-up, slated for 2026.

The project immediately came under attack from environmental groups, as well as the authorities of Zeeland and North Brabant, arguing that the permit for Project One had been issued without an appropriate environmental impact assessment being made on the nearby wildlife reserve known as the Brabantse Wal, which is protected under the European Habitats Directive. In July 2023, the Flemish Council for Permit Disputes agreed, and revoked permits issued by the province of Antwerp. INEOS announced that it would seek to appeal, but while the project may eventually reach completion, the revocation will have a chilling effect. “What company would now dare take the risk of investing in our economy?” stated the Chamber of Commerce for Antwerp-Waasland. “This judgement sends a disastrous signal to foreign investors in Europe and beyond.”2

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Hydrogen The EU has announced increases in subsidies for low-carbon hydrogen fuel. In the aftermath of the energy crisis related to the Ukraine war, it earmarked €5.4 billion for Hy2Tech (an initiative that aims to perfect hydrogen technology), and €5.2 billion for Hy2Use (which will invest in applications in hard-to-decarbonise sectors such as cement, steel and glass).

A further €3 billion subsidy, dubbed the Hydrogen Bank, will help stimulate demand.

Green hydrogen, which is produced using electrolysis powered by renewable resources, has the advantage that it can be produced virtually anywhere. It has a high-energy capacity and, when burned, produces only water as an emission.

BP has announced ambitious hydrogen plans for the UK’s Teesside port. In addition to a blue hydrogen project (which uses carbon capture and sequestration [CCS] to eliminate emissions), it now aims to build a green hydrogen plant that will use renewable sources. HyGreen Teesside will have the potential to deliver 30% of the UK’s 2030 target for hydrogen production. INEOS also announced plans to invest US$1.37 billion in its Grangemouth refinery to produce blue hydrogen for export.

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

Much of the green hydrogen capacity will be developed outside of the downstream sector. In February 2023, OX2, based in Sweden, and the Bank of Aland announced a major green hydrogen project, located in the Port of Långnäs, Finland. Two offshore wind farms with a total of 8 GW will be connected to facilities in the Mega Grön Hamn complex where electrolysers will be used to create hydrogen and shipping fuels (1 GW of capacity equals about 160 000 tpy of green hydrogen production).

In March 2023, the Dutch government officially designated a site for the world’s largest offshore hydrogen production project: the Ten noorden van de Waddeneilanden (the North of the Wadden Islands). The site, which has the potential for 700 MW of generation, will be connected to Gasunie’s proposed offshore hydrogen pipeline network.

In December 2021, Spain’s government announced that it would spend €7.8 billion on renewables and green hydrogen over the next two years, with the aim of attracting a further €9.45 billion in private funding. Approximately €1.55 billion is to be allocated toward the development of green hydrogen through the country’s abundant sun and wind, with the goal to supply 10% of the EU’s target output by 2030. The rest would go toward smart-grid infrastructure, energy storage, training and research.

Because of its tiny molecular size and habit of making conventional steel more brittle, hydrogen will need dedicated storage infrastructure. In June 2023, Centrica announced that it would work to convert the Rough field to renewable energy. “We stand ready to invest £2 billion to repurpose the Rough field into the world’s biggest methane and hydrogen storage facility, bolstering the UK’s energy security, delivering November 2023 14 HYDROCARBON ENGINEERING

a net zero electricity system by 2035, creating 5000 skilled jobs and decarbonising the UK’s industrial clusters by 2040,” said Chris O’Shea, CEO of Centrica Group.3

Problems Hydrogen faces significant challenges. Creating a new energy sector based on low-carbon hydrogen is considered to be exceedingly expensive when compared to other green alternatives. The EU has estimated that it would cost US$430 billion to achieve a 14% hydrogen share of the continent’s energy demand by 2050.

Low-carbon hydrogen is also very expensive to produce; currently, electrolysis can create hydrogen at a cost of US$5/kg vs US$2/kg or less for conventional production.

Research is focusing on commercially-available electrolysers to reduce capital costs and increase efficiency. Proton exchange membrane (PEM) electrolysers cost around US$1400 - 1700 per kg of production, and use 52 kWh of electricity to produce 1 kg of hydrogen; developers are looking at ways to replace expensive platinum catalysts.

Scientists at the US Department of Energy’s National Renewable Energy Laboratory (NREL), are examining the potential for solar thermochemical hydrogen (STCH) production, which has the potential to be much more efficient than electrolysis. The process relies on focusing the sun’s rays to heat metal oxides to 1400˚C, which are then quenched with steam to split the water atoms into oxygen and hydrogen. Currently, research is underway to find the most efficient metal oxides.

Further down the road, natural sources might obviate the need for production facilities entirely, potentially stranding current planned investments. Scientists are studying the formation of pure hydrogen deep in the mantle of the earth, where temperatures approach that of the sun. This ‘white’, or naturally-derived hydrogen then percolates up to the near-surface, where it can be acquired using wells drilled into the substrate. Under certain geologic conditions, it can be captured as easily as natural gas and shipped directly to consumers.

Future In the short-term, the future of European midstream assets will be pressured by the gradual decline of diesel and petrol consumption as EVs gain ground. Increased competition in export markets from new refineries in Asia will place further pressure on margins. Imports of fuels from lower-cost jurisdictions, which currently meets 65% of the continent’s demand, will continue to rise.

In the longer-term, the future is brighter. Conversion of existing facilities to renewables, as well as the growth of low-carbon fossil fuels through blue and green hydrogen, will not only help the sector meet EU environmental targets, but will provide viable, large-scale output for the coming decade.

References 1.

2.

3.

https://www.nesfircroft.com/resources/blog/5-petrochemicalprojects-in-europe-you-need-to-know-about/. https://www.sustainableplastics.com/news/permit-ineos-projectone-antwerp-cancelled. https://www.centrica.com/media-centre/news/2023/centricabolsters-uk-s-energy-security-by-doubling-rough-storage-capacity/.

Advanced recycling projects can provide solutions for petrochemical companies aiming to meet decarbonisation targets. Chris Ploetz and Kevin Syphard, Burns & McDonnell, USA, outline the most important factors to consider in order to achieve project success.

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n increasing number of petrochemical companies are setting their sights on advanced recycling projects to help decarbonise their operations and meet their environmental, social and governance (ESG) goals.

Pyrolysis, gasification, depolymerisation and other emerging technologies dramatically

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increase the types and amount of plastic that can be chemically recycled, avoiding the downcycling effect associated with existing mechanical recycling processes.

By breaking down these materials into their basic molecular components, these technologies make it possible to convert waste into new base materials, reducing or eliminating the need for virgin feedstock.

Implementation of advanced recycling processes should be approached with care. In some cases, the unit operations and design considerations are different than those common to refineries or petrochemical complexes. Additionally, the technology licensors are rarely in a position to fully understand how their process will be integrated into an existing chemical complex. The licensors are rightly focused on their core technology. For these projects to be successful, owners and licensors need the support of an engineering and construction partner that understands the nuances of technology integration.

Managing information voids and experience gaps A project’s success can be negatively impacted by a lack of information and understanding. It is necessary to identify and understand project knowns and unknowns at an early stage to minimise change and churn as the project advances through a gated work process. This can be accomplished by using a structured knowledge transfer process. Such a process provides a holistic method for evaluating project requirements from core process technology to utility systems and material logistics. This article will outline a number of factors that are important to know before beginning an advanced recycling project.

Portions of advanced recycling processes need controlled environments

With some exceptions, many refining and petrochemical processes are well understood steady-state processes performed in outdoor settings. The location and climate of the facility can dictate nuances in design, but most major unit operations have had years of optimisation and refinement.

In contrast, some aspects of advanced recycling projects may be performed in controlled indoor environments. Feedstock receiving, storage and preparation should be kept dry and away from wind.

Additionally, portions of the process can be sensitive to colder climates, so locating unit operations inside buildings can simplify piping, insulation and heat tracing requirements for the project. However, for processes that increase capacity by adding parallel equipment trains, more processing space under roof is needed, which complicates layout, maintenance access and expandability for the future.

These considerations add to design and construction costs and are not always included in the licensor’s cost estimates. They may also impact utility design requirements.

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Material handling systems require customised designs

Hydrocarbon processors have deep experience with pumps, compressors, piping networks and other equipment needed to transport gases and liquids through a facility. These processors may be less familiar with the material handling systems associated with waste plastic feedstocks, intermediates and final products.

Particle size, bridging potential and flow characteristics are essential factors to consider when selecting material handling solutions. For example, pneumatic conveyance systems are commonly used to move plastic pellets. For these systems, plant layout and configuration are key design factors. Additional special processes may be needed to load the pellets into bags or onto trucks and rail cars with minimal dust and damage. When processing sticky polymers with unique flow characteristics, different solutions are required to ensure that materials can be properly mixed, prepared for contact with catalyst and devolatilised.

Material handling systems must be designed to address the unique properties of the materials being managed.

The permitting process can be slow

Finding the appropriate regulatory framework can take time, especially if the project owner wants to avoid permitting under the existing rules for established processes. Early project planning should include conversations with regulators to educate them on the project so they can provide input on the rules that will guide the air and water permitting processes. Since projects in this space need to progress quickly in order to achieve production and profitability goals, utilising a permit matrix approach is crucial to receiving timely permit approvals.

Early and frequent community outreach is equally important to project success. Guiding the neighbouring community on how the plant operates, what additional delivery traffic is expected, and how the facility will integrate into the community is imperative to maintaining the overall project timeline.

Wastewater characterisation and treatment requirements are critical

The wastewater contaminants produced by traditional refining and petrochemical processes are well known, as are the solutions for treating them. However, the wastewater streams associated with some emerging technologies are more varied and less understood.

Ideally, wastewater samples from pilot or demonstration-scale operations would be available for treatability studies by wastewater treatment specialists to inform the development of the treatment scheme.

However, in many cases, the wastewater streams from emerging technologies are not well characterised, which hampers the design and permitting of downstream wastewater treatment systems. Wastewater treatment is a crucial consideration that can significantly impact cost and schedule. The development of a project’s

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wastewater strategy is a key part of early project feasibility studies.

Some advanced recycling processes involve flammable materials that require special fire protection measures

Petrochemical companies have robust safety and fire protection systems. However, like wastewater treatment, these systems may require upgrades to address new risks created by advanced recycling projects. For example, designing fire protection systems for indoor and outdoor processing requires knowledge of processing systems in both areas. Additionally, the potential for combustible dust in some processes must be considered in the design and implementation of fire safety systems. Drainage systems may need to be designed to direct water used for firefighting away from critical processes. Processes may need to be designed to allow for the isolation of hazardous and flammable materials to limit damage to adjacent areas in case of emergencies.

A contingency analysis that reviews an entire advanced recycling process is fundamental to designing fire protection systems that identify and address these risks.

Utility and infrastructure design in refineries and petrochemical plants is complex. Each of the numerous units consume and/or produce utilities that drive the facility. Installation of an advanced recycling unit operation – with its batch and continuous processing requirements, as well as on-stream factors that differ from traditional processing units – can strain a facility’s utility demand in unique ways.

Further, to shed costs on projects, some investors may elect to outsource the utility requirements to a third party in a design-build-own-operate-maintain (DBOOM) scenario. This presents challenges in how these third parties are integrated into the project and understanding each party’s obligations and risks involved in delivering these obligations. In almost every case, utilities and infrastructure must be on-stream first, but they are generally understood and specified later in the design workflow. This gap in timing can drive uncertainty and schedule compression into projects.

Using knowledge transfer to support project success

Advanced recycling provides great opportunities for the petrochemical industry to support the circular economy and increase profitability. By recycling and reusing mixed plastics and other scarce or environmentally sensitive materials, a more sustainable approach to resource Utility sourcing may need to be adjusted to management can be realised. But as with any new or meet overall project goals novel technology, implementation of these projects Advanced recycling projects add a new element to the exposes the many information gaps that can exist mix. Capital planning must consider the complexities between the developers and the end users of advanced that these projects bring to the overall utility recycling solutions. That is why the knowledge transfer infrastructure and the contracts required to deliver the process is so important (see Figure 1). supply needed to meet demand, especially if Finding an EPC partner who embraces the low-carbon energy sources are required. knowledge transfer process and has a background in both petrochemicals and emerging technologies can help bridge knowledge gaps.

The application of a knowledge transfer process that methodically identifies the uncertainties, open issues, and risks inherent in the design, operation and maintenance of these projects can also help significantly.

Both are key to moving forward confidently toward Figure 1. Using a structured knowledge transfer process to confirm the design basis and advanced recycling outcomes is imperative to a project’s success. project success.

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Dan Nienhauser, Stellar3, USA, explains how waste plastics can be transformed into valuable petrochemical outputs.

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illions of tons of plastic waste end up in landfills and oceans each year due to the global plastic waste problem. In terms of managing plastic waste, chemical recycling, specifically pyrolysis, offers a promising solution. This article examines chemical recycling via pyrolysis, which converts waste plastics into valuable petrochemicals. The benefits and challenges of integrating pyrolysis into the circular economy will be discussed, as well as the process principles, factors affecting product distribution, and potential applications of the petrochemical products. Potential strategies to optimise the technology for commercial-scale implementation will also be outlined.

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Pyrolysis process In an oxygen-free environment, pyrolysis involves the thermal breakdown of carbonaceous materials (municipal solid waste [MSW], biomass, waste plastics). It is possible to produce gaseous, liquid, and solid products through a variety of reaction pathways. Depending on the desired product distribution, the process usually takes place between 300°C and 900°C. Condensable output can be created by pyrolysis-based equipment, which is very useful when processing plastics or tyres. In such cases, the operating temperature should not exceed 600°C. A higher processing temperature is required if syngas is to be the primary output – nominally above 800°C. Product distribution is influenced by temperature, residence time, feedstock composition, and catalysts.

Generally, gaseous products prefer higher temperatures, but careful temperature management and residence time can have a significant impact on petrochemicals and refined fuels.

In pyrolysis, temperature plays a crucial role in determining reaction rate and product distribution. Due to the faster rate of reaction at higher temperatures, gaseous products such as hydrogen and methane are produced.

Alternatively, lower temperatures promote the formation of liquid and solid products, such as pyrolysis oil and char.

Reactor residence time refers to the amount of time a feedstock remains inside the reactor. A longer residence time can result in more secondary reactions, resulting in more liquids and solids. In contrast, shorter residence times may favour gaseous formation.

Product distribution is heavily influenced by feedstock composition. Generally, polyethylene (PE) and polypropylene (PP) produce more liquid products, while polyvinyl chloride (PVC) and polyethylene terephthalate (PET) produce more solid products. Considering that PET already has a significant recycling presence, liquid fuels can easily avoid this in the feedstock. In general, PVC should be avoided, except when naturally occurring in waste streams (e.g., hospital waste), where the system should isolate chlorine compounds and transform waste streams accordingly.

The use of catalysts improves the yield and selectivity of products produced by pyrolysis. The use of zeolite catalysts can enhance hydrocarbon production, while metal-organic frameworks (MOFs) can be used to selectively target chemical intermediates. Catalysts should be optional in a system and used only when necessary.

Pyrolysis can be performed in batch reactors, continuous reactors, and fluidised bed reactors. There are advantages and disadvantages to each reactor type, depending on the scale and distribution of the product. Chemical recycling will most likely succeed commercially with continuous reactors, which offer significant economic and efficiency advantages. As an example, if one is favouring syngas as the main output, continuous phase reactors should be used (with up to 1000 kg/hr swallowing capacity, and multiples of 1000 kg/hr units up to 5 tph), then flash pyrolysis is optimal and takes up less real estate in a vertical solution. Phase pyrolysis is frequently the best solution for producing liquid fuels.

For small-scale operations and research purposes, batch reactors are relatively simple and low-cost. Their low throughput and lack of continuous operation make them November 2023 20 HYDROCARBON ENGINEERING

less suitable for large-scale commercial applications.

Therefore, batch reactors are not recommended for commercial use.

Continuous reactors, such as rotary kilns and screw reactors, provide higher throughput and more consistent quality. However, they are more complex and require higher capital and operational costs. Due to their ability to continuously process large volumes of feedstock, continuous reactors are more suitable for large-scale commercial applications.

In fluidised bed reactors, heat and mass are transferred more efficiently and uniformly, subsequently resulting in a more efficient and uniform conversion of feedstock. Suitable for the pyrolysis of a wide range of feedstock types, they have been successfully used in commercial-scale operations.

As opposed to other reactor types, fluidised bed reactors require more capital investment and are more complex. A fluidised bed requires a continuous homogenous feedstock, whereas alternatives described above can be more flexible with feedstock preparation.

Petrochemical outputs and applications Pyrolysis produces three types of products: gaseous, liquid, and solid. The petrochemical outputs from pyrolysis have a wide range of applications across various industries, including energy production, petrochemical feedstocks, and chemical intermediates.

The gaseous products of pyrolysis are carbon monoxide, hydrogen, methane, and other hydrocarbon gases. Once purified, these gases can be used directly as fuels or upgraded to liquid fuels after being purified.

Hydrogen can be used for energy production and as a feedstock in various chemical processes. Combined with nitrogen, it produces ammonia, an essential fertilizer component. It can also be used in fuel cells to generate electricity.

Methane, another gaseous product of pyrolysis, can be used as a fuel or feedstock for chemicals such as methanol and formaldehyde. In addition, methane can be converted into synthetic natural gas (SNG) and injected into natural gas pipelines.

Other hydrocarbons, including ethylene, propylene, and butenes, can also be obtained from pyrolysis depending on the process parameters. Further processing of these hydrocarbons can create valuable chemicals and materials, such as plastics, solvents, and adhesives.

Liquid products from pyrolysis are composed of a complex mixture of organic compounds called pyrolysis oil or bio-oil. This oil can be separated into various fractions, such as naphtha, kerosene, and diesel, which can be further refined and used as fuels or chemical feedstocks.

Pyrolysis oil is a complex mixture of organic compounds, including alcohols, acids, ketones, and hydrocarbons. It can be upgraded through processes such as hydrotreating, esterification, and distillation to produce a range of valuable chemicals and fuels. Alternatively, pyrolysis oil can be used directly as a fuel for heat and power generation in industrial furnaces and boilers.

Pyrolysis oil can be distilled into different fractions, such as naphtha, kerosene, and diesel. As a feedstock for

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Petrochemical outputs from pyrolysis, such as ethylene, propylene, and naphtha, can be used as feedstocks in the production of various chemicals, plastics, and materials. This helps to reduce reliance on fossil fuels and promotes a more sustainable and circular use of resources.

Several chemical intermediates can be obtained from pyrolysis, including methanol, formaldehyde, and acetic acid. These intermediates can be used as building blocks for the synthesis of a wide range of chemicals and materials, such as adhesives, solvents, and coatings.

Benefits of pyrolysis-based chemical recycling include: nn Waste plastic valorisation: pyrolysis enables the conversion of waste plastics into valuable petrochemical outputs, providing an alternative to landfilling and incineration. This not only helps to reduce the environmental impact of plastic waste but also contributes to resource recovery and the circular economy. n Resource recovery and circular economy: by converting waste plastics into valuable chemicals and materials, pyrolysis promotes resource recovery and supports the circular economy. This helps to reduce reliance on fossil fuels, conserve natural resources, and minimise the environmental impact of waste disposal. n Environmental impact reduction: pyrolysis-based chemical recycling can help to reduce greenhouse gas (GHG) emissions and other environmental pollutants associated with the production and disposal of plastics. By utilising waste plastics as feedstocks, pyrolysis contributes to the reduction of the carbon footprint and promotes a cleaner, more sustainable environment. n Energy security and independence: Figure 1. Facility under construction, schematic illustration for mixed the petrochemical outputs from plastics with PVC to HCL and electricity. Commissioning scheduled for pyrolysis, such as hydrogen, January - February 2024. methane, and pyrolysis oil, can be used as alternative fuels for heat and power generation. This helps to reduce dependence on fossil fuels and contributes to energy security and independence. steam crackers, naphtha can be used to produce olefins and aromatics, which are building blocks for petrochemicals. Kerosene and diesel fractions can be used as blend-ready fuels or further processed into other chemicals.

Solid products from pyrolysis mainly consist of char and inorganic residues. Char is a carbon-rich solid product obtained from pyrolysis, which can be used as a solid fuel for heat and power generation. It can also be processed into activated carbon, which has applications in air and water purification, as well as in the production of catalysts and adsorbents.

Inorganic residues, such as metals, glass, and minerals, are the non-combustible components of the waste plastics that remain after pyrolysis. These residues can be used as fillers or additives in construction materials, such as cement, concrete, and asphalt, or as raw materials in the production of glass and ceramics.

Gaseous and liquid products from pyrolysis can be used as fuels for heat and power generation in industrial furnaces, boilers, and engines. Solid products, like char, can also be used as a fuel in certain applications, contributing to energy security and independence.

Challenges and prospects

Figure 2. Facility under construction, schematic illustration for mixed plastics to liquid fuels. Commissioning scheduled for December 2023.

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The pyrolysis process faces several technical challenges, including feedstock heterogeneity, product separation and purification, and catalyst deactivation. To be successful at a commercial scale, these challenges must be overcome.

In the case of mixed plastics with PVC, pre-pyrolysis can be used to drive off only the chlorine compounds and convert them to saleable HCl by adjusting the temperature. In the case of

Let ProTreat® Be Your Guide a liquid fuel application, the remaining PVC fraction can be pyrolysed at a medium temperature or high temperature to produce gas and then electricity as the primary output.

Figure 1 is an example of a mixed plastic (with PVC) facility being installed in the US. It is common for waste plastics to be heterogeneous, consisting of a variety of polymers and additives.

Inconsistencies in quality and distribution can result from this heterogeneity. By producing uniform feedstocks for pyrolysis, sorting and cleaning can help address this challenge. Mixed plastic waste streams can also be managed using multiple strategies, such as removing chlorine from the waste stream prior to entering the pyrolysis retort in the case of medical waste with PVC included. By adjusting temperature and residence time based on predictive analysis of visual and infrared data, in conjunction with sensors and other available and identified data, multilayer machine learning with real-time predictive analysis may be the answer to improve efficiencies and output quality.

To achieve high-quality petrochemical outputs, complex mixtures of products obtained from pyrolysis must be separated and purified efficiently. For pyrolysis-based chemical recycling solutions to remain viable and continue to evolve, cost-effective and energy-efficient separation techniques and automated monitoring will be essential.

Pyrolysis catalysts can be deactivated by coke formation or metal contamination. Pyrolysis will be more efficient and longer lasting if catalysts with improved stability and resistance to deactivation are developed.

The commercial viability of pyrolysis-based chemical recycling depends on factors such as capital and operating costs, system design, product yields, and market prices. It may be necessary to innovate reactor designs, catalysts, and process optimisation to overcome these economic challenges.

Regulatory policies and regulations supporting waste reduction, resource recovery, and circular economies will be essential to the adoption of pyrolysis-based chemical recycling. Future investments in recycling infrastructure, incentives for research, and standards for recycled products will also contribute to the success of this initiative.

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ack in 2019, the changing landscape for global refining presented a series of significant challenges, even before the complications and shifts of a global pandemic were a consideration. Refiners needed hydrocracking technology and catalysts that were able to meet new requirements from changing product demands.

These included shifts towards increased petrochemical production, producing greater quantities of more differentiated fuels and lubricant base oils.

Collectively, refiners needed catalysts that provided flexibility for the volatility presented by changes in feeds and product markets. They were also driven by a need to improve efficiency and maintain a licence to operate under new regulations and requirements. Finally, they needed technology that positioned their refinery assets to meet the needs of the energy transition. The ability to process heavier, larger molecules found in opportunity crudes and difficult feeds was a key constraint and a driver for refining futures and sustainability.

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This article profiles the scientific innovation behind improved hydrocracking catalysts, introduced in 2020, that contain new nano-engineered technology offering better accessibility for larger molecules. Additionally, it illustrates how refiners are using these products in the real world, and the impacts the catalysts have had on their performance.

The original R&D programme Launched in 2020, the Molecular Access Catalysts for Hydrocracking (MACH) from Shell Catalysts & Technologies is the result of a five-year R&D journey. MACH is a nano-engineered technology that enables feed molecules to be converted more efficiently into high-quality fuels, lubricants and petrochemical products, thereby helping refiners to meet their strategic objectives.

The researchers set out to create a new zeolite material that would facilitate better conversion of larger molecules to improve hydrocracking efficiencies. To achieve this, they developed the concept of mesoporous zeolites. In all

Jeff Pro and Johan P. Den Breejen, Shell Catalysts & Technologies, discuss how nano-engineered zeolite catalyst technology is unlocking value for modern hydrocrackers. hydrocracking catalysts, the zeolite component is key to the conversion activity and efficiency.

In a conventional hydrocracker with lighter feeds, the molecules are relatively small and can enter and leave the zeolite structure without hindrance. However, refiners are attempting to process increasingly large or heavy molecules with elevated boiling points, and the mobility of these molecules into and out of the zeolite matrix is reduced. This can lead to unbalanced conversion of the feed, with undesirable over-cracking and gas formation.

A conventional Y-zeolite contains a network of small micropores approximately 0.7 - 0.8 nm, which result from the synthesis process. These are effective for general reactions; however, they are not optimal for cracking large molecules such as those found in heavy vacuum gas oil (HVGO) as the diffusion of these molecules in the matrix is slow. The researchers developed a solution involving a new technology that introduces ordered mesopores into the zeolite crystals (Figure 1). These are nano-engineered structures with a regular

distribution of pores of approximately 4 nm, or five times the size of the ordinary micropores.

The new zeolite is a ceramic crystalline nanofoam and the effect, in reaction engineering terms, is that larger molecules pass through an order of magnitude fewer narrow passages, boosting the effective diffusion rate into the crystal structure by a factor of nine. The outcome is that the heaviest molecules are converted in better balance with the lighter part of the feed, resulting in a step improvement in performance.

Pilot plant validation of the new technology Following the development of the prototype catalysts, the R&D team set out to demonstrate some of the application scenarios in pilot laboratory units. The work was used to validate the technology for unit scenarios in which a clear advantage was anticipated. It included options to enhance the middle distillate yields for existing units, to process heavier

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feeds, and to maximise heavy ends conversion and product quality. Three pilot plant scenarios were used to validate the performance of the catalyst technology.

technology for both the cracking reaction and the targeted hydrogenation of the desired molecules in a conventional scenario in which it replaced a standard product.

Scenario 1

Scenario 2

To explore the advantage that the new technology can offer for enhancing middle distillate yields, the first test scenario was set up to maintain typical operating feeds, temperatures and conversion levels. The middle distillate selectivity when using the new catalyst was 1.5 - 2% better in terms of total yield, as shown in Figure 2. Additionally, the product had a higher diesel to kerosene ratio with significantly less gas make and a measured improvement in unconverted oil (UCO) viscosity index (VI). These properties improved by about five points, and the UCO had a higher hydrogen content. The demonstration highlighted the efficiency of the catalyst

The second scenario was set up to investigate the performance of the new catalyst with a higher-severity feed.

In this system, the feed severity was increased by including 30% deasphalted oil.

The results of this test indicated a lower total deactivation rate for the new catalyst, observed in terms of the temperature required (Treq) for a yield of 45 wt% on feed (wof%). The deactivation rate of the new catalyst system was appreciably lower, 1.1°C vs 1.5°C per month (Figure 3).

Furthermore, an increased heavy end conversion for the new catalyst resulted in higher total middle distillate yields. The total conversion of the residue molecule material was markedly higher with the new catalyst system. Analysis of the spent catalyst after run completion also revealed that the coke deposition for the modified zeolite catalyst was significantly lower than that for the conventional zeolite.

These results support the observations of lower deactivation rate and increased heavy end conversion during the run, and they illustrate how the revised pore size distribution facilitates the processing of molecules that are difficult to process with conventional hydrocracking catalysts.

Scenario 3

The third scenario mimicked the use of the new catalyst technology in hydrocracking second-stage service. It used UCO feed from a first-stage unit that was operating at about 50% total conversion. The results indicated the same higher levels of aromatic saturation in the diesel fraction that were Figure 1. The nano-engineered zeolite structure in the observed in previous scenarios. The higher saturation new catalysts. resulted in a 6% volume swell for the diesel fraction, a significant upgrade for the diesel products.

The same improvements in heavy end conversion and middle distillate yield were observed, again with a higher diesel-to-kerosene Figure 2. Middle distillate selectivity (left) and UCO VI (right). ratio. The operation of the new catalyst in the second stage was very stable and had higher activity.

One of the most promising results that emerged from this trial was a lower level of polycyclic aromatics (PCA) generation in the Figure 3. Catalyst deactivation rate (left) and improved residue molecule conversion (right).

UCO. November 2023 26 HYDROCARBON ENGINEERING

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PCA propagation ultimately limits the operating temperature and the total cycle length for a second-stage unit, so lower PCA generation has huge implications for second-stage operations, particularly when processing heavy feeds.

Real-world examples of performance Although the application scenarios generated great enthusiasm and excitement, the question remained: would it work in the real world? The references from three early adopters of the new technology confirm that it does.

Case study 1

A refinery in Asia selected modified zeolite catalyst Z-HD27 for a second-stage reactor with the goals of improving the longevity and the conversion of the second stage and enabling the unit to operate at higher severity scenarios. In preparation for an overall shift in feed for the entire unit, the new second-stage catalyst was a key part of an overall upgrade package that included changes to the pre-treat and the first stage. The principal results from this application included a 7% increase in total diesel yield and the ability to increase the operating conversion to 98%.

The changes also enabled an increase in capacity. The unit was able to raise throughput by up to 20%. Additionally, the change in the catalyst system provided the flexibility to

process advantage crudes. The unit was able to process an available coker gasoil stream and take the feed-to-product upgrading into a new regime. In the second stage, the Z-HD27 catalyst operated at a lower weighted average bed temperature (WABT), thereby relieving some of the heater constraints that the unit had faced in previous cycles. In the normal modes of operation for this unit, overall middle distillate and diesel yields were improved, as shown in Figure 4.

Case study 2

In this case, the new catalyst technology was selected as part of an overall catalyst upgrade package to enhance middle distillate yields, provide feed flexibility and the ability to process the higher level of recycle present as part of the unit’s operation. The unit benefited with an 8 - 9% higher overall middle distillate yield and resulted in a new record-high total yield. Conversion increased to more than 98% when operating in full recycle mode. Furthermore, the catalyst exhibited excellent stability throughout the first nine months of operation.

The performance graph for case study 2 (Figure 5) highlights the enhanced middle distillate yield performance throughout the cycle. The right-hand portion of the graph indicates when the shift to higher conversion and higher recycle took place.

Case study 3

Figure 4. Case study 1 improved total diesel yields.

Figure 5. Enhanced middle distillate yields in case study 2.

November 2023 28 HYDROCARBON ENGINEERING

In this case study, a European refiner used MACH catalyst in its hydrocracker. The refiner selected a modified zeolite catalyst for its hydrocracker to increase the overall middle distillate yield for fuels application and to improve the VI for its lubricant base oil feed. As in case study 2, Z-MD17 was chosen as the primary cracking catalyst, but for this unit it was directly replacing a conventional Z-MD catalyst product.

This case study provides a true representation of shifting from a conventional Z-MD product to the new Z-MD17 nano-engineered catalyst. The performance

well as the viscosity improvements for the UCO. As seen in Figure 6 (a), there is a 3% higher middle distillate yield for the fuel outputs with, simultaneously, an improved VI for the UCO (Figure 6 (b)). The blue dots indicate the VI of the feed, shown as a benchmark, with the improved VI of the Figure 6. Case study 3 enhanced middle distillate yield and improved UCO VI. UCO. This highlights the upgrade from a lower viscosity feed to the valuable higher viscosity output. highlights for this unit included a 2 - 3% increase in total middle distillate yield but also a significant boost in the UCO VI. The unit was able to increase the output VI despite significant Conclusion drops in the feed VI. This reveals the benefits of improved The MACH technology catalyst line addresses emerging hydrogenation provided by the new catalyst. The catalyst refining trends and helps to prepare hydrocracking units for the system has also enabled greater flexibility, improving the ability energy transition. These nano-engineered catalysts were to process and upgrade difficult opportunity feeds while developed with several operating improvements in mind, and meeting both the fuels target and the UCO target for lubricant specifically to enhance the upgrading of heavier feeds. base oils. It is an example of the new catalyst technology Since their initial launch, catalysts have been used to providing the targeted conversion and hydrogenation that was unlock the value of hydrocracking units. The benefits have observed during development testing. included increased throughput and operating conversion rates, The performance graphs for case study 3 (Figure 6) highlight enhanced middle distillate and diesel yields, and improved VI the middle distillate yield improvement for the fuels cut, as for lubricant-based feed oil production.

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Hernando Salgado, Abdallah Al-Zyoud, Modesto Miranda, Emmanuel Smaragdis, Minwoo Kim and Corbett Senter, BASF, discuss how the FCC process, and associated catalyst technologies, are positioned to sustain the future refining-petrochemical business as it transitions to a more chemicals-oriented market.

H

istorically, the demand for transportation fuels has been the main driver for oil refiners to maximise production of gasoline and diesel products to improve refinery margins. Many investments in downstream refining projects were executed in order to meet increasing demand for transportation fuels and improve the quality of finished products, therefore meeting changing

consumer and regulatory requirements. As a result, fluid catalytic cracking (FCC) units have played a leading role as one of the main producers for transportation fuels in refineries producing mostly gasoline.

Most recent market projections predict that the demand for transportation fuels will gradually drop in the coming years as a result of new regulations to reduce carbon HYDROCARBON 31

ENGINEERING

November 2023

emissions and an increase in electric vehicles in the light-duty automotive fleet. This will reduce the demand of traditional transportation fuels (such as gasoline and diesel) and will put refiners under increased pressure to lower their carbon footprint. At the same time, many outlooks forecast an increased demand for petrochemical products in the future.

This market trend offers refiners an opportunity to better integrate their facilities with petrochemical complexes. If market projections are true, this would increase refining margins and increase refiner competitiveness.

This article will examine how the FCC process, and associated catalyst technologies, are positioned to sustain the future refining-petrochemical business as it transitions to a more chemicals-oriented market. Process configurations and the latest innovations in FCC catalyst and olefins additives design will be discussed, including ZSM-5 zeolite-based catalysts, which can be utilised to maximise chemicals production from FCC units to feed downstream petrochemical complexes.

In addition, three case studies based on trials in commercial FCC units integrated with petrochemical complexes will be discussed. These provide examples of how the correct catalyst technology and unit configuration can be combined to help refiners maximise the production of precursors of petrochemicals, enhancing their competitiveness in an increasingly chemicals-driven world.

Classical and crude oil to chemicals (COTC) FCC configurations FCC units have traditionally been operated as the core unit in fuel-oriented refineries to maximise yields of transportation fuels, especially gasoline. Other non-motor vehicle fuel FCC products were used as fuels for process heaters (e.g., refinery off-gas (ROG)), as heating media (e.g., LPG), or as bunker fuel (e.g., the main column bottoms (MCB)). The typical FCC unit configuration in these fuel-oriented refineries is shown in the blue box in Figure 1.

Since transportation fuels are expected to be gradually replaced by more sustainable alternatives such as electric vehicles, biofuels, and even natural gas, refiners are challenged to change their product slate and integrate with

petrochemical complexes to maximise petrochemical products. Consequently, the term crude oil to chemicals (COTC) is now widely used to describe the overall conversion of crude oil into petrochemical precursors and products. It is considered a way that refiners can help satisfy the growing market demand of such products and achieve higher margins.

Within the refinery, the FCC process flexibility can support the production of some of the most important petrochemical building blocks, such as light olefins and aromatics, as the nature and chemistry of the cracking reactions in FCC leads to a wide range of these products.

As such, FCC and residue FCC (RFCC) units have a particular advantage over other process technologies in their ability to adapt to maximise light olefins and aromatics. It must be noted that to maximise production of these molecules, the units must be equipped with certain process facilities to separate the olefinic building blocks, so that these can be sent to downstream units for conversion into final products.

Examples of how such separation units can be used to separate FCC products are shown in the green box in Figure 1 by the cryogenic distillation and C3/C4 separation.

The items in the green box in Figure 1 also show ways that the FCC unit can be integrated to further boost petrochemical products and precursors. As previously mentioned, not only can light olefins be produced from FCC, but also from other streams, such as mid-heavy naphthas, which contain aromatics. These streams could be processed in a reforming unit and subsequently into BTX extraction.

Similarly, bottoms (slurry) from FCC can be used as a raw material to produce carbonaceous chemical products, such as carbon black and anode grade coke, increasing the conversion to chemical products to as high as 85 - 90%, depending on the process conditions and level of integration.

Mechanism to produce light olefins in an FCC unit using ZSM-5

Adding separation and process steps to maximise petrochemical precursors from FCC units is only possible because of the ability of an FCC to make light olefins via cracking. Light olefins are produced in an FCC or RFCC unit in a two-step approach. The first step is the primary cracking of the feed on the matrix and the Y-zeolite surfaces of the catalyst, where some light olefins are produced. However, olefins maximisation is accomplished in secondary reactions, where light naphtha reactor effluent molecules are further cracked on a to fractionator catalyst, or more selectively by an olefin flue gas additive containing ZSM-5 zeolite. This stipper results in smaller molecules, namely catalyst propylene, butylenes and even ethylene, regenerator depending on the process and catalytic riser reactor air conditions.

An important characteristic of the catalytic system in this two-step approach fresh feed dispersion to maximise light olefins is the base steam catalyst’s ability to maximise the light olefin precursors which exist in light Figure 1. Typical configuration for fuel-oriented FCC units in blue, and naphtha.

This is needed to provide options for chemicals maximisation from FCC in green. enough material, which can be cracked to November 2023 32 HYDROCARBON ENGINEERING

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the desired petrochemical precursors with the help of an olefin additive or FCC catalyst containing ZSM-5 zeolite. This will be discussed in more detail later in this article.

Depending on the target product slate, the activity of the ZSM-5 containing catalyst can be modified. A high-activity ZSM-5 based catalyst, such as BASF ZEAL®, would be ideal to maximise propylene selectivity, and even ethylene under the correct conditions, when dilution of the FCC catalyst is a concern. A ZSM-5 additive with lower activity than ZEAL, such as BASF ZIP, would be more appropriate to balance between propylene and butylenes, or when there is less of an issue with FCC catalyst dilution.

Furthermore, ZSM-5 is a shape-selective zeolite used to design a catalyst, able to convert linear or slightly branched light naphtha olefins (as opposed to highly branched naphtha olefins) into light olefins such as ethylene, propylene and butylenes. This means that a characteristic of ZSM-5 cracking is that only naphtha molecules with a relatively low octane number (unbranched molecules) are converted to lighter products. Consequently, gasoline octane is increased since the concentration of highly branched olefins, which are geometrically restricted from cracking by ZSM-5, is increased in the light naphtha fraction. Similarly, aromatic molecules already present in the medium and heavy naphtha fractions are not cracked by either zeolite-Y or ZSM-5. Consequently, there is immense potential for these naphtha fractions to be used as a source of aromatics, especially toluene and xylenes,

in aromatics plants. Pretreatment of these fractions, especially of medium cut naphtha, might be required to remove the remnant olefinic compounds prior to the reforming section of such plants.

Tuning conditions to maximise olefins production Feed properties

Hydrogen content in feed is one of the most important indicators of the potential for light olefins yield in an FCC unit, and FCC feeds coming from a more paraffinic crude source are preferred for olefins maximisation due to their increased potential to easily crack to lighter products.

Unsurprisingly, hydrotreated feeds demonstrate an even greater yield to light olefins when compared to their non-hydrotreated counterparts. Industrial data shows hydrotreated feeds reaching ~5 wt.% more propylene, compared with non-hydrotreated feeds under similar conditions.

Another aspect of the feed affecting the olefins yield is the impact of the feed properties on the unit heat balance.

Residual and more contaminated feeds tend to have a higher content of Conradson Carbon and contaminant metals.

Therefore, they tend to generate more heat during catalyst regeneration, potentially increasing regenerator temperature.

This results in a need to limit reactor outlet temperature (ROT) and/or catalyst circulation rate (CCR). As will be discussed in a later section, ROT is a key factor impacting the light olefins yield. Therefore, heat sinks such as catalyst coolers, could be used to help process residual feeds. In doing this, the regeneration temperature can be controlled to avoid negative effects on ROT or CCR, and therefore, not reduce conversion.

Catalytic system

Figure 2. Laboratory study demonstrating propylene yield trend with increasing olefins additive.

Figure 3. Simplified rules of thumb for catalyst design to maximise petrochemical precursors.

November 2023 34 HYDROCARBON ENGINEERING

The olefin additive activity and the base catalytic system design are the most critical factors from a catalyst perspective to maximise light olefins in a given unit. The previous section of this article discussed how a high activity olefins additive helps with light olefins maximisation.

However, the correct activity of olefins additive in the unit catalyst inventory will depend on the target for light olefins yield, as well as the desired selectivity to ethylene, propylene, or butylenes.

In general, for light olefins maximisation, an olefin additive concentration level of 10 - 25% is used in the industry. It must be noted that, as discussed previously, the more the hydrogen content in the feed, the more the potential for light naphtha as light olefins precursor. Therefore, a higher concentration of olefin additive can be used. On the other hand, while ZSM-5-zeolite containing additives tend to maximise propylene, it has been observed that high activity additives tend to also increase ethylene, whereas moderate activity additives tend to reduce ethylene in favour of butylenes.

In practice, the activity of any olefins additive in the catalyst inventory can be maximised based on the olefins concentration in the remaining light naphtha. A point will be reached where there are very few olefins remaining in the

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naphtha phase to be cracked by an olefin additive. At this point, increasing olefins additive content leads to minimal increases in light olefins yields, as depicted in Figure 2. This figure shows a laboratory study in which the olefins additive concentration was gradually increased with all other variables being kept constant. In this case, diminishing returns of the olefins additive addition can clearly be seen after 6 - 10%.

The zeolite-Y based catalyst must also be designed in a way that will maximise olefins yields. One important property to consider is the rare earth oxides (REO) content. Although REOs are used to stabilise the base catalyst, they also promote hydrogen transfer reactions which tend to saturate olefins and reduce light olefins yields. Therefore, the REO concentration in the base catalyst should be carefully chosen to maximise olefins yields while maintaining the desired catalyst activity. This will depend on several factors, including the level of contaminants in the equilibrium catalyst (ECAT), particularly vanadium and sodium.

On the other hand, feed properties and secondary targets (after light olefins maximisation) will further define the catalyst

Table 1. Operating conditions, feed properties,

and product yields of case study 1 Operating conditions Riser outlet temperature (°C)

520

ECAT activity (wt.%)

70.5

Catalyst addition rate (kg/t feed)

0.35 Feed properties

Specific gravity

0.904

Concarbon (wt.%)

0.21 FCC product yields

Dry gas (wt.%)

3.8

C3= (wt.%)

11.3

C4= (wt.%)

7.8

Total LPG (wt.%)

29.5

LCO (light cycle oil) + gasoline (wt.%)

54.2

Slurry (wt.%)

6.9

technology and functionalities of the base catalyst. Figure 3 summarises some typical features of the base catalyst depending on feed properties and secondary targets.

As seen in Figure 3, when processing resid feeds, functionalities such as enhanced coke selectivity and metals passivation also need to be considered as part of the base catalyst. Several BASF catalytic technologies include these functionalities such as Valor®, Boron Based Technology (BBT)®, Altrium® and Fortress® NXT. These catalyst technologies can be used in combination with an olefins additive to maximise conversion of residual feedstock to light olefins. Furthermore, BASF Fourtitude® catalyst, based on the Multiple Framework Topology (MFT) platform, can be used to maximise conversion of resid feeds to lighter olefins with increased butylene selectivity.

Process conditions There are several process variables that can be tuned to manipulate light olefins. The most impactful ones are discussed below:

Reactor outlet temperature (ROT)

For light olefins maximisation, ROT will depend on the specific targets and design limits of a given unit, although a general indication for propylene maximisation would be 540 - 550˚C (1000 - 1025˚F) based on industry practice. Some units targeting ethylene, specifically when integrated with steam cracking units, might target even higher temperatures in the range of 560 - 565˚C (1040 - 1050˚F). Other considerations, such as feed properties, are also important to set a target for ROT, as heat balance must be considered.

Furthermore, there are special unit designs to crack naphtha streams rather than vacuum gasoil (VGO) or residues. For these special designs, ROT is typically in the range of 560 - 650˚C (1040 - 1200˚F), to achieve maximum naphtha conversion depending on whether the target is to maximise propylene or ethylene.

Hydrocarbon partial pressure

Light end products such as ethylene, propylene and butylenes are maximised at lower hydrocarbon partial pressure in the riser/reactor section. Hydrogen transfer reactions are expected to be reduced under such conditions, preserving the already produced olefins and increasing the thermodynamically favoured cracking reactions.

A variable that heavily influences the hydrocarbon partial pressure is the steam used, typically depicted as a percentage on fresh feed, including all steam sources used in the riser or reaction section, such as injection (or atomising) steam and lift steam. Typically, FCC units maximising light olefins use more than 10% steam on fresh feed, as increased steam increases the production of light olefins.

Process technology (hardware design)

Figure 4. Fourtitude®/ZIP vs a non-BASF catalyst system from case study 2.

November 2023 36 HYDROCARBON ENGINEERING

The process technology design will also contribute greatly to light olefins maximisation. Currently a variety of such designs for FCC and RFCC units exist. Some key design features to consider are: nn Secondary riser dedicated to cracking recycled light naphtha or C4= oligomers produced downstream of the

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Table 2. Operating conditions, feed properties, and yields of two catalysts used in case study 3 Operating conditions

Incumbent

BASF MPS-R

Riser outlet temperature (°C)

536

537

ECAT activity (wt.%)

73.5

72.5

Catalyst addition rate (kg/t feed)

2.3

2.0

Feed properties

Incumbent

BASF MPS-R

Specific gravity

0.914

0.915

Concarbon (wt.%)

3.6

3.7

FCC product yields

Incumbent

BASF MPS-R

Dry gas (wt.%)

4.2

3.2

C3= (wt.%)

8.1

9.4

C4= (wt.%)

7.9

9.7

Total LPG (wt.%)

24.6

26.9

LCO + gasoline (wt.%)

55.1

54.7

Slurry

7.1

7.0

FCC unit on the olefins additive framework in the catalytic system. The ROT of the secondary riser will depend on the targeted product and can vary between 560 - 650˚C (1040 - 1200˚F). nn Bed cracking at the main riser termination: typically, this is a device used for maximising ethylene since it extends the residence time of the cracked products, including naphtha, with the catalyst, providing enough time for secondary reactions on the olefins additive framework.

This is mainly used with hydrotreated VGO or straight run VGO, rather than residues, since it has a significant impact on the coke formation and, therefore, the unit heat balance. nn Catalyst cooler system: this is an important feature when it comes to residue processing. Typically, VGO or hydrotreated VGO units do not need a catalyst cooler system to maintain proper heat balance.

Overall, the combination of process conditions, feed type, process design, and catalyst + additive system selection can result in light olefins yields > 40 wt.%.

Case studies In this section, three brief case studies will be shown from two different refinery complexes that are integrated with petrochemical units. Each case will show how refinery configuration, process conditions, and catalyst are all tuned to meet the targets of the refinery.

The first example is a refinery in Europe which supplies propylene to an external petrochemical site. It is a complex refinery with integration of petrochemical units. The FCC processes a relatively light feed (a mix of VGO and hydrotreated feed). Typical operating conditions, feed properties, and product yields can be seen in Table 1.

The refinery uses BASF Maximum Propylene Solution Catalyst (MPS), which offers high surface area, low REO, and pre-blended high activity olefins additive (BASF ZEAL) to maximise the production of propylene. Further, Z/M has been tuned to maximise coke-selective bottoms upgrading November 2023 38 HYDROCARBON ENGINEERING

without sacrificing light olefins production. This allows for C3= yields > 11 wt.% using a conventional FCC, single-riser unit, and no external ZSM-5 additions.

The second case study is a residue FCC unit in the EMEA (Europe, Middle East, and Africa) region. This FCC aims to maximise C3= and C4= yields with improved C4= selectivity to satisfy the demand of a downstream petrochemical facility, while maintaining high throughput of a challenging, untreated feed (~4 - 5 wt.% CCR and ~8,000 Ni+V on ECAT). The FCC is a special design for light olefins maximisation, and decided to use BASF Fourtitude catalyst, designed to maximise C4= selectivity and production from resid FCC feeds, and a BASF olefins additive ZIP. The change in yields using the new catalyst and additive system can be seen in Figure 4.

With this operation, C3= and C4= yields exceeded 13 wt.% and 11 wt.%, respectively. In addition, the naphtha research octane number (RON) increased above 95 and less slurry was produced. Therefore, more added value for the petrochemical products chain and higher fuel quality were achieved. The yield shifts indicate the importance of choosing the correct catalyst and additive for crude-to-chemicals applications. This case demonstrates that all parameters need to be optimised together since, despite having a unit designed for maximum LPG olefin yield, the olefins yields were not optimised until the correct catalyst was chosen.

The third example is a residue FCC unit in Asia. It is a conventional FCC which processes a challenging, untreated resid feed (2 - 4 wt.% CCR and 4000 - 7000 Ni+V on ECAT), targeting maximum C3= BASF proposed to replace the incumbent catalyst with BASF MPS-R technology (maximum propylene solution for resid), which is designed with high surface area, low REO, pre-blended high activity olefins additive (BASF ZEAL) and metals passivation technology to maximise C3= selectivity and production from resid FCC feeds. A comparison of operation and yields between the two trials is show in Table 2.

While processing similar feed, the use of BASF MPS-R increased C3= yields to >9 wt.%. This was accomplished using a lower catalyst addition rate and with less dry gas produced – both a result of the strong metals passivation technology used in the BASF MPS-R technology.

Conclusions Many refiners plan to shift their focus from fuels to chemicals production to meet the expected market increase in petrochemicals demand. As a result, refiners need increased conversion of their processed crude oil to chemicals to achieve these goals. To tackle this, refiners need to shift output to light olefins, as well as maximise integration with other units, adding value to what would otherwise be fuel or residual streams. FCC catalyst and additive technologies are one of the main handles to address this need. The inherent flexibility of the FCC units and the continuous development of FCC catalyst and additive technologies allow refiners to increase the value of their output and meet their economic goals in a more chemical-oriented market.

Gabriel Buffin, Bijay Barik and Laurent Watripont, Axens, discuss how isomerisation can open up a world of opportunities for a more sustainable refining industry.

U

pgrading light hydrocarbon (C4 - C6) streams in refineries and petrochemical plants is a process that has gained increased commercial application over the past decades.

Isomerisation remains the main technology driver for upgrading light hydrocarbons, as demand for gasoline

and petrochemicals, both in terms of quality and quantity, have experienced steady growth in most regions of the world.

C4 isomerisation technology prepares feedstock for the alkylation process, producing gasoline pool blending stock. C5 - C6 light naphtha isomerisation technology

HYDROCARBON 39

ENGINEERING

November 2023

based with zeolite, mixed-metal oxide (zirconia), and chlorinated-alumina. All types of catalyst contain platinum. Deep feed pre-treatment to remove sulfur, nitrogen and oxygenates is necessary for all types of catalyst to ensure efficient performance. Therefore, the isomerate produced through the isomerisation process is a sulfur-free blending component that helps to meet the lower sulfur specification of gasoline pool.

Over the past years, there has been a steady evolution in both the flow scheme and catalysts used in the light naphtha isomerisation processes. Depending on isomerate research octane number (RON) target, flow scheme enhancements including the addition of super-fractionators such as deisopentanisers (DIP), deisohexanisers (DIH), or the use of a molecular sieve, help to separate iso and normal paraffin. All of these measures help to recycle the unconverted paraffin back to the reaction section for further conversion.

Catalyst advancements include the use of new materials and base formulations to increase activity, selectivity, and the life of catalysts.

Irrespective of flow scheme improvements to meet isomerate RON target, the choice of catalyst also has an important influence on process scheme configuration.

Depending on the catalyst selected for the isomerisation process, the key operating parameters and facilities needed for feed contaminants management can vary.

The following section shows a Figure 1. Isomerisation typical scheme with zeolite/sulfated zirconia simplified flow diagram for a catalyst. Note: the dryer in the recycle loop is only for process scheme with once-through isomerisation process sulfated zirconia catalyst. scheme involving a different catalyst system (Figures 1 and 2). plays a key role in meeting octane demand in the gasoline pool for cleaner fuels and premium gasoline grades.

The isomerisation process involves the skeletal arrangement of a straight chain paraffin to a more highly branched paraffin with the same carbon number. The isomerisation reaction is initiated by an acid function promoted catalyst. Apart from production of higher-octane isomers, the isomerisation process is also one of the simplest and most economical ways to manage benzene constraint in the gasoline pool, as all types of isomerisation catalyst perform the benzene saturation in the first place.

Several paraffin isomerisation technologies are available on the market today, along with a wide variety of catalyst technologies. Catalyst formulation may be

Isomerisation process: the basics

Figure 2. Isomerisation typical flow scheme with chlorinated alumina

catalyst.

November 2023 40 HYDROCARBON ENGINEERING

Isomerisation reactions are thermodynamically equilibrated reactions. Equilibria for the branched paraffin isomers are generally favoured by low temperatures.

Figure 3 illustrates the thermodynamic equilibria of C4, C5 and C6 paraffin. These equilibrium trends depict that the most active catalyst, when all other process variables are identical, is capable of producing the highest proportion of desired isomers. Apart from favourable equilibria for desired isomers at low temperature, higher catalyst activity helps to have higher selectivity (C5+ yield or C4 retention), lower hydrogen consumption and

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operation with once-through hydrogen in the liquid phase for the C5- C6 light naphtha isomerisation scheme.

Isomerisation catalysts Chlorinated alumina

Figure 3. C4, C5 and C6 paraffin equilibria.

Figure 4. Performance ranking of isomerisation catalysts.

Table 1. Key unit configuration parameters for different isomerisation catalysts Facilities

Chlorinated alumina

Sulfated zirconia

Zeolite

Chloriding agent injection

Yes

Not required

Not required

Caustic neutralisation

Yes

Not required

Not required

Average reaction temperature (˚C/ heating medium)

130˚C/steam

180˚C/fired heater

250˚C/fired heater

Hydrogen recycle

No (once-through)

Yes (recycle gas compressor)

Yes (recycle gas compressor)

Product separator

No

Yes

Yes

Reactor effluent cooler

No

Yes

Yes

Catalyst regeneration

Not applicable

Yes

Yes

Feed drying

Yes, dryers for both light naphtha and make-up hydrogen

Most likely dryer either on recycle loop or in unit feed

Not required

Treatment of CO+CO2 in make-up gas

Yes (if in excess of 1 vol ppm)

Not required

Not required

Feed hydrotreatment

Yes

Yes

Yes

November 2023 42 HYDROCARBON ENGINEERING

Chlorinated alumina is the most active paraffin isomerisation catalyst. This type of catalyst was first developed during the Second World War and was commercially employed in the 1970s. With this type of catalyst, for a typical light naphtha feed, an octane number of approximately 70 can be increased to 82 - 84 in a once-through unit configuration. Higher isomerate octane, up to 91 - 93, can be obtained with recycle unit configuration. The C5+ yield from chlorinated alumina catalysts is generally the highest, compared to any other commercial catalyst, because of its higher catalyst selectivity.

Chlorinated alumina catalysts are not economically regenerable either in-situ or ex-situ. Therefore, they are eventually always replaced with fresh catalysts. This type of catalyst is highly sensitive to contaminants such as moisture, nitrogen and oxygenates.

As such, necessary safeguards are required to ensure a long catalyst life.

While the average life of a catalyst load is approximately five years, when operated with diligent care, a life of 15 - 20 years can be attained.

Chlorinated alumina catalysts require a continuous injection of chloriding agent (C2Cl4) to keep the catalyst in its active form.

Consequently, effluent off gas must be caustic scrubbed before it is sent to the fuel gas network.

Zeolite

Zeolitic isomerisation catalysts operate in vapour phase at higher temperatures than that of chlorinated alumina catalysts. The biggest advantage of zeolitic isomerisation catalyst is that it is not permanently deactivated by water or oxygenates and it is also fully regenerable. Therefore, the isomerisation process using zeolite catalysts does not require protection measures such as dryers and treatment for make-up hydrogen CO+CO2, as is needed for chlorinated alumina type catalysts. However, feed pre-treatment to remove sulfur and nitrogen is still required to ensure optimum performance of the catalyst. Zeolite also requires a recycle gas compressor to maintain the required hydrogen partial pressure to ensure catalyst stability and life.

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Zeolitic isomerisation catalysts can upgrade the light naphtha octane number from 70 to 78 - 79 in a once-through unit configuration. Higher product octanes (84 - 87) can be obtained in a recycle configuration.

Almost no new process units utilise this technology due to unfavorable economics. However, some revamping solutions involving the reutilisation of existing assets of other process units, such as old hydrotreaters or reformer to isomerisation services, can employ the zeolitic isomerisation catalyst.

Mixed oxide or sulfated zirconia

The sulfated metal oxide (zirconia) catalyst exhibits higher activity for paraffin isomerisation reactions when compared to zeolitic type catalysts. However, zirconia catalyst is less active and selective in comparison to chlorinated alumina. Nevertheless, with suitable

selection of catalyst quantity, zirconia catalyst has the potential to bridge the performance gap with the chlorinated alumina catalyst to a narrow margin.

Zirconia is the most recent generation of isomerisation catalysts. Similarly to zeolite catalyst, zirconia is not permanently deactivated by water or oxygenates in the feedstock. These catalysts are also fully regenerable.

Therefore, the isomerisation process using the zirconia catalyst does not require special protection, as is needed for chlorinated alumina type catalysts. Feed pre-treatment to remove sulfur and nitrogen is still required to ensure optimum performance. Zirconia also needs a recycle gas compressor to maintain the required hydrogen partial pressure to ensure catalyst stability.

Moisture has a strong inhibiting impact on the performance of the Zirconia catalyst, causing a large reduction in isomerate RON. Therefore, to ensure steady performance, drying section for unit feed is the most suitable option.

Zirconia isomerisation catalysts can increase the light naphtha octane number from 70 to 80 - 81 in a once-through unit configuration. Higher product octanes (86 - 88) can be obtained in a recycle configuration.

Figure 4 shows the performance ranking of different isomerisation catalysts available on the market and Table 1 compares the key unit configuration parameters for different types of isomerisation catalysts.

Figure 5. HCl recovery scheme.

Alumina isomerisation solution for C5- C6 light naphtha isomerisation unit Axens’ chlorinated alumina catalyst, ATIS-2L, is approximately 20˚C more active than its former generation catalyst IS-614A. This increase in activity was achieved, despite a reduction of 5% of Pt content per unit volume of catalyst, due to a specific chlorination step. Therefore, since ATIS-2L’s introduction to the market in 2003, Axens now offers an isomerisation solution with its highest active and selective chlorinated-alumina isomerisation catalyst, helping customers to minimise their carbon and energy footprints.

HCl recovery section

Figure 6. Pilot test result comparison ATIS-2L and ATIS-2Lp

catalyst with severe feed. Feed used for pilot testing has following the composition: C5 Paraffin = 28 wt%, C6 Paraffin = 31 wt%, C5 Naphthene = 6 wt% , C6 Naphthene = 28 wt%, X-Factor (C6 Naphthene + C7+) = 35 wt%.

November 2023 44 HYDROCARBON ENGINEERING

Axens’ latest technology upgrade involves the integration of a scheme to recover and recycle HCl from reactor effluent off-gas to the reaction section in order to drastically reduce C2Cl4 after consumption (Figure 5). This HCl recovery is achieved through contact of effluent gas containing HCl, with a fraction of the reaction

feedstock in a specially designed absorber column. In this process, reaction section feedstock is enriched with HCl and sent back to the reaction section. This also results in off-gas leaving the absorber column with a much lower quantity of HCl than that of the reaction section off-gas.

This facilitates the combined benefits of a decrease in the quantity of C2Cl4 needed to be injected into the reaction section, and a reduction by the same percentage of caustic needed to neutralise the remaining HCl in absorber off-gas.

To date, 16 units have been designed with the HCl recycle facility and two units have already been commissioned successfully. A chemical consumption saving in excess of 70% has already been achieved in these units.

New generation catalysts Axens has been working on the development of a catalyst with a lower platinum content. For light naphtha isomerisation applications, a low-platinum version of the ATIS-2L catalyst has been developed and tested.

ATIS-2Lp has the following main attributes: nn It contains 13% less platinum per unit volume. nn It was developed on the same alumina base and chlorination process as ATIS-2L, ensuring the highest acidic function for the isomerisation reaction.

Pilot testing on a high severity isomerisation feed (X-Factor = 36) and weight hourly space velocity (WHSV) of 2.2 has demonstrated that: nn The same iP5 isomerisation ratio can be reached by ATIS-2Lp, with an increase of only 8 - 10˚C in reactor temperature. nn The same 22DMB isomerisation ratio can be reached by an increase of about 10 - 12˚C in reactor temperature. nn The same PIN as that of ATIS-2L can be reached by ATIS-2Lp by reactor inlet temperature (RIT) increase of only 8 - 10˚C. It should be noted that the pilot test for ATIS-2Lp was carried out at severe conditions to observe the difference in performance and its resilience to refractory feed. This means that when the ATIS-2Lp catalyst is used in less severe conditions (either at lower WHSV or lower feed X-Factor), the observed activity difference will diminish. With C5 /C6 naphtha isomerisation application feed X-Factor of approximately 10 - 15 wt%, an overall RIT increase of only 5 - 8˚C will be enough with ATIS-2Lp to reach same level of performance and selectivity as that of ATIS-2L.

Carbon footprint reduction and revamping options Electrical heaters

Axens’ isomerisation technology scheme utilises steam as a heating medium. Depending on the fuel used in the steam generators, the carbon intensity of the

isomerisation process can be reduced by replacing all steam heaters with specially designed electrical heaters that are supplied with low-carbon electricity.

Axens’ electrical heater solution is based on remote electric resistance type technology that can be employed for vaporising or phase change service. In addition to reducing CO2 emissions by replacing steam heaters with electrical heaters, this helps to improve unit reliability by cutting down the source of water within the unit.

Divided wall column solution

Divided wall column (DWC) internals are specifically designed to optimise separation effectiveness in the column by having more than two product draw-offs.

Installation of these internals can help to produce high purity food or pharma grade hexane from existing deisohexaniser (DIH), or to combine duty of deisopentaniser (DIP) and deisohexaniser (DIH) in a single column. Replacing existing column internals with DWC internals can significantly save utility consumption.

Therefore, these DWC internals find applications in grass-root, as well as in unit revamps.

Conclusion Isomerisation technology has reached a high level of maturity. Nevertheless, it is important for companies to continue innovating and offering solutions that are more environmentally sustainable, oriented towards lower CAPEX and OPEX, and are operationally robust. Some of these solutions have been described in this article. Other solutions may include: nn Complete feed contaminants management suite (involving management of sulfur, chloride, arsenic, mercury, moisture and CO+CO2), for operation agility and longer catalyst life for chlorinated alumina catalyst. nn Proven unit revamp suite to meet either higher capacity or higher RON severity, or both, with innovative scheme optimisation.

Notes

PIN: paraffin isomerisation ratio, which is the sum of C5 and C6 paraffin isomerisation ratio. Calculated as:

X-Factor: sum of methyl cyclopentane (MCP), cyclohexane (CH), benzene (BZ) and C7+ paraffin and naphthenes, indication of severity or difficulty of feed to be processed in isomerisation unit and difficulty to achieve targeted isomerate RONC. iP5 isomerisation ratio: =

22DMB isomerisation ratio: =

Octane/RONC: research octane number (clear), an important property of gasoline or gasoline blending stocks, indicating its anti-knocking property. The higher the RONC, the lower the anti-knocking property and the better the fuel for the engine.

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Norbert Ringer and Christoph Krinninger, Clariant, introduce the company’s new catalytic solutions, which have the capacity to support green methanol production.

M

ethanol is one of the four critical basic chemicals alongside ethylene, propylene and ammonia. For more than 100 years, it has been used for a variety of ends, such as formaldehyde, acetic acid, and plastics. Approximately 98 million tpy is produced, nearly all of which derives from fossil fuels – either natural gas or coal. The life cycle emissions from current methanol production and use amount to approximately 0.3 Gt/yr of carbon dioxide (CO2), with production accounting for approximately 5% of total emissions in the chemical sector (see Figure 1).1 Methanol production has nearly doubled in the past decade, with a large share deriving from China’s growing methanol-to-olefins sector, and the US’ soaring natural gas supplies driven by the shale revolution.2 As a result of current trends, production could reach 500 million tpy by

2050, releasing 1.5 Gt/yr of CO2 if only sourced from fossil fuels.3 Yet the global warming issues associated with fossil fuels have forced the world to shift towards environmentally-friendly alternatives. A transition to renewable methanol – derived from biomass or synthesised from green hydrogen and CO2 – could expand methanol’s use as a chemical feedstock, and could play a larger role in decarbonising certain sectors where options are currently limited, such as transportation fuels – particularly marine.

Green methanol as a future fuel for marine transport In addition to reducing greenhouse gases, green methanol as a marine fuel can help meet the more stringent

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emission standards in Emission Control Areas (ECAs), as well as the new global emission standards set by the International Maritime Organization (IMO), which were implemented in 2020: 0.5% sulfur content in marine fuel, compared to 3.5% previously.4 With the benefit of reducing sulfur oxides (SOX), nitrous oxides (NOX) and promethium (PM), green methanol is not only less toxic than ammonia but also easier to handle due to its high volumetric energy density (4.33 kWh/l) and liquid form at room temperature (ammonia must be stored at below -33°C).

Moreover, thanks to its liquid form, green methanol is completely fungible (as with marine fuels currently available today), which means that it can be run as a dual-fuel engine while carbon-neutral supply grows.

Consequently, only minor modifications to current marine fuel storage and fuelling infrastructure will be required in order to handle methanol, resulting in relatively modest infrastructure investments compared to the substantial investments needed to build LNG terminals.

According to Maersk’s recent announcement, the shipping company entered into strategic partnerships with six companies, with the intent of sourcing at least 730 000 tpy of green methanol by the end of 2025.5 In this context, Maersk is considering the option of exclusively using green fuels such as biomethanol or e-methanol to build a new industry and send signals to those who produce green fuels.

Green methanol production pathways While today’s methanol production via renewable technologies only accounts for a little more than 1% of green methanol production, two types of net zero carbon methanol do exist, with the two renewable methanol variants being the main topic of this article. Firstly, biomethanol that is made from biomass gasification, with key potential sustainable feedstocks including forestry and agricultural waste. Secondly, e-methanol that can be produced from renewable electricity and captured CO2 – either from bioenergy with a point of source carbon capture and storage (BECCS), or from direct air capture (DAC). The latter pathway and the most mature and scalable method is the combination of water electrolysis to produce hydrogen (H2) and subsequent catalytic methanol synthesis with CO2: CO2 + 3H2 ↔ CH3OH + H2O

(1)

Challenges in green methanol production: costs and feedstock availability

Figure 1. Overview of CO2 emissions from chemical production.

Figure 2. Principal methanol production pathways. Source: IRENA.

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The main challenges associated with producing green methanol are the costs of hydrogen and CO2 as raw materials used in this method. For low-emission electricity, mature technologies such as solar, wind and hydro are in place but not yet at the necessary scale, which drives up costs for low-emission electricity, along with the cost of the electrolysers needed for hydrogen production. Furthermore, a renewable source of CO2 is essential for producing e-methanol, but qualified renewable CO2 point sources are also currently not available at the scale needed, which may increase the cost. To produce 1 t of e-methanol, approximately 10 - 11 MWh of electricity is needed, most of it for the electrolyser (approximately 9 - 10 MWh)3, and not including CO2 capture.

As for biogenic CO2 point sources, CO2 released as a result of the combustion or decomposition of biomass and its derivatives may have limited availability, and DAC is even more expensive.

With the cost of e-methanol depending to a large extent on the cost of hydrogen and CO2, and the cost of CO2 depending on the source from which it is captured, the current production cost of e-methanol is estimated

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be able to increase methanol capacity by as much as 10%, depending on the facility’s design and processes.

Green methanol production demands advanced technologies that reduce resource consumption and minimise waste creation.

Clariant’s catalysts are a possible solution for green methanol production projects, as the catalyst is well suited for CO2-rich conditions, delivering high conversion rates and showing excellent selectivity, leading to only minimal amounts of byproducts such as ethanol and Figure 3. Clariant’s MegaMax catalyst for CO2-based methanol methylformate. Moreover, the catalysts have synthesis. Source: Clariant. demonstrated excellent stability and low deactivation, resulting in an expected lifetime of at least three years in CO2-to-methanol applications. to be in the range of US$800 - 1600/million t, assuming CO2 is sourced from BECCS at a cost of For even higher stability and activity in more hydrothermally-challenging conditions, Clariant developed US$10 - 50/million t3. If CO2 is obtained by DAC, where a next-generation catalyst for CO2-to-methanol conditions costs are currently US$300 - 600/million t, then e-methanol production costs would be in the range of that will come to market soon.

US$1200 – 2400/million t. For comparison, the cost of producing fossil fuel-based methanol is in the range of Business case US$100 - 250/million t.

Approximately 30 million t of methanol is produced However, as with natural gas plants, there should be globally using Clariant’s MegaMax catalysts. For example, some room for economies of scale, which would cut the the Carbon2Chem project in Germany, which is sponsored price per ton of methanol produced at larger plants. Since by the German Federal Ministry of Education and the technique is the same regardless of the source of the Research, focuses on transforming CO2 emitted from steel raw material, there is no reason, in theory, why renewable production into valuable chemicals such as methanol. As a methanol plants should not be on the same scale as project partner, Clariant provides its MegaMax 800 conventional plants. The methanol synthesis and methanol catalysts as well as special adsorbents for distillation units can take advantage of the decreased feed-gas purification to Thyssenkrupp’s pilot plant. The production costs brought on by economies of scale, just methanol obtained is used for many purposes in the like other significant thermocatalytic processes that are chemical industry, and can serve as a low-emission fuel for similar to fossil fuel methanol plants. Increased module more sustainable modes of transport. size can lower costs for the electrochemical process of water electrolysis, and innovation to enhance stack Conclusion production may have a big impact on cost.

As outlined in this article, green methanol not only opens new pathways of renewable feedstocks for the chemical industry, but it is also uniquely positioned to become a Catalytic challenges future mainstream energy source, in particular for marine From a catalytic process perspective, the main challenge fuels. Today, the main production challenges remain the remains the increased water content in the system, which costs of the water and CO2 used as raw materials. Yet, the can deactivate and reduce the lifetime of the catalyst performance, compared to conventional synthesis. The Methanol Institute estimates that 80 renewable methanol transformation of CO2 to methanol is an exothermic projects globally are projected to produce more than 8 million tpy of e-methanol and biomethanol by 2027.6 reaction and therefore favoured at low reaction temperature and high pressure. The absence of CO leads Clariant’s MegaMax series catalysts for CO2-to-methanol to increased water, which creates stressful conditions for offer high activity, and increased selectivity and stability the catalyst. Hydrothermal ageing can shorten the lifetime to ramp up the current and future production of green and deactivate the catalyst, causing difficulty in process methanol. design.

Catalysts Building on 50 years of industry experience in methanol synthesis, Clariant’s MegaMax series catalysts address hydrothermally-challenging conditions, and are well-proven for methanol production, operating in various technologies around the world. The latest-generation catalyst offers higher activity and increased selectivity towards methanol production – even at very low reactor temperatures and pressures. Consequently, producers will November 2023 50 HYDROCARBON ENGINEERING

References 1.

2.

3.

4.

5.

6.

Compiled from ‘The Future of Petrochemicals’, IEA, (2018); Clariant calculations; and market data.

‘The Shale Revolution’, Bloomberg, (2019).

‘Innovation Outlook, Renewable Methanol’, IRENA, (2021).

‘Cleaner Air for Cleaner Shipping’, International Maritime Organization (IMO), (2020).

‘A.P. Moller - Maersk engages in strategic partnerships across the globe to scale green methanol production by 2025’, Maersk, (10 March 2022), https://www.maersk.com/news/ articles/2022/03/10/maersk-engages-in-strategic-partnerships-toscale-green-methanol-production.

‘Renewable Methanol Database of Current/Announced Projects’, Methanol Institute.

Piet Goemans and Oxana Voss, BUCHEN-ICS GmbH, Germany, illustrate the versatile applications of dense phase conveyors in the petrochemical industry.

I

n industries where the gentle and safe handling of granular bulk materials is essential, the use of cranes for filling reactors and containers may not be desirable due to safety or weather constraints. In such cases, dense phase conveyors (DPCs) offer a reliable alternative for positive pressure pneumatic conveying of dry granular particles. Notably, DPCs are commonly employed in permanent installations. This article will explore the applications and benefits of DPCs, with a relevant case study from Germany.

Dense phase conveyors (DPCs) Dense phase conveying involves the movement of bulk materials at low gas velocities and a high cross-sectional pipe area, minimising energy absorption by the particles and reducing relative particle movement. This conveying method is well-known and widely used in various industries, particularly in permanent installations.

One example of a DPC is the BUCHEN-ICS Dense Phase Conveyor, which is highly mobile and designed to be transported and set up quickly. It is built on a fixed skid that fits within a 20 ft container, and peripheral equipment can be accommodated in another 20 ft container. Riser pipe sections are available in different lengths (5.7 m, 3.8 m, and 1.9 m),

offering flexibility in installation. The ease of transport and setup ensures that the system can be operational within a day, minimising downtime during installation and maintenance.

The system incorporates two feeder vessels with sufficient storage capacity, enabling automatic switch-over and continuous conveying. This feature eliminates the need for valves that cut through the material flow and allows for loading out of big bags. Furthermore, the system can be programmed to switch automatically if released by an operator. The continuous operation capability enhances productivity and reduces interruptions during material handling processes.

A DPC hopper is incorporated on the top platform, facilitating gravity-induced falling of the catalyst into the buffer hopper. The loading process also includes active de-dusting, ensuring clean and efficient transfer of materials. The system’s large buffer volume and outlet valve enable compatibility with both sock and dense loading technologies, without interfering with usual loading procedures. Additionally, the system accommodates the loading of inert spheres up to 0.75 in. in size. The optional dosing and conveying belt, which optimally loads the DPC independently of big bag size, enhances adaptability and provides flexibility in material handling operations.

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Safety Safety is always a top priority, and DPCs can prioritise this through a combination of mechanical, electronic, and logic control measures. These measures include safeguards against electrical and control air failures, as well as operator release of the vessel. The BUCHEN-ICS Dense Phase Conveyor features two emergency stop buttons, a regular stop function on the control panel, electronic pressure control on each vessel, and mechanical pressure relief valves on each vessel.

Inspection hatches in the DPC hopper and on the top platform, along with inspection windows in the riser pipe, enable continuous monitoring of material flow and sampling.

Parameter adjustments also allow for easy flow setting, ensuring optimal performance while maintaining product quality.

Case study: hydrocracking reactors loading in Germany The effectiveness of the BUCHEN-ICS Dense Phase Conveyor was demonstrated for the first time in a major shutdown

project in Germany in May 2017. The system was used to load catalysts into two hydrocracking vessels. Throughout the project, regular sampling and analysis of the catalyst condition were conducted by the client. The case study reported that no significant changes were observed in the catalyst before or after conveying. Four different types of catalysts were successfully loaded using the system. These catalysts had a bulk density range of 900 to 1000 kg/m³, with a typical loading speed of 14.4 m³/h. Both sock and dense loading technologies were employed.

Throughout the project, regular sampling and analysis of the catalyst condition were conducted by the client. Importantly, the work was carried out continuously without any interruptions caused by the conveying process. The client’s analysis indicated no changes in the catalyst samples before or after conveying, demonstrating the system’s effectiveness in maintaining the integrity of the materials.

The success of the initial project led to subsequent utilisation of the system on three more occasions with the same reactors.

Why choose DPC technology?

DPCs offer enhanced safety features. By reducing the number of crane movements in congested areas, these systems mitigate the risks associated with material handling. Additionally, the ability to work on multiple pieces of equipment in parallel enhances operational efficiency while maintaining safety standards.

The weather-independent nature of the loading system is another appealing aspect. Adverse weather conditions, such as strong winds or rain, can hinder crane operations. However, DPCs provide a reliable alternative that ensures uninterrupted loading even in challenging weather conditions.

Furthermore, the central loading point at a lower level enhances safety and streamlines logistics. By eliminating the need for crane-based loading, these systems reduce the complexities of material handling processes and minimise the reliance on external equipment, resulting in improved efficiency.

Conclusion

Figure 1. Schematic representation of equipment in use.

Figure 2. Typical effect on particle length.

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DPCs provide a reliable and efficient solution for the gentle filling of reactors and containers with granular bulk materials.

Their positive pressure pneumatic conveying mechanism, combined with inherent safety features, make the technology an attractive alternative to crane-based loading methods in situations where safety and weather conditions pose challenges. The case study in Germany highlighted the successful application of the BUCHEN-ICS Dense Phase Conveyor in loading hydrocracking vessels with various catalysts. The system’s adaptability, mobility, continuity, functionality, safety measures, and quality assurance features make it a valuable asset in industries requiring controlled and reliable material handling.

As the demand for efficient and safe material handling continues to grow, DPC technology offers a promising solution that can be customised to specific industry requirements. With ongoing advancements in design and technology, DPCs are expected to play a crucial role in improving productivity, minimising risks, and ensuring the smooth operation of industrial processes in the years to come.

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S

ustainable biofuels, particularly sustainable aviation fuel (SAF), are pivotal components of a long-term strategy to combat climate change for the aviation industry. Key international initiatives, such as the 41st ICAO assembly and the ReFuelEU aviation regulations, further highlight the need for innovative solutions to address these challenges. While renewable energy sources such as wind and solar are contributing significantly to electricity production, liquid fuels will continue to be indispensable in areas where alternatives are not yet feasible, such as in aviation.

This article discusses the journey of converting agricultural waste into SAF, highlighting the role of technology in the aviation industry’s sustainable future. The article also explains the importance of investment in the development of technological innovations to improve capacity and efficiency, which will result in a more accessible biofuel price for a greener planet. The process of converting agricultural waste to SAF represents a significant stride towards an environmentally responsible future.

The transformation of agricultural waste into biofuels and biopolymers is paving the way for significant reductions in

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greenhouse gas (GHG) emissions, while also conserving valuable natural resources.

Harnessing abundant, sustainable feedstocks Given escalating environmental concerns and the intensified search for sustainable alternatives, agricultural waste, which is abundant and rich in lignocellulosic biomass, is becoming increasingly recognised as a promising feedstock for the production of SAF. Turning this potential into reality involves an intricate series of steps that transforms complex carbohydrates into the necessary hydrocarbon molecules for fuels.

Typically, this conversion journey begins with the enzymatic hydrolysis of agricultural waste. In this crucial phase, specific enzymes act on the biomass, breaking down its cellulose and hemi-cellulose constituents into their respective simple sugars.1 This foundational process sets the stage for the subsequent conversion stages.

Post-hydrolysis, the derived sugars enter the fermentation stage. Here, metabolic activities of specific yeasts and bacteria are leveraged to metabolise these sugars.

Philip Siu, EcoCeres, explains how agricultural waste can be converted into sustainable aviation fuel (SAF) and how companies can contribute towards the development of a clean aviation industry.

The end products are energy-rich ethanol and carbon dioxide (CO2), marking a significant transformation from complex carbohydrates to a simpler, potent form.2 Upon successful production and thorough purification, ethanol is prepared for further transformation, proving itself as an ideal component for fuel production. This holistic process, from breakdown to transformation, underscores the potential of agricultural waste as a vital resource for sustainable fuel production.

Previously perceived as an unavoidable byproduct of farming, agricultural waste has now surfaced as a valuable resource in SAF production, courtesy of advanced conversion processes. These materials, once discarded or burned thereby contributing to pollution, have now claimed a pivotal role in green fuel production. The transformation of this ‘waste’ into wealth provides a potential solution to agricultural residue disposal, whilst simultaneously reducing the aviation sector’s carbon footprint.

Innovations EcoCeres has been contributing towards innovations in SAF production with its own version of hydroprocessed esters

and fatty acids (HEFA), which are now in full operation.

Beyond HEFA, the company is developing its version of hydrolysis technology to produce cellulosic ethanol from agricultural waste, being the front-end precursor for the more customary alcohol-to-jet (ATJ) process to further transform it into SAF. This hydrocarbon, SAF, is particularly valued for its high renewable value, as it efficiently utilises sustainable resources and significantly curbs GHG emissions.

EcoCeres’ hydrolysis technology starts with the process to efficiently segregate lignocellulosic biomass into its three fundamental components: hemi-cellulose, cellulose, and lignin. This is then followed by a second-stage process to further break down those polysaccharides, hemi-cellulose and cellulose, into their respective simple sugars of 5-C xylose and 6-C glucose.

This hydrolysis process marks the metamorphosis of agricultural waste as complex carbohydrates to the most basic forms of resultant sugars. Their simplicity plays a crucial role in the subsequent stages of conversion. In EcoCeres’ route map, the 5-C sugar xylose is further transformed into furfural, a type of furan aldehyde compound. This furfural holds the potential to be further converted into another

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compound, furan-dicarboxylic acid (FDCA), which is useful for making a much-desired type of bioplastic called PEF. 6-C sugar glucose is fermented, a process that has been well-established and widely used, to create cellulosic ethanol, a vital building block in the production of SAF. As cellulosic ethanol serves as a key precursor for the production of SAF, the ability to efficiently and effectively generate it from agricultural waste is vitally important. This innovation makes it possible to harness an abundant, sustainable feedstock – agricultural waste – and transform it into a vital resource for SAF production. By integrating its proprietary hydrolysis technology with traditional fermentation techniques, EcoCeres underscores the potential of biomass conversion, moving the industry closer to a more sustainable future.

The company recently announced the successful dispatch of its first commercial cargo of cellulosic ethanol. This provides a tangible example of this conversion process in action. The shipment, in May 2023, consisted of 850 t of cellulosic ethanol made 100% from agricultural waste, primarily corn cobs, reducing GHG emissions by over 80% compared to traditional fossil fuels, and is in alignment with the EU’s Renewable Energy Directive as an advanced biofuel.

Reversing the lignocellulosic agricultural waste back to its original sugar forms paves the way for SAF to be produced through further alcohol-to-jet conversion. This provides solid proof that the conversion of agricultural waste into biofuels is both scientifically feasible and commercially viable.

EcoCeres is also extending efforts into the development of renewable materials and chemicals, including biopolymers.

One such initiative is a mid-scale industrial test to produce FDCA from furfural at the Hebei facility, China. This attempt could open the door to numerous potential applications in various industries.

Continued support and investment For this future to become a reality, continued support and investment in green energy solutions are essential. The momentum gained from scientific and technological advancements must be matched by a sustained commitment from industry leaders, policy-makers, and investors. A major obstacle to providing a sustainable supply of biofuels, especially SAF, is the lack of clarity in policy direction to drive the environmental values essential to incentivise such commitment.

The aviation industry plans to achieve net zero emissions by 2050 and is betting 65% of its emissions reductions on SAF.3 The International Air Transport Association (IATA) published estimates in December 2022, stating that to reach a decarbonisation tipping point by 2030, SAF should have a production of 30 billion litres/yr. For the aviation industry to achieve net zero emissions by 2050, SAF needs to have a production capacity of 450 billion litres/yr.4 This means that both SAF global capacity and production need to grow exponentially.

However, as of February 2023, there was still a limited number of suppliers that could produce SAF commercially, indicating that both the global capacity and the production of SAF needs to grow exponentially to meet the ambitious goals set for 2030 and 2050.

The future of SAF hinges not only on technological advancements, but also on a broader commitment to sustainability from all stakeholders. For the global capacity and production of SAF to grow exponentially, companies need to be supported. Governments can support this emerging sector by implementing policies that foster the growth and development of SAF, such as subsidies and tax incentives. Private investors can contribute by investing in innovative companies that are pushing the boundaries of what is possible in SAF production. Consumers can also play their part by opting for airlines that prioritise the use of SAF. By working together, the potential of SAF can become a reality.

Conclusion

Figure 1. EcoCeres’ Hebei Luanzhou Plant, China.

The transformative journey from agricultural waste to SAF, propelled by innovative technologies and tangible achievements, offers a promising outlook for a sustainable aviation industry. However, realising this vision depends on continued support and investment in green energy solutions.

As the aviation industry stands at a pivotal crossroads, now is the moment for companies to reaffirm their commitment to sustainability and invest in innovations shaping a cleaner, more sustainable future for aviation and beyond. By doing so, companies are not only investing in the industry’s future, but also in the longevity and wellbeing of the planet.

References 1.

2.

3.

Figure 2. EcoCeres’ Hebei Cangzhou Plant, China.

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4.

NAIK, S., GOUD, V., ROUT, R., and Dalai, A. K., ‘Production of first and second generation biofuels: A comprehensive review’, Renewable and Sustainable Energy Reviews, Vol. 14, No. 2 (2010), pp. 578 - 597.

WANG, L., and CHEN, H. ‘Technologies for Biochemical Conversion of Biomass.’ Elsevier Science. (2010).

‘Net Zero Carbon Emissions by 2050’, IATA, https://www.iata.org/ en/pressroom/pressroom-archive/2021-releases/2021-10-04-03/.

‘2022 SAF production increases 200%’, IATA, https://www.iata.org/ en/pressroom/2022-releases/2022-12-07-01/.

Dr. Ipek Ozturk Ortalan, Kurita Europe GmbH, Germany, reveals how refineries and petrochemical companies can achieve sustainability goals and ensure efficient operation by using real-time wastewater monitoring and control systems.

T

he world is facing a global crisis due to climate change and urgent action is necessary. The scarcity of good quality water is set to become an increasingly signifcant problem in the future.

Key pressure points revolve around four core issues: climate change resilience, environmental pollution, sustainable water consumption, and equitable water access.

Emerging technologies such as sensors, devices, and assets integrated by the Internet of Things (IoT) and connected to digital platforms are powerful tools to resolve real-world problems and have gained tremendous attention due to their applications in various fields. While emerging technologies may contribute to the issue, they also offer potential solutions to support neutralising carbon emissions. Therefore, significant challenges including water scarcity, water pollution and water use efficiency can all be tackled through integration with the existing water treatment techniques and technologies. Among these challenges, the concept of sustainability becomes a central topic of discussion. Therefore, the growing energy consumption and greenhouse gas (GHG) emissions of the industry require sustainable implementation of technologies.

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Moreover, collaboration between stakeholders, sharing knowledge, and assessing these technologies’ environmental and economic impacts is essential to improve energy efficiency and reduce carbon emissions.

The main target is achieving real sustainability and tackling global challenges while recognising individual and collective responsibility.

Water pollution sourced by chemicals has emerged as a significant concern and priority for society, public authorities and, more essentially, for the whole industrial sector. In water and wastewater treatment processes, substances that cause problems in the systems utilising water, and that pollute the environment, should be removed from the water.

Petroleum refineries and petrochemical industries are examples of facilities generating significant amounts of wastewater containing a complex set of contaminants and oxygen-demanding substances during crude oil refining. Wastewater treatment is necessary due to strict environmental regulations, human safety concerns, and growing awareness of environmental preservation in advance to disposal or reuse in the process. As water includes many kinds of dissolved and suspended solids, suitable water treatment methods must be selected according to the water quality to be treated. Since the wastewater composition is never stable, maximising the treatment efficiency to achieve the desired treated water quality is always challenging.

For efficient and optimised plant operations, real-time wastewater monitoring and control systems offer complimentary wastewater treatment solutions (Figure 1).

Successful wastewater treatment Major challenges in water management include scarcity, environmental pollution, water use efficiency, and renewal and replacement of ageing water infrastructure.

Over US$875 billion was spent on water and wastewater management by utilities and industrial end users worldwide in 2021. Two-thirds of that spend was on operations and maintenance.

Europe is urging industrial companies to adopt innovative measures in order to reduce or eliminate the discharge of dangerous priority substances and hazardous materials in their wastewater. Additionally, wastewater recycling is starting to receive significant attention from industry to encourage sustainable development, including the protection of the

environment, developing concepts of ‘green chemistry’, use of renewable resources, improved water management (recycling of wastewater), and health concerns.

Wastewater treatment plants encounter several diverse issues including: nn Turbid water and suspended solids in the outlet water. nn High content of chemical oxygen demand (COD). nn Biological oxygen demand (BOD). nn Hydrocarbons. nn Oils. nn Organic compounds. nn Heavy metals and specificanionic compounds (e.g. phosphates, fluorides). nn High volume of sludge and high water content in the sludge. nn Biological growth. nn Bad smells. nn Formation of persistent foam. nn Limited use of polyacrylamide (PAM) based products.

It is difficult to define a universal method that could be used to eliminate all pollutants from wastewater.

However, among the various treatment processes currently cited, a successful wastewater treatment should target and achieve the following: nn Optimisation of coagulant dosage and pH control, thus avoiding overdosage. nn Constantly dosing the correct amount of product at the right time. nn Stable quality of treated water and continuous compliance with regulations. nn Reduction in the amount of sludge and therefore, the costs for sludge disposal. nn Labour saving of water treatment operation. nn Total cost reduction.

Digitalisation of wastewater treatment applications

Thanks to digitalisation, the availability of large volumes of data enables a detailed analysis of both local and global impacts resulting from consuming products or services. The further processing and interpretation of the information combines social, economic, and environmental perspectives to provide a better understanding of the economic model and the system’s behaviour. The principle of digital offerings is to use networked devices, which are connected via a shared platform and collect data quickly, continuously, and securely through smart tools. Therefore, digital solutions can pinpoint problems in the water systems before they get too expensive and disruptive to fix.

At wastewater treatment plants, industries such as petroleum refineries and petrochemicals are using huge amounts of coagulants and dealing with high running costs. The costs include coagulant, pH adjustment chemicals and Figure 1. Schematic representation of digitalisation impact on polyelectrolytes usage, as well as sludge disposal wastewater treatment plants. cost. Digital solutions have the potential to November 2023 58 HYDROCARBON ENGINEERING

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A unique way to control the product dosage of wastewater treatment products is based on using smart tools, e.g., laser-based sensor technology. Such a sensor can directly measure the turbidity between the flocks in the wastewater. Therefore, it is possible to adjust the dosage of the primary coagulants and flocculants. Such technologies overcome the problem as they can measure the formation of flocks already at the entrance of the sedimentation basin where the flock is formed Figure 2. Schematic representation of real-time monitoring (Figure 2). This allows the immediate reacting and and dosing control with laser-based coagulation sensor at a adjusting of the dosage, even if the wastewater wastewater treatment plant. quality changes. This approach ensures that the optimum amount of product is dosed according to the real wastewater condition, avoiding both over- and under-dose. This results in economical and efficient use of the applied products.

Moreover, the amount of sludge and its disposal cost are reduced. At the same time, this ensures the smooth operation of the plant, controlled by a continuous online monitoring system, while the total cost of ownership is reduced.

Moreover, online monitoring and controlling of wastewater treatment can be connected to a shared, online platform. Therefore, fast, continuous, and secure data collection is enabled (Figure 3). In this way, real-time plant chemistry control is linked to the plant Figure 3. Schematic representation of real-time plant performance performance and key performance indicator and KPI savings monitoring using a digital platform.

(KPI) savings, including monitoring sludge generation amount. Thanks to such an online platform, all data collected from connected sensors, generate significant savings on OPEX by reducing energy assets, and equipment on-site is used to monitor real costs, optimising the use of chemicals for treatment, and performance and targets, recognise the needs, and enabling proactive maintenance of assets through the reduce the risks by being informed with on-time development of user consumption models. They achieve alarming. this by detecting time series anomalies, not using static Effective wastewater treatment is a critical factor in values as the threshold, analysing correlations between the smooth and efficient operation of petroleum variables, predicting emergency events, and learning from refineries and petrochemical facilities. Real-time them at an accelerated rate. These solutions provide wastewater monitoring and dosing control systems play a decision intelligence to support operators and operations, vital role in supporting mechanical and chemical optimise energy and water use, reduce CO2 emissions at treatments. They help increase the efficiency of the total water and wastewater operations, accelerate the move to treatment process. By implementing well-designed, value-based asset management and maintenance, and integrated, and efficient treatment programmes, it is identify early warning signs of device failure. possible to increase the ratio of water recycling. This, in turn, leads to water savings and reduced operating costs.

Real-time wastewater monitoring and Digital tools provide end-to-end solutions by using all dosing control collected data, which speeds up the transition towards Traditionally, the efficiency of wastewater treatment is economic, social, and environmental sustainability. determined by a standard turbidity measurement after the water stays one or two hours at the thickener (or floatation basin) at the end of the treatment. When using this Bibliography • KURITA Handbook of Water treatment, Second English Edition, approach, the measurement while operating the dosing Kurita Water Industries Ltd, (1999). pumps is always approximately delayed by one to • https://www.gwiwaterdata.com/.

• CRINI., A, and LICHTFOUSE, E., ‘Advantages and disadvantages two hours. This approach requires overdosing the used of techniques used for wastewater treatment’, Environmental products to ensure safe and stable water quality.

Chemistry Letters, 17:145–155, (2019).

Additionally, if the load on the wastewater plant increases, • HERNÁNDEZ-CHOVER V., CASTELLET-VICIANO, L., ÁGUEDA BELLVER-DOMINGO, Á. ,and HERNÁNDEZ-SANCHO, F., the necessary adjustment of the product dosage may occur ‘The Potential of Digitalization to Promote a Circular Economy too late. This can result in harmful or unstable water quality in the Water Sector’, MDPI (Multidisciplinary Digital Publishing Institute),14, 3722, (2022). at the wastewater plant outlet.

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Yon-Sing Simon Wong, DNV, Malaysia, explores how performance forecasting can help to optimise downstream oil and gas activities.

he downstream oil and gas industry constantly faces challenges that can have significant impacts on operations and profitability. To help companies navigate these challenges, this article will discuss how downstream companies can improve the under-performance of assets, and what role digitalisation plays in improving the value that these assets can create.

Challenges facing the downstream industry One of the main challenges faced by the downstream sector is the need to optimise operations in order to maximise efficiency and minimise costs. This requires a detailed understanding of the various processes involved in the production of finished products, the intricacies between the

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process units, as well as the ability to reliably forecast and respond to changes in the demand and supply chain, which has become increasingly dynamic over the years.

environmental targets, facilitate the anticipation of trends, and enable more informed choices to be made about how to allocate resources to meet these targets.

Identifying production bad actors

Anticipate changes with sensitivity analysis

Reduce environmental impact

Cost reallocation

One solution that has the potential to address many of these challenges is performance forecasting, which provides insights that can be used to optimise operations and make informed decisions. For example, in a refinery operation it can be difficult to forecast what problems would cause critical production losses and how to plan where the maintenance team should focus time and effort. Performance forecasting can identify bottlenecks in production processes, allowing for corrective action to be taken to improve efficiency.

Another challenge faced by the downstream sector is the need to manage and reduce environmental impact. This includes reducing greenhouse gas (GHG) emissions and conserving resources. Performance forecasting can help to identify and prioritise sustainability initiatives, as well as monitor and track progress towards meeting environmental targets. For example, simulating a plant’s life cycle operation can potentially provide opportunities for reducing energy consumption or emissions, allowing for the implementation of cost-effective sustainability initiatives. This can also help to track progress towards meeting an organisation’s

A third challenge faced by the industry is the need to adapt to changing market conditions and customer preferences, further strained by disruption from the global pandemic, volatile prices, and irregularity in global supply chain demand.

This requires a deep understanding of trends and patterns in the market, as well as the ability to quickly respond to shifts in demand. Performance forecasting can help to anticipate and plan for changes in the market, allowing for companies to remain competitive and meet the needs of customers.

Finally, the downstream sector often faces significant financial challenges, including the need to manage costs, generate revenue, and maintain profitability. Performance forecasting can provide insights that can be used to identify opportunities for cost savings and revenue growth.

For example, running simulations on a model set up with specific objectives on cost reallocation will help identify opportunities for reducing the cost of goods sold, leading to an increase in profitability. This can also help to identify opportunities for increasing revenue, such as by expanding into new markets or developing new products or services.

Investing in a performance forecasting solution Performance forecasting can be particularly useful for businesses that rely on data to make strategic decisions, as it can help them anticipate trends and make more informed choices about how to allocate resources. Despite the clear benefits, implementing such solutions comes with costs. One of the main costs is the initial investment in the software or resources needed to understand the fundamentals. This can represent a significant expense, particularly for smaller businesses or organisations. There may Figure 1. Bad actor analysis for a processing unit, on a system level. also be ongoing costs associated with maintaining and updating the performance forecasting solution.

This can include the cost of training employees on how to use the solution, as well as the cost of any technical support or maintenance required.

In addition to the financial costs, there may be other costs to consider when evaluating a performance forecasting solution. For example, there may be a time cost associated with implementing the solution as part of a full life cycle assessment, which will require effort to set up and integrate it into the business or organisation’s existing systems. It is also important to Figure 2. Flaring reporting demonstrating the number of flaring instances consider the potential risks and required from each system to mitigate their outages. uncertainties associated with November 2023 62 HYDROCARBON ENGINEERING

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implementing such a solution. There is always a risk that the solution may not deliver the expected results, or that it may not be as effective as anticipated. This could lead to additional costs if the solution needs to be modified or replaced.

Overall, the decision to implement a performance forecasting solution should be based on a thorough cost-benefit analysis, and there is no ‘one-size-fits-all’ approach. This will involve weighing up the potential costs and benefits of the solution, as well as considering any risks and uncertainties.

Economic feasibility in performance forecasting Some factors that may be relevant to consider when conducting a cost-benefit analysis of a performance forecasting solution include: nn The size and complexity of the business or organisation: a larger and more complex business may have more to gain, as the solution can help the business to analyse a greater amount of data and make more accurate predictions. However, it may also be more expensive to implement and maintain this solution in a larger organisation.

nn The availability of internal resources: if a business or organisation has the necessary expertise and resources to implement and maintain a performance forecasting solution, it may be more cost-effective to do so.

However, if these resources are lacking, it may be more cost-effective to outsource the solution. nn The potential return on investment (ROI): it is important to consider the potential benefits of a performance forecasting solution in relation to the costs of implementing and maintaining it. If the solution is expected to deliver a significant ROI, it may be worth pursuing. nn The potential risks and uncertainties: as aforementioned, it is important to consider any potential risks or uncertainties associated with a performance forecasting solution. This may include the risk of the solution not delivering the expected results, or the risk of technical issues or other problems arising.

Ultimately, the decision to implement a performance forecasting solution will depend on the specific circumstances of the business or organisation. By conducting a thorough cost-benefit analysis, informed decisions can be made about whether the solution is a worthwhile investment.

Weaving a digital thread with performance forecasting

Figure 3. Example of fleet size optimisation for varying demand levels on the network, e.g. seasonal effects.

Figure 4. Additional impact on production availability of increased crew mobilisation time from 2 to 8 hours.

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In order to get the most value from performance forecasting in operational assets, these models require periodic updates (monthly, quarterly or yearly). The frequency of the update is a function of the purpose of the model. If the model needs to support business planning, the frequency of the update needs to coincide with the frequency of updating the business plan (i.e., an annual update). If the model needs to assess reliability-related risks for short-term periods, the frequency of the update could be shorter (i.e., quarterly or every six months), or could be triggered by specific events (i.e., to understand the increased risks to the production during some emergency maintenance work being carried out).

Given the amount of data available, and the manual task of reviewing it across various applications or spreadsheets, each update is likely to require a significant amount of time and effort. Is it possible to enhance performance across the asset life cycle, from design to operations, in a pragmatic way?

Could one powered by digital technologies that drive data integration and automation make a difference? The answer to both questions is yes.

There are several reasons why businesses and organisations may now want

Case study

Figure 5. The variety of parameters available onsite that can affect the performance of an asset.

Figure 6. Automating input. to automate their performance forecasting processes to unlock the full value across the asset life cycle: n Increased efficiency: automated performance forecasting solutions can free up time and resources that would otherwise be spent on manual data transfer and input.

This can allow businesses and organisations to focus on other higher-value tasks, and improve overall work efficiency. nn Improved accuracy: automation can analyse large amounts of data quickly and accurately, using cloud computing on demand, making it easier to identify patterns and trends and make more accurate predictions about future outcomes. nn Greater scalability: automated performance forecasting solutions can be used to analyse data from a wide range of sources, making it easier to scale the solution as the business or organisation grows. nn Enhanced decision making: by providing businesses and organisations with more up-to-date and comprehensive data, automated performance forecasting solutions can help more informed decisions to be made about how to allocate resources and optimise operations. nn Risk mitigation: automated performance forecasting solutions can help businesses and organisations identify potential risks and take steps to mitigate them, reducing the overall risk of their operations.

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A specific refinery was able to benefit from performance forecasting. The refinery in question is a large, complex operation that processes a variety of feedstocks into a range of products, including gasoline, diesel and aviation fuel. The processed product is delivered to multiple customers with different priorities. In the past, the refinery struggled with declining production, making it difficult to meet consumers’ demand, and it often experienced unexpected downtime and low utilisation rates due to ageing facilities compounded with reliability issues.

A performance forecasting model was built in the early phases by different contractors, as more facilities were added to maintain production and demand. Most of the reliability data used was sourced from publicly-available databases, which do not reflect the actual deteriorating facilities’ performance as a result of ageing equipment. Furthermore, the production profiles had not been kept up-to-date and did not reflect the actual production patterns. As the refinery in question has undergone changes in both configurations as well as equipment reliability patterns, each update required extensive review of the input data.

The company identified that increasing the usage of digital workflow and data integration will positively impact value from the performance forecasting system. Using the performance forecasting solution as the engine, the company created an effective data integration and automation network to redefine its workflow – accelerating production performance forecasts, obtaining insight into potential production bottlenecks, and reducing time to focus on production-critical systems. Data collection was carried out to collate operational reliability data from maintenance records, and this data was then applied within the model, rather than generic data, to ensure that the operational experience was automatically reflected and could be updated.

An interactive dashboard was customised to drive better and faster information for different stakeholders within the organisation, as well as more efficient decision making, thereby reducing the learning curve and encouraging collaboration. By analysing market demand and forecasted performance, the company can now perform business planning for a short-term period (i.e., five years) with production trends as well as predicted quota losses. This was achieved by cutting planning time almost in half, controlling every critical parameter with up-to-date analytics for production forecasts and bad actor analysis, as well as minimising impacts from unplanned events through real-time simulation.

Conclusion Performance forecasting is a powerful tool that can help the downstream industry to overcome a range of challenges and improve operations. By providing up-to-date insights, the tool can help the sector to optimise operations, maintain product quality and safety, reduce environmental impact, adapt to changing market conditions, and manage financial performance. As such, performance forecasting is an important component of any aspect of the downstream industry looking to thrive in today’s increasingly complex and competitive landscape.

Monil Malhotra, Emerson, USA, discusses how state-based control eliminates inefficient processes, leading to more reliable, sustainable and profitable operations.

F

or many hydrocarbon manufacturers, meeting goals is an entirely different experience than it was a decade or two ago. The modern manufacturing process has brought with it a flurry of complications that have changed the way operations teams approach plant management and business teams approach enterprise strategy – and these complications have arrived just as many of their

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more experienced personnel are leaving the industry.

Experts are retiring and taking their knowledge with them, and decades of embedded knowledge that kept plants running at peak performance is disappearing nearly as quickly as the personnel who developed it.

Moreover, today’s organisations are facing new needs.

Competition in hydrocarbon processing is higher than ever, and teams that do not optimise their operations quickly fall behind. Plants are scrambling to find ways to reduce their use of resources, as well as their carbon footprint (Figure 1). Most teams know that automation and digitalisation are the tools that will help them improve operations to stay competitive, though implementing the right systems can seem like a daunting task.

Fortunately, there is a roadmap for implementing the right automation to improve performance and drive a competitive edge. Modern state-based control (SBC) leverages collected knowledge from decades of successful automation solutions, along with deep embedded expertise, providing an easy mechanism to ensure processes are optimised. When implemented correctly, this technology works not only at the plant level, but also across the fleet or enterprise.

Pains of modern manufacturing Hydrocarbon processors have long relied on tribal knowledge to operate at peak performance. Teams had operators in the control room who, through decades of experience, knew what setpoints to dial into their many loops to keep processes running smoothly. They also had field operators and technicians who could quickly recognise failure signs in the field, and then make rapid adjustments to keep processes running within constraints.

Today, however, many process manufacturers operate at levels far more complicated than those of a decade or two ago. Even the best operators can only manage a couple of operational objectives by monitoring hundreds of variables, but in today’s more complex operations – more focused on lower carbon footprint, efficient fuel usage, profitability, and reliability – achieving peak efficiency can mean managing dozens of operational objectives by monitoring thousands of variables

Figure 1. Today’s hydrocarbon processing plants are

spending enormous effort to drive more efficient and sustainable operations.

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continuously. Such a task is impossible for even the best operators, especially since many processors are relying on less experienced operators due to retirement and higher turnover.

As a result, many plants have turned to automation.

Basic automated systems enable organisations to keep plants running safely and more efficiently as they bring new personnel up to speed. But those basic systems can still be configured poorly and are not designed to adapt to changing process conditions, two key enablers of high efficiency operation. Basic automation keeps a plant running safely, but it is rarely enough to turn an organisation into a top performer.

SBC levels up automated operations To drive the most efficient operations, many organisations are now turning to SBC, an approach using a combination of operator-initiated state transitions and automated control logic to continuously drive processes to a desired state. SBC software coordinates interaction among process units, enabling different units to provide and require services to and from one another. The software automates workflows faster than human operators, locking in best practices and adapting as process conditions change. With the most advanced solutions, SBC software learns from the process via artificial intelligence (AI) and machine learning (ML), and it uses the most efficient methodology to keep operations on track.

Within a process state, algorithms and calculations determine recommended setpoints and provide recommended operating regions for various parts of the process. Once calculations are set, the system monitors power consumption, fuel consumption, losses, temperatures, and other variables to produce the highest quantities of the best quality product using the fewest resources possible. These are changes that operations staff might not make because of the difficulty of starting up, switching, or even putting equipment in standby.

Consider the example of a process relying on high-temperature steam. If, at a late stage in the process, the temperature of the steam is too high, the automation system might need to spray it with cooling water or use evaporators to bring the temperature under control. Basic automation can measure the temperature and ensure the steam will be cooled when necessary, but it will be unable to change the process if that cooling is necessary due to conditions from earlier stages of the process. The spraying keeps the temperature under control and the process still works, but it is not optimised because the plant is using extra fuel and water resources for heating and cooling the steam, and thus not maximising profitability.

In the steam example, the operations team might be running the superheater when it is unnecessary. Perhaps the team has a boiler and is trying to produce steam at a certain temperature and pressure, so they superheat the steam in step one to ensure it is still hot enough when it has passed through a set of processes and reaches step six. In such a case, SBC software can examine the process and determine when the superheater is required and when it is not. The SBC software algorithms make those

an unforeseen event, SBC can take the plant to the correct state – even if that means taking the plant offline – faster and more safely than a human operator.

Planning for a longer lifecycle

Figure 2. SBC can quickly and automatically bring a plant process to a desired state, regardless of the experience level of the operator at the control panel. determinations based on variables such as steam flow, environmental variables, and how much heat the equipment can produce to ensure the steam will still be at the right temperature when it reaches step six.

Moreover, since SBC provides consistent, repeatable operations for each process and equipment state, it empowers teams to make the most of their historical data by enabling AI and ML to identify patterns over time and then predict process anomalies, such as losses or poor equipment performance.

Justifying an SBC project Most teams already know the areas in which their processes struggle. Whether it is fuel consumption, power consumption, fluctuating product quality, losses due to inefficiency or downtime, or other concerns, teams can easily compare operations to peers and industry standards to benchmark their production. Recognising the disparity between optimal operation and current operation is the first step. By calculating the amount of resources that should be used for every pound of product versus common standards, teams can quickly begin the process of calculating return on investment (ROI) for an SBC solution.

But the ROI for SBC does not stop with eliminating waste. Teams can also create value by locking in the tribal knowledge created by operators who have run the plant for decades. SBC captures that knowledge to drive best practices automatically, regardless of which operators are on duty. Moreover, SBC enables organisations to move to analysed, repeatable operations that provide more predictable outcomes, removing human error and variation.

SBC does not just keep the plant running well, it also identifies problems and can quickly and methodically take the plant where it needs to be. Because SBC can react so quickly, this often results in a process adjustment, instead of a production interruption. Considering that unscheduled interruptions often cost organisations hundreds of thousands of dollars per hour, the ROI for an SBC solution can quickly reach millions of dollars (Figure 2).

Perhaps the highest value of SBC, however, is the increase in safety. When operations run off course due to

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Today’s highly competitive hydrocarbon process manufacturing plants are already leveraging SBC for highly efficient operations. As those organisations turn their sights toward a Boundless AutomationTM vision for their operations (a seamless architecture in which contextualised data moves freely from field to edge to cloud), these teams are finding ways to apply the core values of SBC not just at individual sites, but also across the enterprise. Teams at these organisations are planning for a future control system deployed enterprise-wide, empowering them to apply the same concepts of safety, reliability, optimisation, and advanced control, simultaneously, across an entire fleet or enterprise.

As organisations start the process of implementing optimisation solutions like SBC in their own plants, it pays to start the process with thoughts of a holistic future in mind. Organisations wanting to compete in the digitalised future of process manufacturing will need to consider how they will keep their data standardised, unified, and mobile as they implement SBC software. Typically, this means choosing the right solutions and standardising them across different plants to ensure seamless integration with the organisation’s automation ecosystem.

Few organisations today have the resources to drive this vision alone. As a result, teams often rely on experts in the industry to help them build holistic solutions. The more well integrated a product suite is, the better the odds that it will be a successful long-term solution. If a new SBC software implementation is not well integrated, it can create additional complexity when connecting with other critical infrastructure tools, such as cybersecurity, reliability, analytics tools and more.

Implementing an integrated software stack can dramatically reduce the time and resources spent building complex connections among systems. Nearly all providers will have a wide range of advanced automation solutions, but not all will have them well integrated. Choosing a supplier with an integration roadmap focused on the boundless future of automation will pay significant dividends in extended equipment lifecycle.

Lock in efficiency SBC is neither as complex nor as intimidating as it used to be. Most modern automation systems are already prepared for implementation of advanced control software, and most teams already know the target areas that they need to improve – the two key elements of fast, successful implementation of SBC. As new challenges, regulations, and requirements continue to shape the hydrocarbon processing landscape, the best way to remain ahead is to stay efficient and flexible. SBC software enables operations teams to achieve those goals, while locking in the best practices that will drive competitive advantage well into the future.

Nabil Abu-Khader and Serge Staroselsky, Compressor Controls Corp. (CCC), explain how technology can be used to monitor, analyse and maximise compressor performance.

O

ver time, the performance of a compressor slowly deteriorates from its original healthy condition. For instance, blade fouling will eventually decrease the flow rate and efficiency of a compressor. Such performance degradation can be quantified by measuring runtime process parameters and comparing them to original equipment manufacturer (OEM) data or other baseline performance characteristics.

Evaluating the performance of a compressor is important in estimating its health and optimising maintenance intervals.

Tools such as the CCC compressor performance advisor (CPA), are available to moitor and analyse the performance of the compressor in order to detect degradation and provide historical and long-term trend analysis.

Concept CPA compares the baseline (based on ASME PTC-10 performance test) adjusted to process conditions, with the actual compressor performance.

Compressor baseline characteristics are stored in a non-dimensional format: n Head coefficient (head factor) ψ vs flow coefficient (flow factor) ϕ n Polytropic efficiency ηp vs flow factor ϕ Where: ψ = normalised head coefficient ϕ = normalised flow coefficient This requires flow, pressure, and temperature inputs for each compressor section.

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Real-time built-in Benedict-Webb-Rubin equation of state (BWR) real gas calculations are used. Flow calculations are based on flow measuring device (FMD) specifications or adjacent sections flow. If gas composition needs to be altered, this can be carried out at any time through the human machine interface (HMI) for accuracy. Deviations are only calculated at steady state (stable process).

Calculations overview The CPA follows the ASME PTC-10 methodology when constructing a performance model. Differences between static and stagnation pressure are neglected, and it obtains gas properties from BWR equations of state. For a single section adiabatic compression, the compressor characteristics are approximated as shown in Figure 1 and this non-dimensional parameter set allows for proper mapping of the compressor baseline curve and the actual operating point at varying compressor operating conditions. Figure 1 shows high-level concept calculations and desired outcomes. There are mainly three phases to be executed within the tool:

Baseline model

After obtaining typical OEM compressor data, the tool calculates ϕ, ψ, and rotational mach number (MaN) non-dimensional variables.

Please note that it is easier to use an Excel spreadsheet with built-in equation-of-state (EOS) functions to calculate ϕ, ψ, and MaN. The REFPROP tool developed by the National Institute of Standards and Technology (NIST) can be used to

estimate gas properties. NIST calculations were embedded into an excel spreadsheet add-in. The excel add-in uses REFPROP DLL provided by NIST, which provides access to the same routines used by the REFPROP interface.

The ϕ, ψ, and MaN variables are plotted based on the following f1 and f2 characterisers: ψ = f1 (ϕ, MaN) ηp = f2 (ϕ, MaN) This facilitates the interpolation of points that are not listed in the OEM compressor maps. ηp values are taken from the OEM data sheet.

Calculate base/theoretical performance

At this phase, the gas composition, suction pressure (Ps), and suction temperature (Ts) is specified for the conditions to be calculated. The flow measuring device (FMD) data is also entered to calculate the corresponding volumetric and mass flow.

From ψ values found in the first phase (above), and using interpolation, all corresponding ψ values for all compressor speeds can be found. This leads to the corresponding Hp ‘base’ for the point of interest. Through interpolation, it is also possible to find the corresponding ηp ‘base’.

To find pressure ratio across compressor (Rc), discharge pressure (Pd), discharge temperature (Td), and shaft power (Jgas) for the current operating conditions ‘base’, both polytropic head (Hp) and polytropic efficiency (ηp) values are used. The process includes finding polytropic temperature exponent (σt) and polytropic volume exponent (σv) and then calculating the required Rc, Pd, Td, and Jgas ‘base’. Here, the EOS is used to estimate the suction and discharge compressibility, according to Schultz.

Calculate actual/measured performance

Figure 1. CPA high-level concept block diagram.

Figure 2. A steam turbine-driven single-section centrifugal compressor at steady state.

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At this phase, it is time to compare ‘base’ with field data ‘actuals’. For each speed, gas composition, dpo, Ps, Ts, Pd, and Td as inputs, CPA calculates the corresponding Hp and ηp and displays them on the Trainview® HMI as ‘actuals’ to be compared with the ‘base’ data calculated in the previous phase.

As a rule of thumb, 5% deviations between the ‘base’ and ‘actuals’ is considered tolerance due to various sources of error, including measurement uncertainties and calculation accuracy using EOS. When CPA is installed, it may use the OEM curves as its initial baseline. In this case, some initial deviation will most likely be present between actual and OEM-based parameters. The deviation will

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then be compared with this initial value. If after installing CPA, the efficiency was deviating, e.g., by 10%, then this can be considered as the basis for further compressor degradation.

Simulation demonstration The process simulated is a steam turbine-driven single-section centrifugal compressor, as shown in Figure 2.

The CPA demonstration calculated outputs are shown in Figure 3. The condition tab shows the inputs received from the field and the calculated variables related to the operating gas conditions. The performance display allows the actual performance of a compressor to be viewed against its healthy performance by comparing the baseline and actual values. The yellow curve (which is shown in Figure 3 on the top of the 1.00 performance multiplier) represents the estimated performance of the compressor at the current operating speed. The operating point will be on this curve when the compressor is performing at its healthiest condition. If the operating

point is deviating from the yellow line, it means that the compressor is under (or over) performing. In Figure 3, the operating point is settled on the expected performance curve, so it can be assumed that the compressor is operating at its best performance. It should be noted that the red line is the surge limit line, the green line is the surge control line, and the blue lines are the compressor’s OEM performance curves.

By introducing high internal recycling to the CPA demo, the effect of compressor fouling can be demonstrated. Figure 4 shows that a 50% internal recycle results in a head drop of almost 4% and a 11% efficiency deviation from the baseline. The operating point is slightly below the nominal value for this stage. This section is not able to develop the head given by the expected OEM curves.

On the other hand, in a few cases encountered in practice, for conditions deviating from the design or guarantee point, actual head can be larger than the baseline. For the condition shown in Figure 5, actual head exceeds the baseline by 6%, with a slight efficiency drop from the nominal value. The operating point is slightly above the nominal values for this stage. This section is able to develop higher head than given by the expected OEM curves.

Communication architecture

Figure 3. CPA demo calculated outputs. Compressor is performing at its healthiest condition.

CPA collects compressor data by connecting to the compressor server database. This data is then accessed by the TrainTools® application software, and presented in tabular, easy-to-understand Trainview® graphics. The data is then historised using local archive or plant historian.

Summary

Figure 4. Compressor is under-performing.

Tools are available to detect performance degradation in order to optimise machine maintenance periods for compressors. It is possible to evaluate the deviation from baseline performance by providing graphical representations of the relationship between actual and baseline performance for visual identification of discrepancies in performance. Tools are also capable of analysing historical data using local archives and can supply data to plant historians, reducing unexpected downtime and optimising operation costs.

Biliography •

Figure 5. Compressor is over-performing.

November 2023 74 HYDROCARBON ENGINEERING

UM5537 TrainTools® Compressor Performance Advisor® Configuration and Operation. Source: Compressor Controls Corp. Library, (2023).

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ADVERTISEMENT FEATURE

Sustainable methanol solutions

Sustainable methanol solutions from JM: high feedstock efficiency by proven and scalable technology

By Zinovia Skoufa, Business Development Manager at Johnson Matthey.

via tailored methanol converter and catalyst design to suit the CO₂‑to‑methanol duty. High degree of heat integration ensures the heat of reaction is recovered, therefore minimising the need for external heat import to the plant. Our superior‑ quality catalyst with enhanced hydrothermal stability has been developed to achieve sustained, high methanol productivity over a significantly longer lifetime, maximising profitability for our clients.

Methanol is an important and highly versatile chemical used to produce hundreds of every-day products. It is also a cleaner-burning and safe alternative to conventional fuels and a potential enabler for decarbonisation.

Today, methanol is mainly produced from synthesis gas obtained from fossil fuels, but going forward, using sustainable feedstock will be key to producing low carbon methanol. As the production of renewable methanol continues to scale up, it will provide a long term, carbon‑neutral energy solution to different transport sectors. Renewable methanol has the potential to be a key enabler in the decarbonisation of the shipping industry. It is bio‑degradable, its combustion releases fewer harmful emissions than traditional fuels and it can be safely handled within the existing infrastructure. Methanol is also an intermediate in the production of Sustainable Aviation Fuel (SAF) and bio‑gasoline, providing solutions for hard to decarbonise sectors in air and road transport.

Bio‑methanol can also be produced from renewable synthesis gas obtained from the gasification of biomass or organic waste.

This route reduces the amount of waste destined to landfill and incineration and replaces natural gas and coal‑based feedstocks, enabling the production of more sustainable fuels and chemicals with a lower carbon footprint. JM has optimised the design of the methanol synthesis loop and combined it with our highly robust methanol synthesis catalyst. This results in sustained, high feedstock efficiency, that enables our clients to get the most out of the biomass feedstock and make more methanol for longer. The process can incorporate green hydrogen, thereby approximately doubling the amount of methanol that can be produced with the same quantity of feedstock, eliminating the conditioning step, and reducing the carbon intensity even further.

Renewable methanol has the potential to be a key enabler in decarbonising the shipping industry

Johnson Matthey is the world’s leading methanol synthesis technology and catalyst supplier. As the world transitions to a net zero future, JM is playing a pivotal role in decarbonising the methanol value chain through development and deployment of its cutting‑edge methanol solutions that deliver the highest yields using the most sustainable process designs to date.

Methanol can be produced by direct hydrogenation of carbon dioxide with renewable hydrogen. JM’s eMERALD ™ Methanol technology enables production of low carbon methanol from captured carbon dioxide and hydrogen produced using renewable energy. The technology offers high feedstock efficiency – hydrogen (~99%) and carbon dioxide (~99%) –

JOHNSON MATTHEY

In JM, we are passionate about methanol and we are proud to offer the most efficient and reliable solutions in the market. Using our unrivalled expertise and know‑how, our goal is to drive profitability for our clients, ensuring our customers are cared for on their methanol journey.

Your proven partner for sustainable methanol technologies

JM, a global leader in sustainable technologies, was the first to commercialise CO₂ to methanol technology in 2011. Built on the experience gained over 60 years and 100 licenses in the methanol industry, we provide the market with low‑risk technology for high feedstock efficiency and process flexibility.

www.matthey.com

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