Hydrocarbon Engineering April 2022

April 2022

Clarifying the Future: Separation Processes Yield New Markets and Profits

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CONTENTS April 2022 Volume 27 Number 04 ISSN 1468-9340

03 Comment

33 Residual focus Vic Scalco, General Atomics, USA, details how efficient separation can help to increase profits during downturn.

05 World news 08 Navigating bumps in the road across Central and South America Gordon Cope, Contributing Editor, explains why life in Central and South America’s downstream and petrochemical sectors is never dull.

14 Renewable carbon for chemicals Andrew Reynolds, Audrey Tardy and Cedric Allemand, Technip Energies, present new perspectives and working models that have the capacity to lower the carbon footprint of chemical processing.

21 Working towards a circular economy Ben Owens, Honeywell Sustainable Technology Solutions, USA, outlines how plastics recycling technology could drive a circular plastics economy.

25 A full-cycle approach to alternative feedstocks Ethylene producers are utilising recycled plastic feedstocks to reduce the use of fossil fuels. In this article, Daniel Dreyer, Kameswara Vyakaranam and Kuldeep Wadhwa, Nalco Water, an Ecolab Company, discuss how new solutions are enabling the storage, transport and processing of alternative feedstocks across the full cycle of operations.

29 Unlocking Permian value Goutam Biswas and Theo Maesen, Chevron Lummus Global, alongside Kandasamy M. Sundaram, Lummus Technology, look at how to unlock the value of Permian crude through its direct conversion into chemicals.

39 Maximising the potential of an FCCU Gary R. Martin, Sulzer Chemtech, USA, explains why dividing wall columns are key to helping refiners shift their operations to petrochemical/chemical manufacturing.

43 Resilient systems Matt Thundyil, Dave Seeger and Carl Hahn, Transcend Solutions, USA, discuss how effective contamination control can help operators to maintain resilient operations in the face of the energy transition.

47 Taking control of catalytic reforming Tai Piazza and Geoffrey Bowers, VEGA, USA, explain how non-intrusive radiometric instruments can improve level control in the continuous catalyst regeneration (CCR) and propane dehydrogenation (PDH) unit.

51 Safe and sound Carolina Stopkoski, FLEXIM AMERICAS Corp., USA, and Jörg Sacher, FLEXIM GmbH, Germany, discuss the advantages of non-intrusive ultrasonic flow measurement in high-temperature bottom of the barrel applications.

56 The rise of instrumentation Neil Murch, Tracerco, UK, details the use of nucleonic instrumentation and technologies to deliver efficiency and performance gains in downstream refinery processes.

63 The evolution of process optimisation Gregory Shahnovsky, Ariel Kigel and Gadi Briskman, Modcon Systems, discuss the use of novel technologies to advance process optimisation in hydrocarbon processing.

67 Sulfur review

Hydrocarbon Engineering presents a selection of sulfur technologies and services currently available to the downstream sector.

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COMMENT CALLUM O'REILLY SENIOR EDITOR

R

egular readers of Hydrocarbon Engineering will have noticed increased coverage of hydrogen technology and applications within the magazine over the past couple of years. It’s clear that this burgeoning sector of our industry is viewed as a key piece of the global energy transition strategy, and we have seen significant interest from our readers, contributors and advertisers recently.

In light of this, I am delighted to announce that Palladian Publications will be launching a brand new publication dedicated to the hydrogen sector this spring.

Global Hydrogen Review will focus on the entire spectrum of hydrogen production and applications – from grey and brown to blue and green. Each issue will be packed full of quality keynote articles, detailed case studies and in-depth technical articles from industry experts, highlighting the latest market trends and innovations within the sector. In addition to covering the entire ‘rainbow’ of hydrogen production, other regular topics will include infrastructure & distribution, safety & sustainability, storage, technology advances, and much more.

Our first issue is currently in production and I’m pleased to reveal that we have an excellent line up of articles from leading experts in the hydrogen sector. While I can’t say too much right now, you can expect to read articles on topics including the current status of blue hydrogen (and its role in the energy transition); options for ensuring security of supply; how the transport sector can grow its use of hydrogen; the challenge of integrity management of hydrogen pipelines; the role of simulation in driving value across the market; the use of compression technologies within the sector; and much more. The issue will also include a keynote article examining how to turn the hydrogen debate into tangible market growth.

We’re offering all readers of Hydrocarbon Engineering a free subscription to Global Hydrogen Review. So if you’re interested in keeping abreast of the latest developments in the sector, please register for your free copy by visiting www.globalhydrogenreview.com/magazine. Or you can scan the QR code at the bottom of this page.

And while you’re waiting for the first issue to hit your inbox, please head over to our new website – www.globalhydrogenreview.com – for the latest industry news, technical content and event information.

Global Hydrogen Review will provide a platform for the industry to share knowledge and advance the development of hydrogen as a clean energy solution.

If you have a technical article or case study that you’d like to share, please get in touch using the contact information on the left of this page. And why not join our LinkedIn Showcase page, and follow us on Twitter and Facebook.

In the meantime, please enjoy this issue of Hydrocarbon Engineering, which includes a special focus on another growing sector of our industry: plastics recycling technology. Other topics in this issue include alternative feedstocks, petrochemical manufacturing, separation technology, instrumentation, and our annual review of the latest sulfur technologies and services.

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WORLD NEWS China | Aramco

JV to develop refinery and petrochemical complex

A

ramco has taken the Final Investment Decision (FID) to participate in the development of a major integrated refinery and petrochemical complex in Northeast China. Huajin Aramco Petrochemical Co. (HAPCO), a joint venture (JV) between Aramco, North Huajin Chemical Industries Group Corp., and Panjin Xincheng Industrial Group, will develop the liquids-to-chemicals complex.

The project, which presents an opportunity for Aramco to supply up to 210 000 bpd of crude oil feedstock to the complex, is expected to be operational in 2024.

It will combine a 300 000 bpd refinery capacity and ethylene-based steam cracker – a building block petrochemical used to manufacture thousands of everyday products.

The facility will be built in the city of Panjin, in China’s Liaoning Province.

Argentina | RefiPampa

signs agreement with Elessent Clean Technologies

R

efi Pampa SA has signed agreements with Elessent Clean Technologies for the license and basic engineering of a new IsoTherming® diesel hydrotreating and dewaxing unit. The grassroots hydrotreater will be installed at the RefiPampa facility in La Pampa, Argentina. In order to comply with the latest fuel specifications in Argentina to meet Grade 3 diesel specifications by 2024, RefiPampa commissioned Elessent for an

USA | DOE

T

IsoTherming diesel hydrotreating and dewaxing unit with a target capacity of 62.6 m3/hr.

The hydrotreating and dewaxing unit will enable RefiPampa to produce Grade 3 fuel year-round, reducing and even eliminating the need for costly additive usage in some months for improving cold flow properties.

Start-up of the unit at the La Pampa site is expected to take place by 2024.

Worldwide | DHL

Express and Neste announce SAF deal

D

HL Express and Neste have expanded their existing cooperation with a new strategic collaboration. In the next five years, Neste will supply DHL with approximately 320 000 t (400 million l) of Neste MY Sustainable Aviation FuelTM. The agreement is Neste’s largest to date for sustainable aviation fuel (SAF), and one of the largest SAF agreements in the aviation industry.

Neste and DHL have been working together since 2020 making Neste MY Sustainable Aviation Fuel available for DHL’s operations. In 2020, DHL became the first cargo operator to use Neste MY Sustainable Aviation Fuel on flights departing from San Francisco International Airport and Amsterdam Airport. In 2021, the companies extended that cooperation to provide Neste’s SAF for DHL’s hub at the UK’s East Midlands airport.

DHL Group has committed to using 30% of SAF blending for all air transport by 2030. Neste’s SAF is produced from sustainably-sourced renewable waste, and residue raw materials.

issues two LNG export authorisations

he US Department of Energy (DOE) has issued two long-term orders authorising LNG exports from two current operating LNG export projects: Cheniere Energy Inc.’s Sabine Pass in Louisiana, and Corpus Christi in Texas.

The two orders allow Sabine Pass and Corpus Christi additional flexibility to export the equivalent of 0.72 billion ft3/d of natural gas as LNG to any country with which the

US does not have a free trade agreement, including all of Europe.

While US exporters are already exporting at or near their maximum capacity, with these issuances, every operating US LNG export project has approval from the DOE to export its full capacity to any country that is not prohibited by US law or policy.

The US is now the top global exporter of LNG, and exports are set

to grow an additional 20% beyond current levels by the end of this year as additional capacity comes online.

In January 2022, US LNG supplied more than half of the LNG imports into Europe for the month.

In a statement, the DOE said that it remains committed to finding ways to help its allies and trading partners with the energy supplies they need, while continuing to work to mitigate the impact of climate change.

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April 2022

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

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

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

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

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

Asia Turbomachinery & Pump Symposium Kuala Lumpur, Malaysia atps.tamu.edu

07 - 09 June 2022 Global Energy Show Calgary, Alberta, Canada www.globalenergyshow.com

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

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

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

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

6

LAO production unit progresses toward commercial start-up

E

xxonMobil has announced that construction of the new linear alpha olefins (LAO) manufacturing unit at its integrated petrochemical complex in Baytown, Texas, is progressing and targeting commercial start-up in mid-2023.

When fully operational, the new facility will have the capacity to produce approximately 350 000 tpy of LAO. ExxonMobil will manufacture 10 high-purity LAO products at the site and market the new offering under the ELEVEXXTM brand name. LAO molecules are used in a broad range

UAE | ADNOC

HYDROCARBON

ENGINEERING

bu Dhabi National Oil Co. (ADNOC) has signed an agreement with Proman, one of the world’s leading producers of methanol, to develop the UAE’s first world-scale methanol production facility at the TA’ZIZ Industrial Chemicals Zone in Ruwais, Abu Dhabi.

Under the terms of the agreement, Abu Dhabi Chemicals Derivatives Co. RSC Ltd (TA’ZIZ) and Proman will construct a natural gas

Australia | Woodside

collaboration

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of applications, including in plastic packaging, high-performing engine and industrial oils, and as building blocks for surfactants and other specialty chemicals.

The new manufacturing facility will feature the latest quality control technology, including in-line analysers engineered to assess product quality and purity in real time, helping to maximise finished LAO molecule consistency and supply reliability.

Founded in 1919, ExxonMobil’s Baytown facility is the largest integrated petrochemical complex in the US.

inks agreement with Proman

A

24 - 26 May 2022

April 2022

USA | ExxonMobil

to methanol facility with an anticipated capacity of up to 1.8 million tpy.

The facility will meet growing domestic and international demand for this clean and versatile chemical commodity, which is gaining momentum as a lower-emission fuel alongside existing uses spanning industrial products.

The project is subject to relevant regulatory approvals.

launches CCU

oodside, ReCarbon and LanzaTech have launched a collaborative studies programme aimed at converting carbon emissions into useful products.

Together, the companies are investigating the viability of a proposed carbon capture and utilisation (CCU) pilot facility in Perth, Western Australia.

The proposed pilot facility would recycle greenhouse gases such as carbon dioxide (CO2) and methane

into value-added ethanol using ReCarbon and Lanzatech’s technologies. The ReCarbon technology would convert CO2 and methane into synthesis gas, with the LanzaTech technology fermenting the synthesis gas into ethanol.

Traditionally, ethanol manufacture relies on land and water use for source crops, such as corn. CCU reduces the reliance on these natural resources.

The project is now in the FEED phase.

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Learn how DEVO can help you create recycled polymers with a volatile content as low as 50 ppm.

April 2022

8

HYDROCARBON

ENGINEERING

Gordon Cope, Contributing Editor, explains why life in Central and South America’s downstream and petrochemical sectors is never dull.

L

ike many other jurisdictions around the world, the downstream and petrochemical sectors of Central and South America have suffered from COVID-19, as well as a wide range of fiscal and regulatory challenges that are unique to the region.

Mexico The oil and gas sector in Mexico has experienced a tumultuous time over the last several years. Citing a need for energy independence, President Andrés Manuel López Obrador has instituted policies to consolidate the sector under state control, including cancelling new licensing rounds and joint ventures (JVs) between state-run Pemex and deep-water operators.

The company manages six refineries with a nominal capacity of approximately 1.5 million bpd – enough to meet domestic demand for gasoline, diesel and jet fuel. However, most have been operating at reduced capacity due to lack of maintenance. The 315 000 bpd Tula refinery, near

Mexico City, is a typical example. The refinery, which has operated at half capacity for the last few years, is a major supplier of fuel to the country’s capital. Pemex has earmarked US$2.6 billion in renovation funds to increase output, but little has been done. Refineries are also frequent targets of civic unrest; in September 2021, protesting teachers temporarily besieged the plant over delayed salary increases and pension reforms.

A new Pemex refinery, the 340 000 bpd Dos Bocas plant, is being built in Tabasco, but costs have soared from the original US$8 billion budget, and the refinery is now expected to cost US$12.5 billion. Even at the original cost, the Mexican Institute for Competitiveness said that the project “could generate a serious crisis for the public finances of the whole country”.1 While the official inauguration of the plant is scheduled for July 2022, analysts doubt it will produce fuel until 2023 or 2024.

In December 2021, López Obrador announced plans to reduce the sale of crude to international refineries in order HYDROCARBON

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April 2022

to convert more domestic production to fuel. In theory, diverting an extra 200 000 bpd to its refineries would halve imports if the refineries were able to increase their low utilisation rates. In addition, in January 2022, Pemex finalised its purchase of Shell’s 50% portion of the jointly-owned 340 000 bpd Deer Park refinery, located in Houston, Texas, US. By classifying the output as ‘domestic production’, the goal could rhetorically be met. Analysts note that the massive drop in foreign exchange from the curtailed exports would have a significant impact on the nation’s economy.

Placing too much faith in Pemex also carries its risks. The state-owned firm, which is the most indebted oil company in the world, has been cited for corruption, poor environmental stewardship and workers’ safety record, and fuel theft.

“Pemex’s losses are placing a burden on taxpayers and crowding out other more productive uses of fiscal resources,” noted the IMF.2 “Past corruption scandals underline the critical importance of strengthening governance and procurement processes within the company.”

Brazil Brazil’s oil and gas sector has been moving from strength to strength. Thanks primarily to its massive presalt reserves in the offshore Santos basin, state-controlled Petrobras’ production is expected to increase from 2.7 million boe/d in 2021 to 3.3 million boe/d in 2025. Even with demand destruction from COVID-19, exports to Asia have increased, as countries (such as China) seek out the light, sweet crude as refinery feedstock in an effort to reduce environmental damage. Petrobras has committed further spending of US$68 billion over the next five years to boost production toward the end of the decade.

“In 2030, when we reach a production of 5.3 million bpd of oil, Brazil will become the fifth largest exporter in the world,” noted Energy Minister, Bento Albuquerque.3 Downstream, Petrobras has been operating an asset disposal campaign to divest up to US$35 billion in properties between 2021 – 2025. The process, instigated by anti-competition regulations, is designed to open up competition and attract fresh investment.

Eight refineries are on the disposal list: nn In August 2021, Petrobras closed an agreement with Atem, a Brazilian fuel distributor, to purchase the 46 000 bpd Isaac Sabba refinery for US$189.5 million. The gasoline and diesel plant, located in the Amazon region, has been operating well under capacity for several years. nn In December 2021, Petrobras finalised the sale of its 333 000 bpd Mataripe refinery in northeast Brazil to Arcelen. For the last year, the plant had been operating at under 70% capacity. The Abu Dhabi-based company, which paid US$1.8 billion for the facility, intends to return the plant to full capacity, and to explore biorefining potential. nn Petrobras negotiated a US$1.65 billion contract with Abu Dhabi’s state-owned investment fund, Mubadala, for the 333 000 bpd Landulpho Alves plant. nn Sales agreements for 8000 bpd Lubnor and 166 000 bpd Gabriel Passos refineries, and the 6000 bpd SIX refinery (REGAP) are being finalised, according to Petrobras CEO, Joaquim Silva e Luna.

April 2022 10 HYDROCARBON ENGINEERING

The disposition of the remaining refineries is still being negotiated. When the process is complete, Petrobras will retain approximately 50% of the country’s refining capacity.

The company is also instigating changes to produce biofuels. In 2020, it reconfigured its Repar refinery to produce 110 000 tpy of renewable diesel made from soybean oils.

Between 2022 – 2026, it plans to spend US$600 million to add 505 000 tpy further capacity to its Paulinia and Cubatao refineries.

Venezuela After several decades of mismanagement, Venezuela, which has an estimated 304 billion bbl of reserves, has seen its output plummet from over 3 million bpd to an estimated 527 000 bpd in late 2021.

A lack of investment in maintenance has been most critical in the downstream sector. The Paraquana refinery complex, with a nameplate capacity of 940 000 bpd, has been the scene of a score of failures, including a crack in a holding tank that resulted in 3.6 million l of fuel spilling into the Gulf of Venezuela marine environment. The 140 000 bpd El Palito refinery in Carabobo State, following a substandard refurbishment by Iranian technicians, has been largely shut due to a leaking catalytic cracker. The entire sector’s infrastructure is so decrepit that analysts estimate that it will cost over US$200 billion to repair – a sum that is unlikely to be supplied by the country’s few remaining allies in Beijing (China) and Tehran (Iran).

Colombia Renewed violence in Colombia has put pressure on the country’s oil and gas sector. Attacks on the 210 000 bpd Caño Limon pipeline, for instance, have hampered efforts to deliver crude from domestic fields to the export terminal of Coveñas. International oil companies have divested onshore assets, including Occidental Petroleum, which sold US$825 million in petroleum assets in 2020.

Overall investment has dropped from US$4 billion/yr over the last decade to US$2 billion in 2020.

The country, which has only 1.8 billion bbl of reserves, desperately needs to increase investment in non-conventional oil. The USGS estimates that the Middle Magdalena Valley (a major source of conventional production), contains shale crude resources up to 7 billion bbl and 13 trillion ft3 of gas. While current conventional production now stands at under 750 00 bpd, the Colombian Petroleum Association estimates that commercial fracking could add as much as 450 000 bbl of daily production and attract US$5 billion in annual investments.

Much of the downstream sector is also in need of investment. In early 2021, Ecopetrol announced that it was spending US$780 million over the next two years to modernise the century-old, 250 000 bpd Barrancabermeja refinery in the Caribbean port of Santander. An upgrade and expansion of its hydrocracking unit will reduce sulfur content in gasoline to 10 ppm. Water treatment and sulfur dioxide (SO2) reduction is also planned for the facility.

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• Duplex steel belts specifically alloyed to resist corrosion.

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• Downstream storage – silo and open/closed stockpiles.

• Custom-built reclaimers for any location.

• Truck, rail and ship loading and bagging systems.

• Large scale block pouring.

ipco.com/sulphur

Argentina Investment in Argentina’s unconventional resources over the last decade is finally bearing fruit. According to the USGS, the Vaca Muerta shales in Neuquen province hold an estimated 16 billion bbl of crude and 308 trillion ft3 of gas.

State-controlled YPF, as well as Shell, Pan American and PlusPetrol, have spent billions on drilling and fracking; production is expected to grow from 120 000 bpd in late 2020 to an estimated 200 000 bpd by the end of 2021.

Natural gas production is also on the rise; associated Vaca Muerta gas stood at 890 million ft3/d in the beginning of 2021, but exceeded 1.6 billion ft3/d by August 2021. Efforts to export gas have not gone well, however. In 2019, YPF contracted a floating LNG (FLNG) ship owned by Belgian-based Exmar, with the intention of exporting 500 000 tpy of LNG from the Atlantic port of Bahia Blanca to international markets.

Subsequent complications due to COVID-19 undermined YPF’s ability to maintain the agreement, and it evoked force majeure in 2020, mothballing the facility.

Argentina has approximately 600 000 bpd of domestic refining capacity. State-controlled YPF accounts for around half, including the 189 000 bpd La Plata refinery near Buenos Aires and the 105 000 bpd Lujan de Cuyo refinery in Mendoza. In 2019, the company announced that it would spend more than US$2 billion to carry out a desulfurisation process at both plants, and the work is expected to be finished in 2024.

Petrochemicals Demand destruction related to the pandemic reduced petrochemical production throughout Latin America. Brazil, Argentina and Mexico account for the majority of the regions’ 7.5 million tpy ethylene capacity. In Mexico, Pemex is the leading producer; in 2020, it produced 4.3 million t of products, down 21% from the previous year. Brazil is the largest chemical and petrochemical producer in Latin America; in 2020, combined sales were approximately US$100 billion, a 30% decline in the 10-year average.

While petrochemical capacity in Latin America is far below consumer demand for plastics and related products, availability of affordable local feedstock (primarily ethane and naphtha) create sector bottlenecks. Braskem is Latin America’s largest petrochemical company, with extensive operations in its home country of Brazil, as well as Argentina, Mexico, and other countries. However, regional feedstock availability is a major impediment to operations, let alone expansion. Mexico, for instance, has faced difficulty in supplying its 1 million tpy ethylene and propylene Braskem Idesa plant on the Gulf of Mexico due to partner Pemex’s inability to deliver 66 000 bpd of ethane. In October 2021, it received shareholder approval to build a US$400 million ethane import terminal in Veracruz. While the source of ethane was not disclosed, much of Latin America relies on US deliveries from terminals in the US Gulf of Mexico.

LNG Strong gas demand in Asia and Europe in recent times has lit a fire under other developers of LNG, including several projects in Mexico. Analysts estimate that Asian consumers can save up to US$1.25/million Btu by shipping from the Pacific coast, as April 2022 12 HYDROCARBON ENGINEERING

compared to Texas and Louisiana, where the bulk of US production resides.

Sempra Energy’s Energía Costa Azul (ECA) LNG in Baja California, Mexico, is located just south of the US border.

A former LNG import site, it is already connected to existing pipelines. The 2.5 million tpy train, scheduled for completion in 2024, will use an estimated 370 million ft3/d. The Mexico Pacific Ltd (MPL) project is located south of ECA on the Sea of Cortez in Sonora State. The plan is to build three trains totalling 14.1 million tpy capacity, using approximately 2.3 billion ft3/d of gas. A final investment decision (FID) is expected in 2022. Both ECA and MPL are already served by major pipelines that are currently underutilised. The two projects can rely on abundant Permian gas at costs comparable to LNG plants in the Gulf of Mexico. ECA’s output has already been locked up in 20-year contracts and the company is talking about Phase II, where it could add 12 million tpy.

Hydrogen When it comes to climate change, hydrogen is seen as a key ingredient in reaching a net zero energy goal by 2050 because it can replace oil and gas in many applications, but does not emit carbon dioxide (CO2) when consumed. The trick is to produce green hydrogen through electrolysis, using renewable energy.

Central and South America produces approximately 4 million tpy of hydrogen, primarily for use in refineries, ammonia production, and the steel sector, with demand expected to increase over the next decade by 50%, to 6 million tpy. Several Central and South American countries have expressed an interest in becoming leaders in low-carbon hydrogen. Chile wants to use its abundant hydropower to become a leading exporter. Australian firm, Enegix, has announced plans to take advantage of northeast Brazil’s abundant wind and sunshine by constructing a 600 000 tpy green hydrogen plant in Ceará state. Colombia has published a hydrogen roadmap where it envisions using solar power and offshore wind to product 3.2 million tpy of green hydrogen.

Conclusion In conclusion, the downstream and petrochemical sectors in Central and South America face many challenges, from the after-effects of COVID-19, to a range of fiscal and regulatory obstacles. Jurisdictions such as Brazil have made great strides in deregulation, while countries such as Argentina have introduced incentives to render international investment in unconventional resources more attractive. While the move toward biofuels and hydrogen has not gained the momentum of other jurisdictions, the two represent vast future potential.

In the meantime, demand for both fossil fuels and petrochemicals will continue to outstrip domestic supplies, creating opportunities throughout the next decade.

References 1.

2.

3.

‘DIAGNÓSTICO IMCO: REFINERÍA DOS BOCAS’, IMCO, (9 April 2019), https://imco.org.mx/diagnostico-imco-refineria-dos-bocas/ ‘Mexico: Staff Concluding Statement of the 2021 Article IV Mission’, IMF, (8 October 2021), https://www.imf.org/en/News/ Articles/2021/10/08/mcs100821-mexico-staff-concludingstatement-of-the-2021-article-iv-mission ‘Brazil will be world’s fifth largest oil exporter in 2030 – Energy Minister’, The Rio Times, (8 July 2021), https://www.riotimesonline. com/brazil-news/brazil/brazil-will-be-the-fifth-largest-oilexporter-in-2030-minister/

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Andrew Reynolds, Audrey Tardy and Cedric Allemand, Technip Energies, present new perspectives and working models that have the capacity to lower the carbon footprint of chemical processing.

T

he oil and gas sector is currently exploring how it can reduce the quantity of carbon dioxide (CO2) released to the atmosphere while continuing to meet the increasing consumer demand for valuable plastics. Although a solution will inevitably be found, a change in perspective may help to provide the framework to get there more rapidly.

Fossil-sourced carbon is currently extracted in the form of gas, oil and coal.

Through the processing industries, this carbon is transformed into longer chain molecules and ultimately into valuable plastic resins. The plastics are then turned into consumer goods. At end-of-life, they are incinerated or sent to landfill, releasing the carbon into the atmosphere as CO2 and causing pollution and global warming as a result.

Countries around the world are implementing regulations to tackle the pollution caused by plastics. Single-use plastic regulations contribute to the reduction of quantities of plastic waste and associated CO2 released into the environment. Despite the underlying growth trend in the use of plastics, carbon efficiency may also be optimised by the design of plastic-based goods and resins. Material R&D leads to the introduction of new resins with better physical properties, and products requiring less resin for equivalent performance.

Classic decarbonisation techniques may also be applied to processing facilities in order to improve energy and raw material efficiencies, to capture carbon, and to introduce electrification as a potential energy source to replace fossil fuels.

However, a combination of the above is unlikely to be enough. As opposed to the energy industry, where carbon is used for fuels and burnt, the vast majority of carbon for chemicals is used as a feedstock, with the carbon incorporated in the final product.

For polymer resin producers, a reduction limited to Scope 1 and 2 emissions will not have a significant impact on the global carbon balance. Reductions in Scope 3 emissions will be required both upstream and downstream of the polymer units.

Recycling end-of-life plastics will have a much larger impact. The carbon required from conventional feedstocks is substituted in part by recycled material, whereby the carbon released to the atmosphere at end-of-life through incineration or landfilling is drastically reduced. The greenhouse gas (GHG) emission calculation, performed for a polyolefin resin throughout its full life cycle, shows a typical reduction of total carbon footprint from 5 kg CO2 equivalent for a straight run process to 3.9 kg CO2 equivalent, with 30% of recycled plastics incorporated in the final product. This advantage, along with simplicity and cost, leads to the natural adoption of plastics recycling as a solution of choice.

The path forward to net zero will be complex, with the progression of alternative techniques depending on the maturity of the technologies proposed. Carbon sourcing from recycled and biogenic feedstocks in the mid-term will provide a renewable carbon source that will displace conventional fossil-sourced carbon over time. Additionally, novel technologies to combine and transform captured CO2 with green hydrogen produced from renewable electricity will emerge in the longer run.

For the moment, however, recycling of end-of-life plastics will make a key contribution to the chemical industry. It not only avoids carbon released through end-of-life incineration or pollution through landfills and leaks to the environment, but also provides a source of valuable renewable carbon feedstock, and leads to a global reduction of 25% of the carbon balance.

Plastics recycling Macro factors concerning global warming, plastics pollution and sustainability are shaping consumer awareness and government policies that strongly impact industrial practice and techniques. The pace of change is rapid.

Although new packaging and products are being designed for recyclability, post-consumer plastics recycling is not simple, due to the numerous types of plastic resins, their conditioning, and their intrinsic physical properties.

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April 2022

The main techniques for plastics recycling include mechanical and chemical methods. Chemical recycling may be further sub-divided into thermal techniques (pyrolysis and gasification) or depolymerisation and dissolution. The suitability and differentiation of the different techniques will be discussed further on in this article.

Mechanical sorting and recycling Mechanical sorting and recycling techniques are required to separate post-consumer waste into the various plastic streams required by the downstream converters. These techniques allow for the separation of the target polymer contained in municipal waste through the different unit operations of separation, crushing, washing, shredding, drying, sieving and re-conditioning. The polymer that is recovered may be delivered in different forms – such as bales, flakes, pellets or powder – and sold to the transformers as a non-virgin product.

The major inconvenience of material produced through mechanical recycling is the nature of the processing steps and the subsequent downgraded product specification. The resulting material demonstrates lower tensile strength and is more favourably reused for lower value goods. The compliance of mechanically-recycled polyolefins for food grade packaging applications is also a challenge. Chemical recycling technologies may offer an alternative solution to these needs.

Chemical recycling: thermolysis Chemical recycling by thermolysis allows for the transformation of the plastic waste to feedstocks for the monomer production units. The base product from pyrolysis or gasification is recycled back to the refinery or steam cracker via a long recycle route.

Figure 1. A linear extractive model.

Subsequent processing in existing facilities is required to produce virgin-grade material.

The polymer is subjected to thermal treatment at high temperatures by pyrolysis (absence of air) or gasification (presence of air). These techniques, in the presence or absence of catalysts, are most suitable for hard-to-recycle, low-quality waste such as SRF/RDF or mixed plastic resins that cannot be separated into the constituent monomers by other chemical techniques.

Chemical recycling: pyrolysis Pyrolysis techniques are based on known principles, with a great number of technologies available on the market. Only a few are mature, with a technology readiness level of 8 and above. The industrialisation and commercialisation effort needs to be correctly and methodically addressed as the technology is owned mainly by small or start-up companies.

After pre-treatment, the waste is thermally degraded in the absence of air at approximately 400°C. Catalysts and promoters may or may not be used. The resulting cracked gas is cooled and passes through primary separation for the production of pyrolysis-oil or gas. The resulting products are returned to the existing upstream infrastructure of refineries or steam crackers by way of a long recyle loop, where removal of contaminants and subsequent processing may be carried out. The py-oil and py-gas may also be used as a source of energy required for the pyrolysis reaction. Certification of the final product and recycled sourcing are proposed by a mass balance approach.

The adoption of pyrolysis technologies will be rapid within the industry, with the need to address several challenges such as: n Small plastic waste catchment areas limiting unit size. n Location of pyrolysis plants (close to waste collection facilities or existing processing facilities). n Waste plastic recovery, logistics handling, and security of feedstock supply. n Seasonality and quality of municipal waste. n Waste plastic cost. n Contaminant removal facilities and final product quality. n Communication between – and working practices of – waste handling companies and downstream processors. n Mass balance certification. n Small companies and start-ups holding the technologies.

Chemical recycling: depolymerisation Figure 2. Typical GHG emissions for the plastics value chain.

April 2022 16 HYDROCARBON ENGINEERING

Chemical depolymerisation produces virgin-grade monomers that are recycled

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back through a short recycle loop, directly to the polymer production units. This contributes to a better overall carbon balance and leads the way towards infinite recycling.

Chemical depolymerisation techniques are best suited to condensation polymers such as polyethylene terephthalate (PET). The intra-molecular bonds are weaker than for polyolefins, and the constituent monomer building blocks are easier to access.

During pre-treatment, the polymer waste is cleaned and amorphised to reduce the crystalline structure of the polymer and render the polymer chains accessible. The long polymer chains are depolymerised and cut into the constituent building blocks by chemicals, often in the presence of a catalyst. The resulting mixtures are separated and building block monomers subsequently purified using common process unit operations.

However, chemical recycling by depolymerisation is currently at a lower technology readiness level. The intrinsic advantages of chemical depolymerisation techniques – in terms of carbon balance and quality of product – are such that

accelerated technological development and commercialisation methods are required. This may be obtained by the introduction of novel collaboration models for technology development that will be briefly discussed later in this article.

Case study

Methods for process technology development are typically sequential with the decision to move to the next phase after completion and validation of the results of the previous phase.

The required investment increases as the project matures.

Although tried and tested, with risk being minimised, this method is time consuming, and the failure rate on the road to commercialisation is high.

New working methods are required to accelerate the time for novel technologies to appear on the market. A change of mindset and the collective collaboration of different players is required.

CARBIOS, a small French start-up using a programme of basic research, has invented an enzyme that selectively depolymerises PET at atmospheric pressure and low temperatures. The conversion yields and time to depolymerise the PET waste warranted a focused effort to industrialise the process and prove the technology on a fast-track basis.

The industrialisation effort of the CARBIOS enzymatic depolymerisation technology C-ZYMETM to produce polymer grade monomers from PET waste is being jointly-executed

by Technip Energies’ teams.

Following initial proof-of-concept through a laboratory and pilot plant built

by CARBIOS, the following tasks are executed in parallel, on a fast-track collaborative basis: Figure 3. Moving from linear to circular. n Set the framework and requirements for the demonstration and commercial plants and for third-party licensing. n Design, procurement and construction of the demonstration unit to validate batch processing steps and confirm absence of technological lockers in view of the commercial plant design. n Design, procurement and construction of an industrial unit to demonstrate the technology on a continuous basis and on a Figure 4. Integration of recycled plastics into the value chain. large-scale.

April 2022 18 HYDROCARBON ENGINEERING

As the different tasks are executed in parallel and results are produced stepwise, information flow and communication between the different activities must be clear and rapid. This may only be achieved with a small and agile team with open communication and a trustworthy relationship. Working at the interfaces is critical, and unlocking technical and economical lockers through specific workstreams is an integral part of this iterative working process.

The initial results from the demonstration plant are promising and the teams are focused on delivering the commercial plant, which is targeted for start-up in 2025. Renewable carbon for chemicals is now becoming a reality.

Figure 5. Pyrolysis overview.

Bibliography

Figure 6. PET chemical depolymerisation overview.

• International Energy Agency, https://www.iea.org/ • Ellen MacArthur Foundation, https://ellenmacarthurfoundation.org/ • Boston Consulting Group, https://www.bcg.com/ • Renewable Carbon Initiative, https://renewable-carbon-initiative.com/ • ‘An engineered PET depolymerase to break down and recycle plastic bottles, Nature, (8 April 2020), https://www. nature.com/

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Ben Owens, Honeywell Sustainable Technology Solutions, USA, outlines how plastics recycling technology could drive a circular plastics economy.

P

lastics play an important role in our society, providing cost-effective utility for a wide range of applications including packaging, textiles, transport, medicine, electronics, appliances and sports. In addition, plastic packaging extends the shelf life of food, minimising waste.

Furthermore, compared with heavier glass or metal containers, lightweight plastic packaging can help reduce the emissions involved in the transport of goods.

However, only 10 – 15% of plastics are recycled due to limitations in collection, sorting and recycling processes. Most waste plastics are incinerated or landfilled. In landfills, waste plastics can leach microplastics into the soil and groundwater.

Incinerators, meanwhile, can recover some energy content from waste plastics to generate electricity, but they emit the carbon as carbon dioxide (CO2) into the atmosphere.

This article will take a closer look at current plastic recycling methods and examine how new technology is being applied to help increase the volume of plastic that can be recycled.

Limitations of current recycling techniques Today, most plastic waste is recycled via mechanical recycling, whereby it is washed, chipped, melted down and reformed into

pellets that can be used to create new products. At each stage of this process, the physical properties of the plastics degrade to some extent, relegating them to lower-grade applications such as filling for jackets or park benches. This performance downgrade is called downcycling. Only certain polymers, colours and formats are suitable for mechanical recycling. Plastic sorting facilities must pick through general waste streams to separate ideal materials and reject portions of waste such as flexible plastics, polystyrene, and incompatible formats or colours of rigid polyethylene and polypropylene. These reject plastics will ultimately end up in a landfill or incinerator.

In comparison, chemical recycling breaks down plastics at the molecular level, producing a feedstock replacement for existing plastics production plants. Some chemical recycling processes generate monomers that can be purified and repolymerised into the same polymers from which they came.

Such processes work well for polymers such as polyethylene terephthalate (PET), which is commonly used in drink bottles, because they can be easily depolymerised while leaving the monomers intact. However, recycling lower-quality mixed waste plastic streams is more challenging and requires processes with the ability to handle different plastics and non-plastics.

Technologies such as pyrolysis are able to meet this need.

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Pyrolysis works by subjecting lightly-sorted mixed waste plastics to moderate temperature and pressure in the absence of added oxygen to decompose the waste plastic into hydrocarbon molecules which resemble conventional feedstocks for plastic production plants. This recycled polymer feedstock is converted into new plastic with high-quality and high-performance properties identical to plastics made from conventional sources. The lower-quality waste plastic streams processed by pyrolysis are not rich enough in the formats, polymers or colours suitable for mechanical recycling, so without processes such as pyrolysis, they would have been bound for

landfill or the incinerator. As such, upgrading mixed waste plastics with pyrolysis prevents these plastics from reaching end-of-life status in landfills or incinerators, while replacing fossil feedstocks that would have been used to make new plastics.

Honeywell’s Sustainable Technology Solutions group, part of Honeywell UOP, has been working on ways to enhance the effectiveness of pyrolysis to increase the volume of waste plastics that can be recycled.

Converting everyday plastics into high-value molecules By combining its expertise in pyrolysis, contaminants management, and molecular conversion, Honeywell UOP has developed a commercially-viable way to use pyrolysis to upgrade low-quality waste plastics into recycled polymer feedstock that can be used to produce new, virgin-quality plastics. This process is called UpCycle.

How the process works

Figure 1. Honeywell’s Sustainable Technology

Solutions group has been working on ways to enhance the effectiveness of pyrolysis to increase the volumes of waste plastic that can be recycled.

Figure 2. Honeywell’s UpCycle pyrolysis process transforms low-quality mixed waste plastics into a recycled polymer feedstock that could be used to produce new food-grade or medical-grade plastics.

April 2022 22 HYDROCARBON ENGINEERING

The process applies chemical process technology to pyrolyse plastics at moderate conditions, breaking down difficult-to-recycle plastics to their building blocks.

Low-grade, coloured, flexible, multi-layered polyolefin or polystyrene-rich waste plastics that would otherwise be disposed of by incineration or landfilling are broken down via pyrolysis from large, complex polymer molecules into simpler, smaller hydrocarbon molecules. Once the vapours are recovered, condensed and cleaned of trace contaminants, the liquid product (recycled polymer feedstock) is shipped to a steam cracking plant where it is converted into plastics precursors that can be used to create virgin-quality recycled plastic with performance equal to the product produced from fossil feed sources. For example, using the UpCycle process, a lightly-sorted mixture of waste plastics can be recycled into new plastics suitable for food-grade or medical-grade applications and not simply downcycled into bench planks or jacket filling.

The process has been designed for both operational resiliency and economic performance. By upgrading low-value, mixed-waste plastics into steam cracking feedstock, plastics producers are better able to achieve their recycled content targets. This places a strong demand and high value on the recycled polymer feedstock produced in the UpCycle process.

Furthermore, the process aims to strike the balance between capital efficiency and feedstock availability to meet the mixed waste plastics upgrading needs of a typical metropolitan area with a modular equipment design. The process is scalable and can be integrated into a range of existing waste management and petrochemical infrastructures globally.

Unlike combustion or incineration, the process does not consume oxygen; its main purpose is not to burn plastic for energy, but to convert recycled plastic into feedstock to make new plastics. Whereas combustion converts the carbon within plastics into CO2 that is emitted to the atmosphere, the process is designed to maximise the amount of carbon from plastic that ends up in the recycled polymer feedstock, enabling a high degree of circularity.

Delivering a spectrum of benefits According to a life cycle analysis conducted in October 2021 based on an UpCycle process plant in Spain, the process would

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be expected to reduce CO2-equivalent (CO2e) emissions by more than 50% compared with the same amount of virgin plastic produced from fossil feeds.1 Alternately, it would be expected to reduce CO2e emissions by more than 75% compared with a typical combination of conventional modes of waste plastic handling, such as incineration and landfilling.1 These CO2e reductions are some of the largest improvements among all waste plastic pyrolysis technology offerings.2,3 Above all, the process offers the potential to divert millions of tons of plastic waste from landfills and incinerators, reducing both the global threat posed by plastic waste leakage and the dependency on fossil feeds to create plastic.

Proving the concept To encourage the adoption of the process and demonstrate its viability, Honeywell is collaborating with waste management companies around the world to bring the solution to collection sources. The modular design of the deployed process units can facilitate faster installation of the technology to allow greater volumes of plastics to be recycled sooner.

As a first step, Honeywell is partnering with Sacyr, a Spanish engineering and waste services company with operations in over 20 countries. The two companies will co-own and operate an UpCycle process plant in the Andalusian city of Jerez de la Frontera, where the process will transform up to 30 000 tpy of mixed consumer, commercial and industrial waste plastic into recycled polymer feedstock. When operations commence, this new unit will be among the largest of its kind in Europe.

Desired outcome In a September 2020 study, market intelligence firm, AMI International, forecast that plastic waste processed with emerging technologies could enable between 5 – 15 million tpy more of plastic waste to be recycled by 2030. The actual utilisation rate will depend on several factors, including legislation, the status of sorting infrastructure, and the outcome of life cycle analysis. To illustrate how much volume that is, 14 million t of uncompacted waste plastic is enough to fill approximately 70 American football stadiums.

That said, there is no magical solution for eliminating plastic waste. The UpCycle process is not a singular answer to all of the world’s recycling needs; it has been designed to operate in conjunction with other waste management methods, each of which will continue to play to its strengths.

Such technology supports changes to plastic waste management that the world needs, and offers the potential to drive an unprecedented, global and circular plastics economy that improves the sustainability of everyday products.

References 1.

2.

3.

Honeywell Life Cycle Analysis, (October 2021). The LCA results are calculated by Honeywell UOP in accordance with international standards for life cycle assessment, ISO 14040:2006 and 14044:2006.

The LCA is pending critical review.

‘Life cycle assessment of plastic energy technology for the chemical recycling of mixed plastic waste’, Plastic Energy, (September 2020), https://plasticenergy.com/wp-content/uploads/2020/10/PlasticEnergy-LCA-Executive-Summary.pdf ‘Evaluation of pyrolysis with LCA – 3 case studies’, BASF, (July 2020).

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I

Ethylene producers are utilising recycled plastic feedstocks to reduce the use of fossil fuels. In this article, Daniel Dreyer, Kameswara Vyakaranam and Kuldeep Wadhwa, Nalco Water, an Ecolab Company, discuss how new solutions are enabling the storage, transport and processing of alternative feedstocks across the full cycle of operations.

n the last decade, the climate and water crisis has drastically escalated. Companies are looking to dramatically reduce carbon emissions, optimise water usage, and eliminate waste, all while remaining profitable in a hyper-competitive environment. The companies excelling in this landscape realise that water, energy and waste are inextricably linked, and to achieve a more circular, sustainable economy, each of these must be addressed.

In response to this growing crisis, advanced recyclers of plastic waste have begun to produce an alternative feedstock called pyrolysis oil, which utilises recycled plastic waste to address the plastics challenge with a more circular approach. Pyrolysis oil has also been shown to significantly reduce carbon emissions over other traditional feedstocks, such as petroleum naphtha.

In the past, pyrolysis oil was difficult to process and transport, but Nalco Water, Ecolab’s water and process management business, has recently introduced new solutions to make its production and transportation easier.

This includes new chemical and process solutions that improve feedstock flowability and stability as it is transported, stored and processed. Recent trials of these methods at select energy companies are proving the new technologies to be successful in real-world applications.

Trials that examine a suite of solutions and processes that are new to the downstream energy and chemical markets are currently underway in North America and Europe. The trials have shown that companies are able to process pyrolysis oil using existing equipment, which requires lower capital costs than retrofitting operations for feedstock transportation. The trials have specifically demonstrated that these solutions can enhance feedstock stability, improve cold flow properties, and reduce acidic corrosion to protect plant assets.

Nalco Water conducted multiple tests to characterise pyrolysis oil as a feedstock. Pyrolysis oils produced through chemical recycling are a new stream with relatively unknown properties, particularly when considered for use in petrochemical operations (such as ethylene production). The company analysed over 30 different pyrolysis oil samples from a variety of producers in order to understand key properties and potential problem areas, and as new streams are available, these feedstocks will be tested as well. Several key areas emerged as sources for issues related to cold flow behaviour, gum formation, and film deposition. Tests were then identified to assess potential problem areas in each sample, as shown in Table 1.

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Based on these tests, the company identified the following potential issues: nn Product stability: pyrolysis oil can be highly olefinic in nature, breaking down to form films or gums. nn Flow properties: poor cold-flow properties lead to poor pumpability in colder temperatures. nn Heavy components: tar-like components can cause regular downtime in pyrolysis processes and pose a feedstock quality concern. nn Variability: physical properties vary from producer to producer and even from batch to batch. nn Other contaminants: metals, chlorides, oxygenates and other contaminants can cause processing challenges.

Table 1. Characterisation tests Problem or concern area

Test

Method

Cold flow

Pour point

ASTM D5950

Corrosion

NACE

TM0172

TAN

ASTM D664

Organic chloride content

ASTM D4929

Thermo-oxidative stability

Proprietary Nalco Water method

Total sediment

ASTM D4870

Fouling potential

Proprietary Nalco Water method

Gum formation and fouling

Table 2. Trial A Cold flow improver treat rate (ppm)

Pour point (°C)

0 (blank)

6

200

-3

400

-12

600

-21

Table 3. Trial B Stabiliser treat tate (ppm)

Induction period (hr)

0 (blank)

2.28

250

3.91

500

6.60

1000

12.60

Figure 1. Trial C results.

April 2022 26 HYDROCARBON ENGINEERING

To address these diverse issues when recycling pyrolysis oil, an entire set of solutions had to be developed. These include chemical solutions to help with the production, storage and transportation of recycled plastic feedstock; consulting on programme implementation, seasonal variabilities, asset protection and future scaling potential; and continuous research and development to optimise operations.

The three solutions that enable pyrolysis producers and end users to experience fewer operational upsets include a cold flow improver, a stabiliser, and an extraction solvent.

One early trial showed the success of using the cold flow improver. A pyrolysis oil producer based in Europe (with additional operations planned for the US) presented a pyrolysis oil sample that had a high base pour point of 6°C. The recycler is based in a cold weather climate and was concerned that the pyrolysis oil would solidify during periods of low temperature, leading to constricted flow in pipes, valves, and other process sections. The cold flow improver was shown to significantly reduce the pour point of the pyrolysis oil in the sample, which would enable the material to remain fluid at much lower temperatures when compared to the untreated material, as shown in Table 2.

Another trial showed promising results when using the stabiliser. An ethylene producer based in Northern Europe presented a sample of pyrolysis oil that was suspected to be oxidatively unstable. Over short periods of time, oxidative instability may not be a problem, but over longer periods of time, this instability can lead to gum and sediment formation.

Nalco Water created a proprietary method to measure the relative stability of samples, and this result was expressed as an ‘induction period’ (measured in units of hours). Treatment with the stabiliser led to significantly increased induction periods, indicating that the oxidative stability of the samples in field conditions would be expected to increase upon treatment, as shown in Table 3.

A third trial with a new extraction solvent also showed successful results. An ethylene producer with global operations presented a sample of pyrolysis oil that was known to exhibit film formation when stored. Treatment with various antioxidants did not resolve the issue, suggesting that there was a non-oxidative route for fouling. Extraction of the pyrolysis oil sample with the extraction solvent was able to remove the precursors to the film formation, resulting in significantly reduced film formation, as shown in Figure 1.

These solutions work in different scenarios. For example, the stabiliser may be used at ethylene plants or as plastic to feedstock plants. The cold flow improver may be used during the transport and storage of pyrolysis oil. The solutions work together holistically to help ethylene and advanced recycling plants use their existing infrastructure and equipment when transporting and storing pyrolysis oil. The cost of retrofitting plant infrastructure can exceed thousands of dollars depending on the specific operation.

The solutions also come together to support feedstock stability and flowability as the pyrolysis oil is stored and processed, which helps to protect refining and chemical processing infrastructure from fouling and corrosion. Fouling and corrosion can cause production bottlenecks, which, at the front end of the plant, can occur from deposits in the feed pumps and exchangers, and can impact heat transfer and

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Conclusion

Figure 2. Nalco Water’s approach to advanced recycling for plastics. flow rate. When used together, these solutions mitigate the loss of heat transfer and preserve flowability.

Combining these solutions with monitoring capabilities and consultative expertise that focus on maintaining ethylene plant performance during pyrolysis oil processing offers the most gain for energy companies. Multiple performance factors, including increased fouling, corrosion, quench emulsions, compressor performance, quality impacts, and other factors, should be addressed simultaneously. This approach provides ethylene plants with an essential feedback loop, and when coupled with chemical solutions and compositional analysis of the pyrolysis oil, enables customers to optimise plant performance while taking maximum advantage of pyrolysis feedstocks, as illustrated by Figure 2.

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Nalco Water continues to engage in the development of new or alternative solutions for the wide variety of pyrolysis oils that are generated by various producers. Each solution should be tailored to the specific needs of a unique operation for maximum efficacy.

Ultimately, the production of pyrolysis oil has helped the industry to take a more circular approach, and has aided ethylene producers and their value chain partners along their decarbonisation and sustainability journeys. For ethylene producers and crude oil refiners, advancing towards a more sustainable future is not possible without focusing on transformative innovation. More than 350 million tpy of plastic waste is generated around the globe, and companies are taking collective action to invest in plastic waste reduction.1 The combination of government regulations, consumer behaviour, and industry emphasis on sustainability will continue to drive innovations that focus on providing alternative feedstocks for ethylene production.

Nalco Water’s early trials show that using a variety of chemical and process solutions can improve or solve many of the challenges associated with utilising pyrolysis oil.

Reference 1.

‘Drowning in Plastics – Marine Litter and Plastic Waste Vital Graphics’, UN Environment Programme, (October 2021), https:// www.unep.org/resources/report/drowning-plastics-marine-litterand-plastic-waste-vital-graphics

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Goutam Biswas and Theo Maesen, Chevron Lummus Global, alongside Kandasamy M. Sundaram, Lummus Technology, look at how to unlock the value of Permian crude through its direct conversion into chemicals.

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olyolefin resins are integral to human prosperity and are found in everyday applications ranging from food packaging and detergents, to automobiles, durable goods, and plastics. The olefins to make these polyolefin resins are produced primarily through the thermal cracking of hydrocarbons such as ethane, LPG, naphtha and complex feedstocks that boil in the gas oil boiling range. Each of these hydrocarbons stem from crude oil or natural gas. A location’s preferred feedstock depends on local economics and feedstock availability.

Ethane is slated to remain abundantly available as a low-cost petrochemical feedstock for olefin production in North America. Similarly, it is available at low cost in the Middle East. This provides the US and the Middle East with a comparative advantage when it comes to the manufacturing of low-cost polyethylene.

These two regions are expected to build more world-scale ethane crackers to meet increasing demand for polyethylene across both internal and overseas markets. Most of the demand growth for polyolefins will be in the Asia Pacific region. Here, limited ethane

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availability made naphtha the predominant feed for steam crackers.

In China, producers have built large and complex refineries integrated with petrochemical units to produce olefins and aromatics from crude oil instead of naphtha, assuming historic trends would continue so that crude oil would remain less expensive than naphtha on a mass basis.

These crude-oil-based facilities enjoy an economy of scale, and manufacture ethylene at a cost that is competitive with stand-alone naphtha crackers. With the cost advantage of crude oil over naphtha projected to increase, the economic incentive for converting crude oil into chemicals is also expected to increase.

Today, steam cracking technology has advanced enough to enable thermal cracking of light crude oils and

Table 1. Permian WTL properties Name

Permian light crude

Density (API)

48.6

Total sulfur (wt%)

0.01

Total nitrogen (ppm)

26

Total metals

0.5

Hydrogen (wt%)

14.5

520°C+ (wt%)

4.8

Micro carbon residue (MCR) (wt%) 0.07 Paraffins (vol%)

48.5

Naphthenes (vol%)

39.5

Aromatics (vol%)

11.62

condensates without prior refining. Such ‘direct crude oil cracking’ implies a major capital advantage.

This article will address the routes to crack crude oil directly into ethylene and the economics of this process.

Along with ethylene, pyrolysis yields other valuable chemical products, such as propylene, butylene, butadiene and aromatics.

Why Permian crude?

The world has witnessed a remarkable increase in US crude oil production. In 2018, the US became the world’s largest producer, producing over 12 million bpd. The Permian oilfield in Texas is the world’s most prolific oilfield, and produces a light (tight) crude oil.

Based on their density (38 – 56 API), Permian crudes are subdivided into three grades of crude, namely West Texas Intermediate or WTI (38 – 43 API), West Texas Light or WTL (44 – 50 API) and West Texas Condensate or WTC (50+ API).

Contemporary steam cracking technology enables the direct conversion of light crude oil into olefins at refinery scale, without having to first refine the oil to make it ready for steam cracking. Such direct crude conversion requires the external placement of a heavy oil fraction, as this more hydrogen-deficient fraction produces excessive (pyrolysis) fuel oil and dramatically shortens the onstream time of cracking furnaces.

Provided the feed portfolio is limited to lighter crude oils, refining of crude oil prior to steam cracking or placement of heavy oil fractions outside the facility can remain at a minimum.

A feed portfolio anchored on Permian WTL would be highly suitable for direct steam cracking into chemicals, as Permian WTL exhibits low impurity levels and high hydrogen and paraffin content. It consists mostly of naphtha (approximately 50%), some vacuum gas oil (VGO) (typically 10 – 18 %) and a minimum of vacuum residue (1 – 5%), so that only a small (residue) fraction requires rejection. See Table 1 for a full breakdown of Permian WTL properties.

Lummus Technologies’ Heavy Oil Processing Scheme (HOPS) technology enables the cost-effective steam cracking of oils with a relatively small residue fraction (such as condensates, WTC and WTL)1 without prior fractionation, as the technology integrates fractionation and pyrolysis, enabling rejection of the residue fraction from within the steam cracker.

HOPS to steam crack Permian crude

Figure 1. Simplified diagram of the convection section with HOPS: FPH = feed preheat, UMPH = upper mixed preheat, DSSH = dilution steam superheat, LMPH = lower mixed preheat.

April 2022 30 HYDROCARBON ENGINEERING

In addition to an attractive boiling range, Permian WTL is a preferable feedstock for direct steam cracking because of its high paraffin and low polynuclear aromatic compound content. Paraffins produce the most olefins and exhibit the lowest coking tendency. Minimum polynuclear compounds minimise the coke make. Figure 1 shows a simplified sketch of the residue rejection section, which is a key HOPS design feature that contributes to the economic attractiveness of HOPS in direct steam cracking of condensates and ultra-light crudes such as WTL.

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The convection section in a steam cracker enables the heating of feed components to temperatures high enough to vaporise (fractionate) them. It controls vaporisation through mixing with dilution steam and further superheating. A HOPS vessel adds more superheated dilution steam to vaporise the feed to the desired level. It has tailored furnaces and proprietary internals that ensure vaporisation at minimum fouling. The vaporised feed leaves the convection section for the radiant section, and the radiant section then pyrolyses the vapour. Feed that remained in the liquid phase then leaves the HOPS as residue. In its economic sweet spot, a HOPS bleeds up to 5% of the feed.

Table 2 shows the overall material balances for the direct cracking of Permian WTL crude and naphtha. Case 1 corresponds to high severity, whilst Case 2 corresponds to low severity conditions. Valuable chemicals are olefins (ethylene, propylene, butadiene, butylenes) and aromatics (benzene, toluene, and xylene [BTX]).

The material balances in Table 1 are anchored on 1.5 million tpy ethylene production and 8000 hours of operation. Light saturates (ethane, propane, butane) are recycled to extinction. Products from a two-stage dry pyrolysis gasoline hydrogenation (DPG) unit and from a pentene saturation unit are recycled to extinction.

Aromatics (BTX) are extracted from the C6-C8 DPG heart cut. The remaining resin (a non-aromatic C6-C8 fraction) is recycled back to the steam cracker heaters to extinction.

Economics of Permian crude

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H

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Saudi Aramco, Lummus Technology and Chevron Lummus Global (CLG) have co-developed the Thermal Crude to Chemicals (TC2CTM) process that expands the crude oil feedstocks suitable for nearly complete conversion into petrochemicals beyond light crudes and condensates. TC2C is a departure from the conventional crude refinery and includes a pre-conditioning section to increase the hydrogen content of the middle and heavy components of crude oil.

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Economic analyses based on the yield of directly steam cracking WTL and naphtha were based on the 2019 IHS price forecast of feeds and products delivered in South Asia.2 In-house capital index correlations yielded Total Installed Costs (TIC) values. Naphtha is considered the reference case. The WTL required investment is estimated at US$250 million over the naphtha case. The energy cost, maintenance cost, catalyst, chemicals, and other operating costs are included in the economic analysis.

Gross margins and internal rate of return (IRR) of steam cracking either WTL or naphtha into chemicals are based on stock balances generated through linear programming.

Stock balances assume that the residue fraction is sold as very-low-sulfur fuel oil (VLSFO). The analyses show that WTL exhibits approximately US$250 million incremental margin over conventional naphtha-based steam crackers (see Figure 2). This translates to > 1.5% better IRR over a generic naphtha cracker.

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

This higher hydrogen content makes more oil suitable for steam cracking. TC2C designed for Arab Light (or heavier feed) can process more Permian WTL (or other paraffinic low-sulfur crudes and condensates), and introduce heavy orphan streams (e.g. FCC slurry oil) or lower cost feeds (e.g. high-sulfur fuel oil) to utilise the robust residue upgrading capability while processing Permian. If it is designed exclusively for Permian WTL, it will lower CAPEX, OPEX and crude oil throughput for the same quantity of ethylene.

Alternately, CLG’s ISOTREATING and ISOCRACKING technologies can be deployed to increase a crude oil’s hydrogen content and to eliminate coke precursors and contaminants. An increase in hydrogen content facilitates steam cracking, as it increases the olefin yield and reduces pyrolysis oil yield.

Upgrading residue all the way into steam cracker feedstock requires a dedicated residue hydrocracker or catalytic cracker. Hydrocracking Permian residue is not

Table 2. Permian crude cracking yields Case Case 1 Feed

WTL

Case 2 WTL

Case 3 Naphtha

Severity

High

Low

High

Crude specific gravity

0.786

0.786

0.725

Crude feed (BPSD)

114 079

125 287

116 250

Ethylene to crude ratio

0.316

0.287

0.336

Chemicals to crude ratio

0.684

0.682

0.748

Total feed (‘000 tpy)

4756

5224

4471

Rel.sp.energy (Kcal/kg ethylene)

1.04

1.16

1.00

Hydrogen and methane off gas

669

632

775

Ethylene

1500

1500

1500

Propylene

672

864

656

Products (‘000 tpy)

Butylenes, butadiene

414

620

407

Pygas (BTX)

770

750

882

PGO and PFO

502

605

249

Residue

227

249

0

Acid gases

3

3

2

Total (‘000 tpy)

4756

5224

4471

economical, as Permian crude contains too little residue to fully utilise residue-upgrading technologies. Permian residue is better placed in the oil market or sold as VLSFO. Resid Fluid Catalytic Cracking (R-FCC) can upgrade the heavy part of crude oil if manufacturing transportation fuel is economical. Lummus has marketed both IndmaxTM (with Indian Oil Corp. Ltd [IOCL]) and SRDCTM technology to maximise propylene production. Typically, Y-zeolites and amorphous components crack large molecules while simultaneously converting olefins into aromatics. The addition of ZSM-5 zeolite to an FCC enables the cracking of particularly paraffinic moieties into small olefins (mostly propylene), and ZSM-5 preserves these olefins. This enables the cracking of VGO (350°C+) and residue into propylene and light gases (both olefins and paraffins). Novel technologies such as Indmax and SRDC FCC preserve more of the light olefins partly by enhancing the contribution of the ZSM-5 catalyst. The higher the integration value is available, the more the refinery and steam cracker can exchange feeds and products.

Whether ethylene or propylene is more valuable depends on how quickly an economy is growing. Nearly irrespective of economic growth, normal butylene is less valuable than ethylene or propylene. This implies that it is attractive to upgrade butylene into propylene using Lummus’ Olefin Conversion Technology (OCT).3 OCT is a low-CAPEX technology enabling the energy-neutral conversion of ethylene and butylene into propylene – or vice versa – to optimise product slates.

Conclusion The chemical and refining industries face a trade off between available capital and return on capital. Maximising crude oil valorisation requires a complex integrated refinery-petrochemical facility that can require more capital than is accessible, even for capital-effective options such as TC2C. Starting with steam cracking, Permian WTL offers a staged investment pathway toward more complex and versatile processing options.

Permian WTL crudes provide the opportunity to produce chemicals at an advantaged cost without significant prior investment in operations to first condition the crude oil. The capital required for directly steam cracking a crude oil such as Permian WTL (or another light crude) into chemicals is comparable to that of a naphtha cracker, but the returns are significantly higher. To crude oil consumers, Permian feedstocks are slated to continue to be an attractive choice, providing a window of opportunity to harvest the benefits of the mature technology to directly steam crack crude oil into chemicals. To crude oil producers, direct steam cracking is an opportunity to unlock maximum Permian value.

References 1.

2.

Figure 2. WTL vs naphtha gross margin comparison.

April 2022 32 HYDROCARBON ENGINEERING

3.

SUNDARAM, K. M., US Patent 10 017 702 B2, (issued on 10 July 2018; US Patent 10 669 492 B2, (issued on 2 June 2020).

IHS Markit, (copyright July 2020 [used with written permission

by IHS Markit]), https://ihsmarkit.com/research-analysis/index. html STANLEY, S. J., and HILDRETH, J. M., ‘New options to boost propylene production with metathesis chemistry’, AIChE ethylene producers’ conference, (2013).

Vic Scalco, General Atomics, USA, details how efficient separation can help to increase profits during downturn.

I

t would be an understatement to say that the COVID-19 pandemic has created one of the most transformative periods in our history. For the oil and gas industry in particular, the pandemic’s impact has intensified the need to improve operations to weather the effects and downward demand trends caused by the ongoing crisis, as well as the anticipated uncertainty that is forecast for the months and years ahead.

Technology-led rapid supply response, flat-to-declining demand, investor scepticism, and increasing government pressure regarding environmental impact are also leading the industry into a new era of intense competition and self-examination. There is no question that oil and gas will continue to play a fundamental role in supplying affordable energy and critical products to support worldwide demand.

However, without a fundamental shift-change in how the industry manages its processes and available technologies to maximise operations and create greater value, it will be difficult to return to the profitable performance that has historically prevailed prior to the onset of the pandemic.

Reactionary market trends To answer the question of how to create greater value in this increasingly competitive, multi-trillion-dollar market, refineries need to place each gallon in every barrel under greater scrutiny for profit. The sharp drop in demand has forced some refiners to shut down, while others have reduced crude runs. Furthermore, refiners have considered rerouting process streams, and have explored enhanced integration with petrochemical facilities in an effort to reoptimise refinery processes and generate more profit from day-to-day operations.

The ongoing energy transition away from hydrocarbons is adding to the declining demand. In this environment, it will HYDROCARBON 33

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April 2022

be increasingly important to execute projects that will drive additional value in the refining system. To bring greater profits to the refining sector, high-margin opportunities are emerging in the petrochemical feedstock market. At the 2020 American Fuel and Petrochemical Manufacturers (AFPM) Summit, several speakers reinforced findings that the pandemic is actually creating demand and market expansion of chemical building blocks such as propylene. Among the strongest projects for refineries to consider are those focused on upgrading the heaviest fractions of the crude oil (resid processing). Upgrading these feedstocks to petrochemicals and marketable fuel components such as high octane alkylate, propylene or high-quality marine fuels will improve industry profit potential in a challenging low product margin environment.

One of the best options available to refiners is to process heavier, low-cost residual streams in the fluid catalytic cracking unit (FCCU), while adapting conditions to produce the ideal product slate. Fluid catalytic cracking (FCC) conversion technology is scaling up, providing more options for competing against a confluence of market and regulatory forces. Many of the options under consideration involve increasing resid conversion through the FCCU. Unprecedented demand reduction in 2020 lowered FCCU operating rates in most regions. These turndowns changed the traditional constraints on the FCC, especially unit heat balance that can be restored by processing heavier feedstocks. This process, however, has its own set of challenges for the refiner to consider. Production of resid or opportunistic feedstocks poses technical issues beyond those of conventional processing, including removal of contaminants, corrosion concerns, metallurgy selection, and increased levels of asphaltenes, while maintaining high liquid yields. Integration of process configuration technologies and operation of the FCCU, coupled with the proper separation technologies, are paramount to mitigating any technical challenges. If the proper separation technology is

not in place, higher severity FCC conditions when processing resid can result in higher main column bottom catalyst fines concentration and increased hazardous waste from fines migration.

Increasing bottom of the barrel profits from the FCC Upgrading more challenging opportunity feedstocks will provide refiners with greater flexibility and will improve their ability to shift product portfolios to address expanding markets such as marine fuel or bunker pool. In the chase to increase the bottom line, the industry is looking at resid-to-propylene as a reliable means to increase conversion value.

FCC is one of the most versatile and profitable upgrading processes in a refinery. While the FCCU is well-known for its ability to process multiple feedstocks, it has traditionally processed atmospheric and vacuum gas oils (AGOs and VGOs) from the crude distillation unit (CDU).

One of the most value-driven advantages of the FCC process going forward is the flexibility to process complex blends of residues, including atmospheric, hydrocracked and hydrotreated residues. Other feeds that can be processed with unit upgrades and advanced catalyst formulations include coker and visbreaking gas oils, demetallised oil, etc.

Equipment upgrades allowing resid FCC operations at high severity involve strippers, injectors, cyclones, improved metallurgy, efficient flue gas, and slurry separation technology. Resid-capable FCCUs operating at high severity require the right catalyst design with the proper catalyst-to-feed ratio, facilitating the diffusion of large resid molecules.

Recycling of smaller fines from efficient bottoms separation technology will assist in fluidising the larger fresh catalyst and lower fresh catalyst uptake in the resid cracking process. This action alone is worth millions to the refiner annually. Proper productivity within the FCC generates

Figure 1. Global demand outlook. Source: Wood Mackenzie Macro Oils Service.

April 2022 34 HYDROCARBON ENGINEERING

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valuable cracked products without the coke and gas penalty experienced with improper catalyst productivity. The result will leverage resid processing and efficient downstream integration into the petrochemical value chain. This may motivate refiners to increase their focus on resid processing to provide a feedstock cost advantage while meeting on-spec product demand.

With advancements in high-severity processing, complications can arise in improving lower valued products. Many of the options for resid feedstocks present unique processing challenges. Efficient separation technology is required not only for the flue gas, but more importantly for reducing the concentrated main column bottoms to meet fine concentration levels for the bunker fuel and marine market. The International Maritime Organization (IMO) has imposed new restrictive regulations (MARPOL VI/IMO 2020) calling for < 60 ppm and lower sulfur content.1

Bunker fuel challenges for FCC slurry As the pandemic’s effect on lowering demand subsides, marine fuel and bunker fuels will continue to face the same pressures as oil, with peak demand and incremental economics driving decision making. The long-anticipated arrival of the 0.5 wt% sulfur limit in marine fuels, in keeping with IMO 2020 bunker fuel regulations, was expected by some to severely limit global market outlets for at least 3.3 million bpd of low-quality high-sulfur fuel oil (HSFO): > 3.5 wt% sulfur. Instead, the demand loss resulting from the COVID-19 pandemic and the unexpectedly high number of shipping vessels installing scrubbers created a unique market environment in which the value of HSFO exceeded expectations.2 This may well be a temporary situation as markets return to a new normal following the pandemic. In the long-term, however, streams such as FCC bottoms will be increasingly hard to blend into very-low-sulfur fuel oil (VLSFO) fuels but may have a home in the larger-than-anticipated HSFO products if the fines content is contingent.3 One of these products, FCC slurry oil at a 4 – 5% yield, is the lowest value product from the FCC unit. It is a highly

Figure 2. Gulftronic electrostatic separator and RFCC

unit.

April 2022 36 HYDROCARBON ENGINEERING

aromatic, low-API material containing FCC catalyst.

Because of the catalyst content and high aromaticity, environmental restrictions make easy disposal of sludge from settling tanks expensive. In addition to this, processing the catalyst-laden slurry can cause severe erosion of refinery equipment. To manage the challenges for FCC slurry oil presented by the IMO regulations, operators have benefitted from investing in separation technology solutions to meet the regulation requirement of < 60 ppm catalyst fines in marine fuel to increase the revenue from the FCC bottoms. To achieve this level of clarity, there are only a couple of options that are proven to be efficient at this level.

Slurry oil particulate removal technologies Historically, holding tanks have been used to allow solids to settle out of the main column bottoms or slurry oil. The resultant decant oil solids content is a function of the sedimentation tank design, the physical characteristics of the slurry, the temperature of the storage tank, and whether settling aids are used. It should be noted that another product generated along with clarified oil is sludge, which is classified as hazardous waste and requires special treatment and expense for its disposal. Depending on the tank size and rate of slurry oil production, estimated costs per cleaning are in the range of US$1 – 4 million. In the absence of countermeasures, increasing resid feed to the FCCU increases the rate of slurry oil production and sludge formation. This level of separation is slow, and without some form of blending it is unable to meet the market requirements for high-value clarified slurry oil.

Perhaps the least expensive capital and maintenance cost method for removing solids from slurry oil is the liquid phase cyclone separator or hydroclone. Liquid phase hydroclones have been in the departiculating slurry oil service for over 50 years. Unfortunately, the hydroclone method only allows reduction in solids levels to approximately 300 – 500 ppmw, which does not provide the refiner with as much product application flexibility as other, more effective removal methods. The dynamics of the hydroclone allows for approximately 10% of the feed slurry to be sent back to the riser, increasing coke makes and eroding profits. Although centrifuges have been used to remove solids from slurry oil, their use has been limited and it is difficult to generalise.

The first membrane filters were put into slurry oil service in around 1990. Mechanical filtration operates at temperatures up to 600˚F and employs tubular porous metal elements. The solids collect on the inside of the elements while the filtrate passes through to the outside.

Some filters use porous sintered woven wire mesh metal filters and operate at 400 – 650˚F. Others employ a 2 – 5 μm woven wire filter element, using light cycle oil (LCO) as a backwash at 350˚F, and claim 85 – 95% solids removal from the feed slurry.

Due to the limitation in smaller particle removal, until the creation of a solids layer, the mechanical unit has difficulty separating fines below 18 μm, and these units are also highly-susceptible to plugging from asphaltenes and

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Learn more at www.ga.com/gulftronic ©2022 GENERAL ATOMICS

waxes in resid use. The process of mechanical separation is the most expensive out of all the separation technologies to maintain on an annual basis, due to the replacement cost of cartridges, expensive backflush medium requirement, and labour-intensive cleanings when out of service.

Electrostatic precipitators are commonly found at the top of the FCCU to remove catalyst fines from stack emissions. A similar efficient process has been found for the removal of solids from liquids in the main column bottoms from resid FCCU: the di-electrophoresis electrostatic separator.

Electrostatic separation of FCC catalyst fines from slurry oil has been in commercial operation for over 30 years with over 50 systems in operation worldwide.

Improved continuously over this period, electrostatic separation is a robust, automatic process that is capable of removing sub-micron catalyst fines from slurry oil or other hydrocarbon streams.

This technology is not affected by the presence of asphaltenes, making it an excellent choice for removing solids not only from resid FCC derived slurry oil, but also from gas oil crackers. Increased profits from efficient separation, low maintenance costs, and a solid return on investment (ROI) have resulted in electrostatic separator units being the most sought-after fines separation technology on the market today.

The following is an example of applying the electrostatic separator in place of tank settling and remedial removal and disposal: Refinery A operates an FCCU with a throughput of 80 000 bpd. The FCCU has a slurry oil product flow of 6.0 vol% of feed, or 4800 bpd at 0.0 API. The FCCU uses an electrostatic separator to remove fines from 3000 ppm to < 50 ppm. This is equivalent to approximately 2.25 tpd of fines.

Assuming 2 tpd of sludge for every 1 tpd of fines, a total of 4.5 tpd of sludge and fines would have accumulated in the storage tank. In one year, the accumulation would be approximately 1600 t.

The electrostatic separator adds value by upgrading the slurry oil quality for high-grade coke production.

Assuming a product value increase of US$2/bbl of slurry oil, the added value is the following: 4800 bpd slurry oil product x 365 days x US$2.0/bpd = US$3.5 million/yr The only meaningful process cost for the electrostatic separator is for recycle flow. For this scale, the recycle flow rate would be 2 vol% of the effluent, or 100 bpd. At a cost of US$1.0/bpd, this cost is: 100 bpd recycle x 365 days x US$1.0/bpd = US$36 500 Ignoring the labour and material costs of tank cleaning, it is important to consider the cost of landfill for the sludge removed. Assuming landfill is US$1.0/lb, the cost is 1600 tpy x US$2000/t = US$3.2 million/yr.

The annual savings would be: US$3.5 million US$0.04 million + US$3.2 million = US$6.7 million/yr April 2022 38 HYDROCARBON ENGINEERING

The road to resid Prior to now, most propylene was produced from naphtha-based steam crackers and new world-scale propane dehydrogenation units, with a smaller fraction (> 30%) coming from high-severity FCC units using ZSM-5 based catalysts to increase propylene yields. Using resid FCC units (RFFCs) has also increased the concentration of fines in the main column bottoms (MCB). More than 40 RFCCs from multiple licensors have successfully exceeded objectives towards maximising propylene production.

Fortunately, technology for efficient resid processing through the FCCU will serve to increase propylene conversion beyond the pandemic. The reduction of catalyst fines in this process must be achieved in order to increase profits from the processing of specialty product feedstocks, higher value fuels, and blend stocks. This separation is paramount to increasing market value, reducing downstream erosion, and evading disposal concerns.4 The FCCU is a truly dynamic unit with licensor unique operation. When faced with transforming operating scenarios and shifting market economics, being prepared to process resid with the proper fines control in place will allow a refiner to remain nimble and maximise the overall profitability of the resid FCCU operation.

Investing in a specialised catalyst, FCC licensor optimisation, modern separation technology, and industry-leading separation understanding will secure increased revenue in the race to high propylene yields. More flexibility in separation expands the refiner’s portfolio and increases revenue from the bottom of the barrel alongside processing a wide range of feedstocks, from heavy resid to VGO.

References 1.

2.

3.

4.

TAN, F., et al, ‘How the World’s Oil Refiners Plan to Grapple with Their Fuel Output After 2020’, Reuters, (28 September 2018).

‘IMO 2020: Mayhem or Opportunity?’, Wood Mackenzie, (12 November 2019), https://www.woodmac.com/ HICKIN, P., ‘Coronavirus Impact Masking Post- IMO 2020 Risks for Marine Fuels’, S&P Global Platts, (24 February 2020).

SINGH, R., LAI, S., DHARIA, D., TechnipFMC Process Technology; CIPRIANO, B., HUNT, D., W. R. Grace & Co., ‘Conventional FCC to Maximum Propylene Production’, Hydrocarbon Processing, (September 2020).

Bibliography • • • • • • • • • •

2020 AFPM (Virtual) Summit, ‘Industry Leadership Panel’, (25 August 2020).

CUNNINGHAM, N., ‘Goldman Sachs: Prepare for a Global Consolidation of Refineries’, Oil Price, (2 July 2020).

‘Short-Term Energy Outlook: Global Liquid Fuels’, US Energy Information Administration, (6 October 2020), https://www.eia.gov/ HUNT, D., et al, ‘Parkland Refining and Grace Collaborate to Increase FCCU Catalyst Circulation Capacity’, Catalagram, No. 125, (Spring 2020).

VAN HULL, K., ‘Reason to Believe: Why Build an Ethane Steam Cracker in A Time of Low Ethylene Margins’, (7 July 2019), https://rbnenergy.com/ DILIP, D., et al, ‘Introducing PropyleneMAX® Catalytic Cracking (PMcc®)’, Catalagram, No. 125, (Spring 2020).

WAGNER, K., and FARMER, D., ‘OlefinsUltra® HZ Technology Improves Propylene Yields’, Catalagram, No. 108, (2010).

2020 AFPM (Virtual) Summit, ‘Running Slurry Recycle Through Derated FCC to Maintain ROT and Regenerator Temperatures’, (26 August 2020).

‘Global Downstream Outlook to 2035’, McKinsey & Company, (16 July 2019), https://www.mckinsey.com/ ‘China’s Building Mega Refineries Just as Fuel Demand Stalls’, Bloomberg News, (6 October 2020).

Gary R. Martin, Sulzer Chemtech, USA, explains why dividing wall columns are key to helping refiners shift their operations to petrochemical/chemical manufacturing.

R

efiners are being driven to shift from fuel production to more profitable petrochemical and/or chemical manufacturing while reducing costs and environmental footprint. Fluid catalytic cracking units (FCCUs) have the flexibility to process feedstocks at different levels of severity in order to optimise profitability and move the product slate toward petrochemicals, such as propylene. To enhance their competitiveness in a challenging marketplace, businesses can leverage dividing wall columns (DWCs) as an economical and eco-friendly solution to modifying existing FCCUs, and produce valuable products as a result.

Increasing propylene production While FCCUs have traditionally produced high-octane gasoline from vacuum gas oil, they also provide an important link between a fuel refinery and the production of light olefins and aromatics for petrochemical manufacturing. To address changing market needs, which are characterised by increased demand for petrochemicals and limited necessities for fuels, FCCU licensors are designing units to produce higher volumes of propylene yield on fresh feed. In effect, these are currently planned for 10 – 20 wt%, while they have historically been approximately 5 wt%.

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ENGINEERING

April 2022

Realistically, economics are driving the designs of propylene production equipment, with one factor being the CAPEX associated with recovering the chemical.

More precisely, systems that offer yields towards the lower end of the ranges discussed are the most common, with optimum solutions usually somewhere between 10 – 15% for new units and between 7 – 10 wt% for revamps.

Such upgrades can provide for increased propylene production at the expense of gasoline. Businesses can address this issue by increasing the severity of the process, adding catalysts such as Zeolite Socony Mobil–5 (ZSM-5), and varying the reactor partial pressure, total pressure and catalyst-to-oil ratio to expand propylene production. However, this can have a significant effect on the gas concentration section (GasCon).

For a GasCon revamp, the reuse of existing equipment to minimise CAPEX can place a constraint on increasing propylene production.

A simplified process flow diagram of a common conventional FCCU GasCon configuration is shown in Figure 1. The shift in FCCU processing to produce additional propylene generates higher volumes of dry gas, making it more difficult to recover propylene. Maintaining high recovery rates leads to higher loadings in the sponge absorber, primary absorber, deethaniser, debutaniser and C3/C4 splitter. When revamping existing units, these columns are often shell limited. Thus, it is normally expensive to replace or add in parallel these five columns by conventional means. While shifting the product slate towards petrochemicals makes sense for a forward-looking refiner, it must also be cost-effective for today’s business.

Therefore, to succeed in the shift from fuels to petrochemicals, businesses require more effective solutions.

FCCU GasCon revamp

DWC technology is ideal for a capacity-constrained FCCU gas plant, as it requires limited investments as well as simplified construction and minimal plot space.

As shown in Figure 1, the typical process train utilises six separate columns, although some GasCons have been designed with the primary absorber stacked on top of the deethaniser. This has the benefit of eliminating an additional foundation and bottoms pump, as well as reducing the plot space required.

The DWC design shown in Figure 2 relies on a single vessel that combines the sponge absorber, primary absorber, deethaniser and C3/C4 splitter altogether. This operates in parallel with the existing GasCon. Depending on the existing capacity of the wet gas compressor Figure 1. A simplified process flow diagram of a conventional FCCU GasCon. discharge cooler and high-pressure receiver, it may be best to add a separate cooler and high-pressure receiver in front of the new DWC. A DWC solution can reduce the load to the existing GasCon, helping to improve the recovery in the existing unit while supporting additional process loads resulting from the shift towards propylene production.

In addition to simplifying the revamp design, a DWC can recover larger volumes of propylene and deliver products with high purity levels. All of this is achieved while also increasing the overall processing capacity. Finally, the DWC can also be used to overcome limitations in plot space and the construction can be completed prior to a shutdown, Figure 2. FCCU GasCon revamp utilising GT-LPG MaxSM technology. limiting downtime to tie-ins only.

April 2022 40 HYDROCARBON ENGINEERING

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three to two, and the number of reboiler systems is diminished from four to two.

The DWC FCCU GasCon design can easily operate over the typical operating range of FCCUs and offers a solution with limited CAPEX. The lean design configuration helps businesses to achieve equal or higher product recovery and purity rates than conventional systems. For typical FCC reactor yields in maximum gasoline mode, this FCCU GasCon set-up can be used without the addition of a high-cost refrigeration system to provide propylene recovery rates greater than 97 vol%.

Figure 3. FCCU GasCon utilising GT-LPG Max and GT-DWCSM technology.

However, in reactor designs with demanding propylene yield numbers, it is necessary to use chilled cooling water for the primary absorber to The only potential limitation in a revamp such as this is maintain propylene recovery greater than 97%, which the bottom of the existing debutaniser and the bottom of would be required by a conventional GasCon unit in any the C3/C4 splitter. However, it is possible to overcome case. these challenges with key adjustments if this is the case.

As with a conventional system, intercoolers and other Typically, this will not be a problem due to changes in the design elements on the primary absorber can be utilised product slate. The shift in product slate decreases gasoline as necessary to obtain the desired propylene recovery. yield, which helps unload the bottom of the debutaniser.

For an FCCU operating in maximum gasoline mode, the typical DWC FCCU GasCon, with no chilled cooling water Grassroots FCCU GasCon system, is designed to recover more than 97% propylene, The DWC technology is also being used to replace entire C3 stream purity can reach 99% (combined C3s), and FCCU GasCons as well as in new facilities. A conventional mixed C4 stream purity should be greater than 96% design requires five or six columns to fractionate the (combined C4s).

FCCU naphtha and lighter compounds, which results in considerable investments. The use of a DWC for FCCU GasCons can significantly reduce CAPEX, as two vessels Conclusion alone can produce the same product streams as the Changes in the demand for global refinery products will typical design. In effect, the sponge absorber, primary continue to drive innovation in FCCUs. Currently, it is absorber, deethaniser and C3/C4 splitter are combined advantageous for refineries to increase propylene and into a single vessel, while the debutaniser and naphtha butylene extraction for the petrochemical industry, in splitter are merged together in a single unit. Figure 3 addition to high-octane gasoline production. DWC shows one configuration of DWC technology for solutions, such as Sulzer Chemtech’s GT-LPG Max and grassroots FCCU GasCons.

GT-DWC, can address these market demands while An example of a highly-effective DWC design is requiring limited investments. offered by Sulzer Chemtech. This utilises two advanced Pressure on corporations to limit fossil fuel DWC separation units, GT-LPG MaxSM and GT-DWCSM, to consumption, reduce carbon emissions, provide a lower carbon footprint, and have less impact on the optimise CAPEX while maximising the product recovery environment has made these considerations a real factor rate and purity level. The first column combines the in making business decisions. Competitive refineries sponge absorber, primary absorber, deethaniser and should be aiming to do more with less. A DWC system C3/C4 splitter, while the second merges the debutaniser provides processing plants with a key solution that has and naphtha splitter. low CAPEX, offering the distillation tools to meet a The reduction in columns reduces the number of plant’s processing objectives while also improving foundations required. Similarly, the amount of vessel sustainability and energy efficiency. metal is cut significantly, reducing foundation load and Ultimately, the use of DWCs can support businesses material cost. In addition, column insulation, ladders, in increasing the yield of petrochemicals from crude, platforms and similar pieces of equipment are also helping refiners to enhance their competitiveness in a limited. Finally, the number of condenser systems challenging sector. (exchangers, drum, pumps, controls) is reduced from April 2022 42 HYDROCARBON ENGINEERING

Matt Thundyil, Dave Seeger and Carl Hahn, Transcend Solutions, USA, discuss how effective contamination control can help operators to maintain resilient operations in the face of the energy transition.

T

he hydrocarbon and chemical processing industries are being disrupted by the transition to green energy. It is intuitive that fossil fuel processors will be under social, political and investor pressure to reduce their carbon dioxide (CO2) footprint, and this will affect their operating profitability. The winners emerging from this disruption will be those that have maintained operating excellence, and have adapted the fastest. As discussed in a previous article, one of the most critical factors affecting operating excellence is resilience in the face of disruptions to systems and varying feed streams to the facility.1 When a system is not resilient, it tends to fail, and failure can often translate into reduced throughput and uptime; increased operating costs and environmental impact; and ultimately a decrease in profitability. During paradigm shifts within industries, the less resilient players lose, and the more resilient players not only survive, but often thrive.

The resilience of a system is defined as the system’s capability to recover from anomalous operations, which are endemic in the process industry.

Anomalous operations are often characterised as ‘process upsets’, and can be caused by a myriad of factors beyond the control of the facility, including variations in feedstock, weather events (cold fronts, hurricanes, heatwaves, etc), or by reliability issues in support systems (power, environmental treating, etc). Most process facilities are interconnected to maximise operating

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flexibility and energy efficiency. The consequence of such interdependence is the propagation and amplification of any anomaly in the operation. Figure 1 illustrates this.

What if that propagating anomaly could be intercepted? In a resilient system, a black box that absorbs the anomaly allows the system to operate without any fluctuation caused by the anomaly. This concept is captured in Figure 2, where a black box (in the feed to the green unit) can absorb fluctuations in the

feed, providing a stable feed to the green unit, and therefore to all downstream systems.

Contamination as a process anomaly There are many different types of anomalies that can afflict a process system. Contamination is one of them. There are a variety of ways that contamination is introduced into the system, including the following: nn Feedstock can be contaminated (sand, corrosion products, treating chemicals, immiscible liquids, etc). nn Pipelines can corrode. nn Corrosive chemicals are used or formed (chlorides, carbon dioxide, hydrogen sulfide [H2S], sulfuric acid, caustic, etc). nn Aggressive operating conditions (high temperature, high pressure, etc).

nn nn nn nn nn

Figure 1. An anomaly in the feed to the green unit

cascades to downstream units, resulting in the amplification and transmission of this anomaly into additional systems.

Figure 2. An anomaly in the feed to the green unit is absorbed by the black box, assuring stable feed to the downstream units.

Contamination can take a number of forms, as listed below: Solid particles in gases.

Solid particles in liquids.

Liquid droplets in gases.

Immiscible liquid droplets in other liquids.

Dissolved or vaporised contaminants in either liquids or gases.

Contamination can also affect a process in a variety of ways, including: nn Heat exchanger fouling. nn Catalyst or adsorbent bed fouling. nn Column foaming or fouling. nn Rotating equipment (compressor, pump) fouling and damage. nn Turbine or generator damage. nn Valve or pipe wear.

Contamination control systems are engineered into most process systems, as the impact of contamination on process instability is well accepted, even if it is not well understood.

These systems take the form of filters, coalescers, separators, strainers, etc. The challenge that most plants face is that the contaminants in their systems are not effectively removed by the units that are expected to remove them. The effect of persistent contamination – and its impact on process instability, downtime, reduced throughput and increased operating cost – typically becomes accepted as the prevailing paradigm. When an entire industry is disrupted, accepting the prevailing paradigm trap is not a winning strategy. Rather, the winners are those that transcend the paradigm. Breaking the paradigm often involves asking ‘would we face these issues if the system was clean?’ This simple question points operators in the direction of the root cause, and its solution. Thundyil et al have recently illustrated that operational excellence through effective contamination control is possible without significant capital expenditure, if operators know precisely where to look.2

Example one: heat exchanger fouling

Figure 3. Generic SRU schematic.

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Heat exchanger fouling is often caused by contamination in process streams. The consequent loss of heat transfer frequently results in the additional energy being expended to overcome the loss in heat transfer coefficient. In some cases, the lost heat transfer cannot be overcome, and the consequence is a direct

loss in production. Many cryogenic heat exchangers operate in complex, interconnected, energy-integrated services where any loss in heat transfer results in a loss in recovery. In the hydrocarbon processing market today, the most common examples of cryogenic exchanger fouling are in NGL recovery facilities, and LNG production facilities.

Consider, for example, a typical 5 million tpy LNG train (equivalent to 700 000 000 ft3).

The production margin on natural gas conversion to LNG is greater than US$0.015/ft3. (a) 1% loss in recovery costs 0.01 x 700 000 000 ft3 x US$0.015/ft3 = US$105 000/d. (b) A single day outage costs 700 000 000 ft3 x US$0.015/ft3 = US$10 500 000 of lost revenue per event.

Similarly, consider a 200 000 000 ft3 cryogenic recovery facility that produces 30 000 bpd of NGL. The NGL recovery margin is approximately US$40/bbl. (a) 1% loss in recovery costs 0.01 x 30 000 bpd x US$40/bbl x 365 d/yr = US$4 380 000/yr. (b) A single day outage costs 30 000 bbl x US$40 = US$1 200 000 of lost revenue per event.

Example two: hydrocarbon contamination of sulfur plant feed Globally, air quality considerations have impelled the installation of sulfur recovery units (SRUs) within hydrocarbon processing facilities where sulfur compounds are present. These SRUs are most commonly Claus units where sulfur compounds are oxidised in an air-deficient environment to produce elemental sulfur, and the tail gas is reduced back to H2S to be recovered and recycled in order to minimise sulfur emissions. The feed to the sulfur plant is commonly from the acid gas removal unit (AGRU) and the sour water stripper (SWS) unit. If hydrocarbons are present in either of these streams, they can end up in the sulfur plant feed on either a continuous or episodic basis. Figure 3 illustrates a generic scheme.

Note the 2:1 ratio of H2S and sulfur dioxide (SO2) that is required to form sulfur as part of the Claus reaction. This ratio is managed by means of a H2S/SO2 analyser that controls the air demand to the SRU. If hydrocarbons are entrained into the SRU, they consume considerably more oxygen (8 – 30 times more) than the same molar quantity of H2S depending on the length of the hydrocarbon chain in question: H2S + 0.5O2 = S + H2O C3H8 + 5O2 = 3CO2 + 4H2O C9H20 + 14O2 = 9CO2 + 10H2O

(1) (2) (3)

The oxygen consumed by combusting hydrocarbons will starve H2S conversion to SO2 and affect the air demand analyser, resulting in intermittent excursions of SO2 into the tail gas treating unit (TGTU). SO2 breakthrough to the TGTU will cause corrosion and column instability in addition to affecting environmental emissions. Further to this, oxygen consumption by hydrocarbons reduces the amount of oxygen available to combust H2S, and if the refinery or gas plant is environmentally regulated, the reduction in capacity to treat H2S has a direct impact on refinery crude capacity. For example, a typical 250 000 bpd refinery treating a 3 – 4% sulfur crude will have a 1000 tpd sulfur plant. The production margin of a sour refinery is approximately US$10/bbl of oil processed. nn 1% loss in crude capacity = 0.01 x 250 000 bbl/d x US$10/bbl x 365 d/yr = US$9 125 000 /yr. nn A single day outage costs = 250 000 bbl x US$10/bbl = US$2 500 000 lost profit per event.

Identifying a path forward Refineries, midstream cryogenic recovery gas plants, and LNG plants are the three largest hydrocarbon processors in the energy segment, outside of coal. As fossil fuel processors, these are the companies that will be immediately and directly affected by the energy transition. They are highly integrated and highly susceptible to contamination-related process upsets. In many cases, the plant already has a separator in place, but it is just not performing HYDROCARBON 45

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at the level that is needed. As a result, contamination makes its way downstream. If the separator in question can be upgraded to mitigate the contamination, will it improve operating excellence? Obviously, there is a need to characterise the contaminant, verify compatibility with the process, validate the capability, and estimate cost. In virtually all cases, a tremendous impact on operating excellence ensues without significant

capital expense, or with exceptionally high return (< one year ROI) capital expense.

Case study: LNG production facility – protection of cryogenic heat exchanger As discussed, cryogenic heat exchangers are very sensitive to fouling. The cost of lost efficiency or downtime is significant.

Faced with fouling, a large LNG facility was interested in evaluating its feed dust filters to the cryogenic heat exchangers.

A photomicrograph of the contamination captured from the product is illustrated in Figure 4.

The presence of large contaminant particles indicated inadequate performance of the dust filters onsite. An evaluation of those elements indicated poor sealing (as seen in Figure 5), and the use of inefficient media technology. An upgrade to the conventional separator was developed to improve the sealing and media efficiency, and enhance operating ergonomics.

Case study: sour water stripper A refiner experienced hydrocarbon contamination of its sour water unit. The foulant was affecting the feed-bottoms exchanger and required frequent cleaning. In addition, the lost heat transfer was affecting the energy efficiency of the stripper column. Finally, a fraction of the hydrocarbon contaminant was in a boiling range that would build up within the column. As such, Figure 4. Scanning electron micrograph of a the risk of episodic hydrocarbon carryover to the sulfur plant contaminant entering the brazed aluminium cryogenic was endemic. The feed was routed through a high-efficiency exchanger section of an LNG plant. particle separator and high-efficiency emulsion separator which were part of a Transcend TORSEPTM demonstration system, prior to contacting the heat exchangers. The impact on the heat exchanger was immediate. Figure 6 shows pictures of the inlet sour water and the TORSEP effluent. The pressure drop of the exchanger immediately plateaued and even decreased. The exchanger has not required cleaning in over three years. The downstream sulfur plant reported no hydrocarbon excursions following the installation of the system. The refiner was so impressed that it Figure 5. Sealing surface of the dust filters. Left: the groove of the bought the demonstration system. ‘knife edge’ sealing surface. Right: the regions where the elastomer does not seal.

Conclusion The disruption caused by the energy transition is imminent. The winners will be the operationally excellent and resilient.

Implementing operating excellence and operating resilience is a high return investment, and often requires no new capital expenditure as existing equipment can be upgraded. The key to operating resilience is understanding where risk tolerance is to be implemented.

Among the easiest to identify are contamination control related resilience.

References Figure 6. Sour water feed prior to the TORSEP system (left) and after (right).

April 2022 46 HYDROCARBON ENGINEERING

1. THUNDYIL, M., SEEGER, D., and HAHN, C., ‘Beyond band-aids’, Hydrocarbon Engineering, (March 2021), pp. 75 – 80.

2. THUNDYIL, M., SEEGER, D., and HAHN, C., ‘Operating excellence without capital expense’, Hydrocarbon Engineering, (November 2021), pp. 57 – 61.

Tai Piazza and Geoffrey Bowers, VEGA, USA, explain how non-intrusive radiometric instruments can improve level control in the continuous catalyst regeneration (CCR) and propane dehydrogenation (PDH) unit.

C

atalytic reforming accounts for a large share of the world’s gasoline production, and it is the most important source of aromatics for the petrochemical industry. The process converts low-octane naphtha to higher value aromatics and blending feedstock for the gasoline pool. Metal catalysts are used in the reformer unit for the conversion of refinery and petrochemical feedstocks into more desired products. In order to ensure the continuous operation of the reformer, the metal catalyst must circulate through the unit so that coke build-up is burned off and the catalyst can be regenerated on a continuous use.

Additionally, metal catalysts are used in the generation of propylene from propane feedstocks by dehydrogenation in propane dehydrogenation (PDH) units. Again, to maintain higher reactivity, the metal catalysts must be decarbonised and rechlorinated for use on a continuous cyclic basis.

In these process train operations, a continuous catalyst regeneration (CCR) unit is often included, which is tasked with taking spent catalyst from the HYDROCARBON 47

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conversion unit, regenerating the reactivity of the catalyst, and returning the recovered catalyst back to the operating unit.

Specifically, these units are included in catalytic reforming within refineries and PDH units at petrochemical plants with polypropylene (PP) production. The advent of CCR technology has addressed a growing need for gasoline and aromatics

Figure 1. Continuous level measurement.

production while significantly decreasing environmental impact and improving industry economics. This is why, as of today, more than 500 units have been licensed worldwide.

Non-contacting measurements to support high-temperature and erosive process There are three main pieces of hardware that make up the catalytic reforming unit: the reaction section, the regenerator, and the fractionator. In each of these hardware sections, level control is very important in order to ensure efficient and safe unit operation. Over decades, radiometric technology has proven to be the most reliable instrumentation technology for catalyst level control. Since radiometric technology does not make contact with the process, the level instrumentation is not directly exposed to the high temperatures and abrasive conditions of the process medium.

The primary function of the radiometric instruments is to provide inventory control of the catalyst as it exits the process unit, and to control batched volumes of catalyst as it passes through the regeneration process.

This ensures that catalyst reactivation is continuous and reliable for the unit. Tightly controlling the batched volumes has two benefits. The first is the assurance that the catalyst is entirely regenerated before reintroduction into the process unit; the second is the maintenance of minimum pressure drop between vessels in the CCR. This allows the material to proceed through the unit without the addition of unwanted mechanical force. A real-world example of how various VEGA ProTrac radiometric sensors are used in these applications will be discussed later in this article.

Radiometric measurement to support material mass flow and pressure balance

Figure 2. Point level measurement.

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The CCR consists of multiple vessels. The first is the spent catalyst disengaging hopper, which receives spent catalyst from the production unit. This vessel operates at a high temperature, which is similar to that of the operating process. Within the vessel, there is a continuous level measurement that acts as an inventory control of the surge zone. The level measurement can be made with VEGA’s FiberTrac 31, with its flexible, lightweight and scintillating fibre bundle; or the SoliTrac 31, with maximum sensitivity to reduce source activity. In both of these cases, due to the high operating temperature of this hopper, care should be taken to prevent heat transfer from the vessel to the instrumentation at the point of installation.

To initiate opening and closure of a valve for moving the spent catalyst into the regeneration zone of the CCR by gravity feed from the spent catalyst disengaging hopper, the MiniTrac 31 is used as a low limit switch.

Reliable switching is necessary to prevent the process from reaching the point of empty condition. The location of the radioactive source as it relates to the

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measurement ranges for the continuous level and switch points defined by the process licensor is important, in order to ensure proper unit performance (see Figure 1).

The spent catalyst then moves to the regeneration section of the unit, whereby the catalyst is cleaned of process deposits before chemical activation occurs.

Similarly, a continuous level measurement and low level switch are used to control the batch of catalyst as it proceeds through the unit. The radiometric point level measurements in particular can be calibrated to change state under very specific conditions against the mounding of the catalyst material or cone. This allows for optimised process control of the regeneration process (see Figure 2).

Once the ‘like new’ catalyst reaches the final stage, it is captured and stored in the regenerated catalyst storage hopper. From here it will be reintroduced to the operating unit via pressurised gas flow. This is carried out by the batching method to ensure that the proper volume of catalyst remains inside the operating vessels.

Both radiometric level and point level instruments are used to ensure optimal utilisation of regeneration capacity, and efficient usage of regenerated catalyst volume.

There are additional lock hopper vessels that accept reprocessed catalyst as it passes between the regenerator and the regenerated catalyst storage vessel

that also utilise radiometric instrumentation. The function is again to maintain a pressure barrier between upstream and downstream vessels. The pressure differential comes from the higher pressure required to push the regenerated catalyst back into the operating vessel.

Conclusion Radiometric systems are used throughout the catalytic regeneration process to ensure a smooth and continuous reactivation process. Radiometric measurements have decades of proven, in-use experience in the CCR and PDH unit by providing reliable catalyst control and, consequently, ideal utilisation of units capacity.

VEGA’s ProTrac series of radiometric instrumentation is well-designed for the unique demands in the CCR unit. These radiation-based sensors enable the precise measurement of bulk solids under extreme process conditions, such as high temperatures and highly-erosive environments in the material flow of metal catalysts. In the instance of both new and existing projects, radiometric instruments can be added without vessel modification and installed while the unit is in operation, as the instrumentation does not make contact with the process. The measuring principle offers maximum operational safety and reliability, while requiring no maintenance or recalibration.

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Carolina Stopkoski, FLEXIM AMERICAS Corp., USA, and Jörg Sacher, FLEXIM GmbH, Germany, discuss the advantages of non-intrusive ultrasonic flow measurement in high-temperature bottom of the barrel applications.

R

efiners face a multitude of challenges today. While global fuel demand will likely decline in the mid-term as a result of the energy transition, leading to overcapacities and decreasing prices, demand will instead continue to shift to high-quality and clean products.

The task therefore resembles modern hydrocarbon alchemy: efficiently converting crude oil of varying and increasingly lower quality into marketable products.

Feedstock variability impacts product quality and unit reliability. One crucial factor is the processing of heavy crude oil fractions – the so-called ‘bottom of the barrel’. These mixtures, composed of long-chain hydrocarbons that remain as residue during atmospheric and vacuum distillation, place the highest demand on equipment. As such, the profitability of any refinery depends on efficient operations. It is therefore of huge importance that refinery operators enhance the reliability of

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equipment in order to extend run lengths and minimise the impact of shutdown. Plant availability is crucial.

High-temperature flow measurement Reliable and accurate flow control is a prerequisite for safe and efficient refinery operation. Measuring residue flow is a particularly demanding task. The main challenges are high viscosity of the fluid, entrained abrasive particles, and high temperatures. Despite their well-known shortcomings, conventional flow measurement instrumentation still depends upon differential pressure (∆P) measurements. These wetted devices suffer from coke formation on the primary element and, more importantly, clogging of the small pressure taps. As a result, they tend to require a lot of maintenance. Further disadvantages of ∆P measurements are resulting pressure losses, impaired energy efficiency, and limited measurement dynamics (turndown).

Due to its practical advantages, external flow measurement with clamp-on ultrasonic transducers has become a standard measuring technique across a broad range of industries and applications. Experts are happy to resort to non-invasive technology when it comes to measuring the flow of complex media. Measuring with clamp-on transducers mounted on the

Figure 1. Operation principle of the WaveInjector:

metal plates separate the transducers thermally from the hot pipe, whilst ensuring the best acoustic contact.

outside of the pipe means measuring from the safe side. Since the transducers do not come into direct contact with the medium flowing inside, they do not suffer wear and tear.

Non-intrusive measurement also means no pressure loss and no risk of leakage. Furthermore, the acoustic method provides high accuracy over an extremely large measuring range, independent of the flow direction.

For over three decades, FLEXIM has provided non-invasive solutions for challenging flow measurement tasks. Today, the company offers clamp-on ultrasonic equipment for a range of industries.

Patented technology Almost 20 years ago, FLEXIM introduced its high-temperature device, the WaveInjector, which extends the application range of non-intrusive clamp-on ultrasonic technology to temperatures of up to 600°C. The working principle of the patented transducer mounting system is simple: it separates the ultrasonic transducers thermally from the hot pipe while simultaneously ensuring optimum acoustic contact. Heat is radiated via large steel plates so that the temperature at the coupling points of the transducers is within their working range.

The installation equipment provides continuously high-contact pressure on the supporting surface. Specially-designed metal foils ensure optimal connection and long-term stability.

It is available in various sizes that cover a number of pipe diameter ranges. As it is a purely mechanical arrangement, it can also be used in hazardous atmospheres. It is not necessary to cut into the pipe in order to install the transducers. They can also be retrofitted without downtime or complicated approval procedures. The other advantages of clamp-on measurement still apply, such as not being dependent on pressure or media, no wear caused by the medium, and high measurement dynamics.

The WaveInjector was invented specifically for the refining industry. Its development followed the general evolutionary pattern which characterised the establishment of ultrasonic technology as a common method for flow measurement. At the beginning, refinery operators welcomed the new technology only when they urgently needed to find a means to replace temporarily failing measuring devices and therefore to extend the availability of the respective plant until the next planned turnaraound.

As the ultrasonic systems proved to be reliable and accurate, they were then not dismantled during the turnaround, but remained as redundancy for the existing ∆P measurements. In most cases, roles changed after the next turnaround: ∆P measurements were not dismantled, but remained as redundancy for the non-invasive ultrasonic measurements.

Safety matters

Figure 2. Ultrasonic transducers mounted on a WaveInjector during installation.

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Absolute safety is the number one priority in refinery plants.

Flow measurements often have the capacity to monitor the safety-relevant continuous passage of fluids, and with them, energy (i.e. heat). FLEXIM’s product portfolio includes non-intrusive flowmeters with SIL certification to fulfil safety functions according to IEC/DIN EN 61508. Dual-channel measuring systems allow for the creation of redundant configurations by combining different transducer types.

Non-invasive high-temperature flow measurement solutions for refineries and petrochemical facilities FLEXIM‘s non-invasive clamp-on ultrasonic technology provides refineries and petrochemical facilities with a ‘fit for purpose’, durable and cost-effective flow measurement solution.

Mounted onto the outside of the pipe, clamp-on ultrasonic transducers do not suffer any wear and tear from the media flowing inside. FLEXIM’s patented WaveInjector® mounting fixture extends the application range of non-invasive flow measurement technology to extreme temperatures up to 630 °C.  Non-invasive flow measurement at extreme temperatures from -200 °C up to 630 °C  Installation without opening of the pipe and without process interruption  No contact with flowing media – no impulse lines to clog – free of wear and tear  Certified for use in hazardous locations (ATEX/IECEx Zone 1&2, FM Class I, Div. 1 / 2 and SIL2 approved)  Wide range of ultrasonic transducers and transmitters to match any flow measurement application  Robust, durable, and environmentally friendly – zero potential for leakages www.flexim.com info@flexim.com

Although clamp-on ultrasonic measuring systems do not come into direct contact with the fluid, they are not completely unaffected by scaling.

Deposits on the inner pipe wall attenuate the ultrasonic signal and lower the measuring accuracy. To achieve the highest possible accuracy and guarantee absolute reliability at all times, a combination of ultrasonic transducers with higher and Figure 3. Non-intrusive ultrasonic flow measuring points in the five processing units lower signal frequencies in of Sinopec ZRCC’s hydrocracker. different measuring arrangements has proven its worth: higher-frequency transducers in a reflex arrangement ensure high accuracy, while low-frequency transducers in a one-path arrangement guarantee the absolute reliability of the measurement.

In addition, ultrasonic measurement technology provides meaningful diagnostic values that can be used for predictive maintenance, such as pipe cleaning.

Today, the WaveInjector is a widely-accepted solution for high-temperature flow measuring tasks in refineries, and is increasingly used for flow measurement instrumentation in bottom of the barrel applications, e.g. for measuring the flow of residues of atmospheric and vacuum distillation as well as feed and residue measurement in coking, visbreaking, hydro, and fluid catalytic cracking operations.

Figure 4. WaveInjectors in the reaction unit of the hydrocracker at Sinopec’s ZRCC during commissioning.

The insulation only needs to be temporarily removed to install the WaveInjectors with the clamp-on ultrasonic transducers on the pipe.

Figure 5. All flow measuring points in Sinopec’s hydrocracker are equipped with explosion-proof transmitters. As pictured, there are three dual-channel FLUXUS F801SR units for safety-related applications, and one FLUXUS F809 in the background.

April 2022 54 HYDROCARBON ENGINEERING

Case study: the Sinopec hydrocracker project Founded in 1975, Sinopec Zhenhai Refining & Chemical Co. (Sinopec ZRCC) is currently the largest integrated refining and chemical company in China. Under its quality policy of ‘making every drop of oil count’, the company commits itself to providing clean products for society, producing intermediate petrochemical products to supply downstream, which ultimately produces a range of high-end petrochemicals. The variety of its refining and chemical products comprises more than 50 distinct products, including different grades of gasoline, jet and diesel fuels, asphalt and polypropylene plastics, etc.

Sinopec ZRCC has a hydrocracker in addition to many other refining units. Hydrocracking is a refining process for upgrading low-quality heavy gas oils from the atmospheric or vacuum distillation tower, the fluid catalytic cracker and the coking units into high-quality, clean-burning jet fuel, diesel, and gasoline.

A hydrocracker takes gas oil, which is heavier and has a higher boiling range than distillate fuel oil, and cracks the heavy molecules into distillate and gasoline in the presence of hydrogen and a catalyst. Two main chemical reactions occur in the hydrocracker: catalytic cracking of heavy hydrocarbons into lighter unsaturated hydrocarbons, and the saturation of these newly-formed hydrocarbons with hydrogen. Catalytic cracking of the heavier hydrocarbons absorbs heat and cools

the feed as it progresses through the reactor. The saturation of the lighter hydrocarbons releases heat and causes the feed and products to heat up as they proceed through the reactor.

There are various methods of hydrocracking with different ways to bring the residue feed, catalyst and hydrogen to reaction. Sinopec ZRCC’s hydrocracking unit uses ebullated-bed technology to process heavy feedstock residues (atmospheric and vacuum residue) with high contents of metals, sulfur, nitrogen, asphaltenes and solids. One major advantage of this technology is that there is virtually no limit to operation time, as fresh catalyst is continuously added and spent catalyst withdrawn to control the level of catalyst activity in the reactor, enabling constant yield and product quality. Where conventional fixed-bed residue hydrotreaters are limited to catalyst cycle intervals, this patented process can achieve the 2 – 4 year turnaround cycles to match that of the FCC unit, and requires only one or two reactors.

One major challenge of all hydrocracking technologies lies in their process conditions. Hydrocracking combines high temperatures with high pressure. In Sinopec’s hydrocracking unit in Ningbo, China, the reactors need to operate at high temperatures of up to 468°C with pressure up to 28.9 MPa in order to maintain the high conversion rate of residual oil.

The original plan was to install wedge meters for flow measurement when construction of the hydrocracking unit began in summer 2017, even though the shortcomings of ∆P measurements were well known. ∆P measurements are challenged by both the viscous fluid with its high content of coke particles, and by the metal catalyst. Therefore, both

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operator and licensor agreed that these would not be optimal for the types of crudes that the plant would be processing and could create potential leak points and blockages, resulting in plant shutdowns. The search began for suitable ultrasonic metering instrumentation that could cope with dirty mediums and extremely high temperatures. Furthermore, it was important that this technology could be standardised in the plant and could be used in Proportional-Integral-Derivative (PID) control and emergency shutdown applications where zone 1 explosion-protected equipment with SIL2 certification is required.

After intense discussions, exhaustive investigations, comparisons of technologies, and empirical verifications of their respective performances, Sinopec ZRCC decided to replace all wedge meters for high-temperature and high-pressure flow measuring points in its hydrocracking unit with the WaveInjector.

In total, FLEXIM equipped 43 measuring points with clamp-on ultrasonic flowmeters. Installation and commissioning was completed during the plant’s start-up in 2020.

Conclusion Non-intrusive ultrasonic high-temperature flow measuring technology has evolved over time to become an established standard method. Increasing variability of crude oil and feedstock makes flexibility in refining operations a decisive competitive factor. When flexibility is decisive, plant availability is crucial. Therefore, non-intrusive flow measurement proves to be an excellent solution, offering high measurement dynamics and flexibility, whilst never impairing plant availability.

April 2022 56 HYDROCARBON ENGINEERING

Neil Murch, Tracerco, UK, details the use of nucleonic instrumentation and technologies to deliver efficiency and performance gains in downstream refinery processes.

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s the energy industry looks to align with other global industrial trends to decarbonise production operations and become more sustainable, greater emphasis will be placed on the downstream oil and gas sector to meet climate change targets, such as those set out by the Paris Agreement.

Operators have a key role to play in delivering increased energy efficiency and reductions in greenhouse gas (GHG) emissions by investing in technology to enable process improvement and asset optimisation. There are significant investment and operational challenges associated with emerging initiatives such as electric cracking and replacing feedstocks, but there are other, lower-cost options that can be implemented over a much shorter timeframe to improve efficiency and potentially reduce emissions.

Instrumentation is a vital part of process control – it provides information to operators to assist in decision making, and acts as a safety function to prevent unplanned or unsafe conditions from occurring. However, it can often be overlooked as an area for improvement. There are technologies that lend themselves to troubleshooting production problems and process optimisation, such as neutron backscatter (NBS), tracers, and gamma scanning, along with fixed instrumentation that can offer more than just a conventional signal output. Only by having a complete understanding of the process through these valuable insights can operators make the changes required to deliver safer and more efficient production.

The refining process is energy intensive, and searching for opportunities to reduce energy consumption – especially when considering the volatility in the wholesale gas market – is becoming more of a priority. The industry is shifting to greener energy production and a number of oil and energy majors have recently announced plans for blue and green hydrogen production facilities.

While greener sources of process energy are important, so too is optimising oil and gas processes to reduce consumption.

Gaining process insight Following a number of recent projects in crude desalter units (CDUs) for Tracerco’s refining customers, the company found that process insight through scanning and instrumentation has given operators more confidence through evidence-based analysis to deliver more efficient operations. The use of NBS to preliminarily identify ongoing issues and upsets to guide process improvement, whilst maintaining continued control for ongoing efficiency, is achieved through instrumentation.

While scanning can provide a snapshot in time, an advanced nucleonic instrument facilitates the continuous monitoring of process fluids in process vessels to enable efficient control of multiple interfaces,

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reducing demand for electrical grid transformers and improving salt removal efficiency (SRE) to decrease overhead corrosion and heat demand.

Figure 1 shows NBS scan line data from three sections of a first stage desalter. The technology works by using the nucleus of the hydrogen atom to slow down high-energy neutrons, thereby turning fast neutrons into slow neutrons. Fast neutrons penetrate the vessel wall and interact with the process contents, and if hydrogenous, slow neutrons diffuse back out to the detector adjacent to the neutron source. The signal level or intensity at the detector fluctuates rapidly when the

hydrogen concentration behind the vessel wall changes, which is at the following interfaces: vapour and liquid, liquid and liquid, or liquid and solid. The analysed signal data in Figure 2 illustrates that solids removal performance is good in this vessel, although the operating levels are low, and an average of 22% by volume of the vessel is made up of emulsion. Other scans as part of the study on the second stage desalter were as high as 30%. It is apparent from the data that the emulsion layer can be reduced, increasing the available volume in the vessel, by adjusting chemical additive dosing to the appropriate level.

Additional scans at varying intervals can start to build a process picture, however ongoing monitoring of multiple data points over the operating ranges can provide greater insight.

Trending operating levels continuously over time provides the next layer of process analysis, with the ability to inform process set points and maintenance regimes based on proven data, while also offering the capability to diversify crude blends.

Emulsion control is one challenge related to crude blending, while maintaining continued operations and efficient removal of water, chlorides and other base impurities is equally important to the ongoing separation efficiency of the unit.

Proven solutions

Figure 1. Tracerco NBS scan line data.

Figure 2. Tracerco analysis of scan data.

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Tracerco’s ProfilerTM technology allows data to be captured across all of the process fluids, in order to build a true process fluid profile. The instrument is customisable to the measuring range requirements and utilises low-energy gamma to differentiate fluid density over its discrete point detector array.

The Profiler takes the field signals and applies proprietary algorithms to deliver high-resolution measurements for use with the asset’s distributed control system (DCS). While providing this information to the operator in real time, the instrument is also capable of offering trend functionality where information can be displayed in an easy-to-interpret format that enables unit engineers to visualise and analyse process data to better understand upsets and bottlenecks, leading to increased efficiency. The Profiler can be used for monitoring or interface control, even in shutdown functions.

Having limited visibility of the position or extent of interfaces due to inappropriate instrumentation can lead to increased demand on electrostatic grids, ultimately resulting in a trip or a greater amount of oil in water due to carry under. This could potentially affect wash water quality. Figure 3 is taken from the Profiler trend analysis and shows an unplanned process outage from a first stage desalter. The water and emulsion phases can be seen to increase, reaching the electrostatic grids, and overloading the transformers. Outages such as these are entirely preventable when the correct technology is deployed to monitor and control process levels.

Efficient separation is key to high-performing refinery CDUs. Having increased levels of chlorides in desalted crude can lead to issues such as reduced product quality, overhead corrosion, and potential

See inside your process with the Profiler TM

Like a real-time window into your desalter, the Tracerco Profiler™ helps you improve product quality, reduce downtime and enhance safety. It’s the only field-proven interface level technology designed to measure the vertical distribution of multiple process fluids, in real time and at high resolution.

• Process opportunity crudes with confidence • Optimise processes and increase throughput • Measure and control individual phase levels • Reduce corrosion • Improve environmental compliance • Accurately control addition of chemical additives

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catalyst deactivation further downstream, among others.

Figure 4 shows monitoring of the increasing emulsion layer over time, which can stem from blending alternate feedstocks, overmixing of wash water, or overdosing of emulsion breakers.

The visualisation provided by utilising high-resolution measurement allows refinery operators to achieve more precise interface positioning, leading to optimised mixing valve pressure drop, wash water droplet size, and desalter separation performance.

When attempting to categorise other effects to downstream processes through instrumentation, it is important to have the technology toolkit available to diagnose and address issues. There are a number of diagnostic techniques

Figure 3. Process outage trend from Tracerco Profiler.

available using isotopes to assess liquid levels in columns, for example, and nucleonic technology overcomes some of the most challenging processes. Conventional nucleonic level instruments using scintillators provide a very accurate form of measurement, although the reliability of measurement can be susceptible to changes in process conditions. Gamma-ray absorption systems function on the principle of measuring a difference in the radiation field between two process densities, namely liquid and gas. Liquid is denser than gas and attenuates most or all of the signal, allowing the detector to measure the top of the liquid. Upsets occur when there are changes in the gas field in the form of solid deposition on the vessel wall, or liquid fall from overflowing trays. These increases in density impact the detector signal and affect the overall level output of the instrument. The segmental technology of the advanced nucleonic instrument OptimusTM overcomes this challenge.

Figure 5 shows the representative change in level output due to changes of density in the vapour section of the column bottom, vs the corrected signal output of Optimus. By using multiple measurement points along the instrument’s detector length, as well as specially-designed algorithms, the instrument can differentiate between false liquid level and true liquid level. This additional level of insight reduces the possibility of liquid carryover or gas blowby in the event of a false level, providing a versatile and reliable instrument in a range of measurement applications. The system offers a conventional analogue output to the DCS, as well as over 150 variables through HART to provide corrected process level, build-up levels and, in some cases, foam height. The technology is non-contact with the process, making it ideal for retrofit level applications where non-segmented measurement technology may be struggling to meet unit performance requirements.

Conclusion Figure 4. Emulsion increase trend from Tracerco Profiler.

Figure 5. False level change due to build-up.

April 2022 60 HYDROCARBON ENGINEERING

Accurate and reliable instrumentation systems are a necessity to operate safely, productively and efficiently, while offering added value to refinery operators and process engineering teams who are looking for additional levels of insight to make better-informed operational and process decisions. The use of nucleonics and these field-proven technologies is not limited to the most challenging applications, but can be deployed to optimise process measurement and control on a variety of level, density or interface applications across downstream process systems.

Tracerco is recognised for delivering technologies that enable operators to make informed decisions on the condition of their assets. The technology outlined in this article has been field-proven across hundreds of installations, and acts as the level and interface control solution for millions of barrels of oil processed every day.

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Gregory Shahnovsky, Ariel Kigel and Gadi Briskman, Modcon Systems, discuss the use of novel technologies to advance process optimisation in hydrocarbon processing.

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aunched in 2015, the World Economic Forum initiative has determined digitalisation as an indisputable requirement, resulting in the oil and gas industry taking a fresh look at its boundaries. The pandemic has accelerated digitalisation, and companies quickly learned that they had to become more agile to respond to significant disruptions and demand fluctuations when the COVID-19 crisis diminished demand for oil and gas almost instantly.

At present, the oil and gas sector must be flexible enough to respond immediately to the changes in feedstock product demand as a result of the changing global economy. The hydrocarbons industry has become more sophisticated, with heavy investment in cleaner fuel production, molecular recycling, plastic waste reduction efforts, and more efficient and environmentally-friendly production methods. Economic process optimisation is now a fundamental requirement and the only solution to survive in competitive markets.

In order to fully exploit the economic optimisation potential of a technological process, the approach of working in the paradigm of optimising control should be taken, as opposed to addressing optimisation and control problems as two separate tasks. This article demonstrates how the trend for convergence of process optimisation and multivariate control has evolved, and discusses the computational roadblock that is standing in its way. It also explores how artificial intelligence (AI) can overcome these constraints without compromising the process modelling fidelity.

Ramo-Wooldridge Co. at the Texaco Port Arthur refinery polymerisation unit in Texas, US. The project included the digitisation of sensor readings and control outputs. The algorithm approximated the economically-optimal process parameters using the measurement from the sensors. The implemented algorithm performed multivariate control, but a significant component was missing.

The next major step in multivariate process control was to consider the delay between a change in the process parameters and the delayed response of the process. This technology was named Model Predictive Control (MPC), and its commercial deployment began in the 1970s. The first industrial application of MPC algorithms could be traced back to Shell Oil’s internally-developed controller in 1973. The linearised model of the dependencies between the manipulated and controlled variables and a quadratic form of the optimised cost made its implementation feasible with the computers available at the time. This notation of the optimisation problem allowed for a straightforward and achievable solution.

Multivariate process control The first computer usage for multivariate process control can be traced to the 1959 deployment of the RW-300 computer by

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The impact of applying MPC on the stabilising process is demonstrated in Figure 1. Remarkably, linearised modelling of the controlled plant remains the mainstay of MPC implementations to this very day.

Further developments Over the years, the MPC algorithms developed by the major vendors were further refined. Among the introduced improvements have been supporting constraints on control variables, prioritisation of control objectives, and robustness to plant model mismatch. Plant model evaluation through step-testing improved over time, increasing the degree of automation and reducing the time needed to learn the linear dynamic model of the system, known as gain matrix.

The target process trajectories to be followed by MPC are calculated by a group of products called real-time optimisation (RTO). These products are based on finding the economically optimal state of the process based on solving ordinary differential equations describing its steady state. Due to their computational complexity, RTO solutions were first commercially-introduced in the late 1980s. However, the adoption of RTO systems by the industry has remained moderate. One of the reasons for this is high maintenance complexity requiring an employee skillset that is not readily-available at the processing plants.

Possibly as a way to respond to the processing industry’s slow adoption of RTO solutions, since the early 2000s MPC products have started to incorporate optimisation capability by including an economic component in their objective function. This notion of cost allows an economically-optimal working point of the process to be found, based on the controller’s linear process model. The Honeywell Profit Controller is an example of an MPC solution with an embedded economic optimisation ability.

Economic optimisation within the MPC has its drawbacks.

The linearised process model based on the traditional MPC reduces the precision of the economically-optimal process setpoints calculation in approximating inherently non-linear parameter dependencies. Analytical modelling of the process limits its fidelity, as it does not account for the aspects of process dynamics that cannot be expressed explicitly.

The linear formulation of MPC was necessitated by computational limitations of computers in the late 1970s. Since then, non-linear MPC (NMPC) products have been offered by the major MPC technology vendors. Nevertheless, their adoption by the industry has been relatively limited. A possible cause for that could be a concern related to the numerical stability of repeatedly solving a non-linear optimisation problem in real time.

The industry has taken a different approach to dealing with non-linear processes, which entails continuously updating the linearised gain matrix of the MPC by using a digital twin of the process, based on first-principle models. This approach can be defined as dynamic linear modelling.

The dynamic linearisation approach allows for optimisation of a chain of units, rendering the overall solution complex and challenging to troubleshoot while allowing for limited process modelling precision.

Figure 1. The impact of applying MPC on the stabilising process.

Figure 2. DRL implantation.

April 2022 64 HYDROCARBON ENGINEERING

Solutions to limitations The limitation of the traditional approach in process modelling can be addressed by using machine learning and AI technologies. Neural networks can be used to precisely model the optimised process, serving as a basis for digital twins. Machine learning allows the digital twin to capture the nuances of process dynamics that cannot be expressed analytically.

However, using machine learning for modelling alone does not de-bottleneck the optimisation. The traditional optimisation algorithm still needs to be applied to a black box process model, represented by the neural network. The removal of computational constraints in process optimisation is achieved when gradient-descent-based optimisation

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is replaced by a neural network, implementing the optimising control law.

The generated setpoints nudge the process toward an economically-optimal state at each iteration of optimising control implementation. De-bottlenecking occurs, as instead of solving an optimisation problem that calculates the optimal control signals for the current process parameters, the trained neural network takes these process parameters as an argument and generates the control signals in a matter of a few seconds.

Replacing the gradient descent optimiser with a neural network reduces a few orders of magnitude calculation time.

An explanation as to why the implementation of optimisation control by the neural network is much faster than the direct calculation can be found in the thinking of a neural network as a look-up table, containing the pre-calculated results for each set of process conditions. Given the process parameters and constraints, the neural network approximates the control law to maintain the process at its most effective economical state.

The training method, Deep Reinforcement Learning (DRL), is one of the most powerful techniques to fully exploit the potential of a neural network in providing optimising control to a technological process. DRL is inspired by trial-and-error, experience-based training that a child uses to learn from its interaction with the world. It allows for continuous improvement of the control policy by making small adjustments to the produced control signals and updating the control policy to generate results, leading to higher rewards. This is illustrated in the diagram of the DRL implantation in Figure 2.

Because the neural network implementation can lead to an almost instant result calculation, it allows the operator to answer ‘what if’ questions. This means that before a particular change to the process parameter is made, its impact on the process’ economic performance can be evaluated. This ability allows for the application of technological constraints on the process while assessing their impact on the economic optimisation objective.

Conclusion Despite the progress in optimising control technology since the first commercial deployment of multivariate control in the late 1970s, computing power remains the bottleneck of real-time optimisation and control. The emerging AI technologies and, specifically, the DRL technology that Modcon used as an AI process optimisation solution, hold the keys to fully exploiting the full potential for real-time economic optimisation.

The result of efficiency improvement in this solution implementation is a marked reduction in operation costs without affecting the production capacity or product quality to allow for the highest possible efficiency of the process, at the lowest cost. The refinery increases its revenue, profit and economic growth. This approach enables the refinery to stand against any undesired influences caused by the geopolitical and highly-competitive economic environment.

Combining process knowledge, online analysis technologies, and DRL technologies drives efficiency, productivity and performance.

Hydrocarbon Engineering presents a selection of sulfur technologies and services currently available to the downstream sector.

AMETEK Process Instruments Measurements of hydrogen sulfide (H2S) and sulfur dioxide (SO2) are critical at the outlet of the sulfur recovery unit (SRU) in refineries, gas processing plants, steel mills, and petrochemical plants. These measurements – typically referred to as Air Demand – provide SRU process insights, allowing operations to optimise the use of energy, injected air/oxygen, and catalyst. Unexpected H2S and SO2 measurements can also be an indicator of plant process upsets prior to the SRU. Due to the toxicity of the sample gas, many users prefer to install a gas analyser at the sample point. There are instances where installation at the sample point is not possible, due to environmental conditions (extreme cold or

Blasch Precision Ceramics Blasch Precision Ceramics is an advanced refractories company specialising in the design and manufacture of close tolerance, complex net shapes by utilising a proprietary injection molding process that yields components exhibiting exceptional thermal shock

heat) or a lack of space for the analyser. With thousands of Air Demand analysers installed in the field, AMETEK has been asked to provide solutions for the installation of analysers both at the sample point and in remote locations, such as a shelter.

For those users that need to install an Air Demand analyser remote from the sample extraction point, AMETEK has introduced the 888L Air Demand analyser. A variation of the field-proven 888 ‘top of the pipe’ analyser, the 888L provides the accuracy and durability users expect from an AMETEK sulfur analyser. With a user interface, demister probe and other hardware shared between the 888 and 888L analysers, the learning curve to operate and maintain the new 888L is extremely low for current AMETEK 888 users.

resistance and consistency. The company’s engineers have developed checkerwall and ferrule designs that eliminate the various issues associated with the conventional designs, such as equipment failure and costly downtimes. These designs have provided reliable operation at refineries worldwide for over 20 years.

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Internal structures such as choke rings and checker walls in the sulfur recovery unit (SRU) reaction furnace (RF) often collapse, resulting in frequent shutdowns. From a process standpoint, a large portion of the flow jets through the centre of a choke ring do not satisfy the minimum residence time for key reactions. Blasch’s VectorWalls, in combination with the company’s ProLok Ferrules, have been specifically designed to address these problems. They offer

easy and fast installation with longer run lengths and improved structural integrity. They have better ammonia and BTEX destruction from higher RF front zone temperatures due to the unique radiation blockage from the Vectortile. Along with increased path lengths and an increase in temperature in Zone 1 (before the wall), there is the potential to not only use less fuel, but also offer lower carbon dioxide (CO2) emissions and shorter furnace designs.

CG Thermal LLC

A variable-pitch tube bundle, innovative baffle arrangement, and full annular inlet plenum are important features that can be designed to create the desired symmetry in temperature profile and thermal stress across the tube bundle. Computational fluid dynamics (CFD) and finite element analysis (FEA) are at the core of a thorough evaluation The proper use of CFD and FEA is required to verify the tube wall temperatures, minimise pressure drop, maximise heat transfer rates, and model the flow through the recuperator to design in this symmetry. The initial design is evaluated and adjusted based on analysis until the optimal arrangement is determined.

This design approach has been proven by 20+ years of successful installations by the AirBTU High-Temperature Variable Pitch Radial Recuperator (VPRR).

High-temperature gas-to-gas heat exchangers are commonly found within sulfuric acid plants, functioning as interchangers or preheaters for the catalyst bed and as preheaters at the sulfur furnace. These recuperators see very high temperatures, high-temperature differentials, and potentially highly-corrosive gas streams.

When common shell-and-tube exchanger designs are employed for high-temperature gas applications, several failure modes are prevalent. These include cold-end corrosion, cold-end fouling, stress failures, and unanticipated pressure drop. Therefore, a thorough analysis of the unit is essential during the design phase in order to avoid costly modifications and repairs after the unit is in operation.

Creating thermal symmetry within the unit is fundamental to the design of a well-engineered recuperator.

Comprimo With a depth of industry experience, Comprimo offers a broad technology portfolio for all associated sulfur block technologies in relation to gas treating and sulfur recovery. The company’s suite of technologies provide a solution at the lowest CAPEX and OPEX levels to meet your local sulfur recovery efficiency regulations and give you confidence and peace of mind.

Comprimo brings more than 65 years of proven experience and expertise in the development, application and management of gas treating and sulfur recovery process technologies, with more than 1200 licensed sulfur recovery units (SRUs) worldwide.

The company offers leading technology to deliver optimised solutions for every project, backed by the renowned engineering delivery capability of the combined Worley organisation. With five execution centres supported by a

Howden Howden has been chosen to supply the main air compressor for the sulfur recovery unit (SRU) within the new 820 000 tpy biofuels facility at the Shell Energy and Chemicals Park Rotterdam, the Netherlands.

Shell PLC recently announced the decision to build the facility at its Energy and Chemicals Park, formerly known as the Pernis Refinery.

This supply adds to the overall involvement of Howden in one of Europe’s largest developments for sustainable aviation fuel and renewable diesel production after Howden Thomasson

April 2022 68 HYDROCARBON ENGINEERING

comprehensive global network of experts, Comprimo is able to provide its clients with responsive technical support and access to over 100 dedicated sulfur experts.

Comprimo has recently added two digital tools to its suite of offerings. In the Comprimo Insight tool, which is a cloud-based plant monitoring system, near real-time information is collected to create dashboards that allow Comprimo subject matter experts (SMEs) to support its customers to monitor and troubleshoot their units. The Comprimo Immerse tool is a dynamic SRU simulator that prepares operators for every scenario behind the panel by immersing them in a replica of their SRU. It can be used to train operators, create a full digital twin of the distributed control system (DCS), and provide assistance with a move to a new DCS or investigation of new scenarios before implementing them in real life.

was selected to provide the reciprocating compressors for the same project.

Howden’s Turbo Compressor technology, proven over decades in sulfur recovery applications, is now a critical component of the sulfur recovery process at this new facility.

This project is capable of producing enough renewable diesel fuel to avoid 2.8 million tpy of carbon dioxide (CO2) emissions, or the equivalent of removing more than 1 million European cars from the roads (based on the annual driving distance of a UK/EU driver, assuming a medium-sized diesel car. Based on the production of 820 000 tpy of renewable diesel).

IPCO IPCO is a world leader in sulfur processing and handling systems, having delivered complete end-to-end systems to hundreds of companies around the globe since 1951.

Two solidification systems are available to meet all throughput requirements: For small to mid-size capacity operations, IPCO’s proven Rotoform system offers excellent product uniformity and environmentally friendly operation. The efficiency of this single step, liquid-to-solid process results in premium quality pastilles of uniform shape and size, free-flowing for easy handling, while a predictable high bulk density is a major advantage in terms of storage and transportation. More than 700 Rotoform pastillation systems have been installed for sulfur processing to date.

For higher capacity sulfur solidification requirements, IPCO offers rotating drum technology to deliver high

Optimized Gas Treating Inc. The OGT | ProTreat® simulator now contains new hybrid solvents thermodynamics and mass transfer characteristics that extends ProTreat’s powerful, accurate, and proven mass-transfer rate-based model to blends of multiple physical and chemical solvents.

Hybrid solvents belong to a class of extractive agents for gas treating, in which part of the water and amine content in

productivity ‘once through’ performance. The SG product line consists of two sizes: the SG30 with a forming capacity of up to 2000 tpd, and the scaled-down version SG20 for forming at up to 800 tpd.

The first industrial installation of the IPCO SG20 was successfully commissioned in Italy in 2021 and offers an environmentally-friendly process that is simple and safe to operate, while producing the highest quality product. The latest features incorporated into IPCO’s drum granulators resolve the biggest issues that customers are facing, including: sulfur build-ups; frozen and plugged sulfur nozzles/product quality; drum roller maintenance; dust emissions and scrubber waste; hydrogen sulfide (H2S) emissions; and consistent operation.

IPCO looks forward to welcoming customers onsite in Italy to witness the state-of-the art in sulfur drum granulation.

a normal amine-based solvent is replaced by a physical, non-reactive component.

A classic commercial example is Sulfinol-DTM whose main ingredients are water, sulfolane and DIPA, first developed by Shell Catalysts & Technologies more than 60 years ago. More recent examples are Sulfinol-MTM (with MDEA) and Sulfinol-XTM (using MDEA and piperazine). Solvents containing sulfolane, a cyclic sulfone with the formula (CH2)4SO2, are

particularly advantageous for removing organo-sulfur components such as mercaptans, COS and disulfides. The amine remains very effective for hydrogen sulfide (H2S) and carbon dioxide (CO2) removal. The hybrid solvent has the advantages of both.

OGT’s hybrid solvents package is not limited just to sulfolane. For example, heavily-glycol-contaminated amine solvents can now be accurately simulated as a hybrid solvent

incorporating the glycol’s influence on acid gas VLE along with the effect of modified solution physical properties on mass transfer. Solvent suppliers offering proprietary hybrid solvents with several physical solvent or amine components can now accurately tailor blends of varying quantities for custom applications. And with an over 20-year proven history, the effects of ionic contaminants such as heat stable salts are still rigorously accounted for at the fundamental chemistry level.

Servomex

before the gas is vented. Combustion applications are highly corrosive due to the presence of high levels of sulfur compounds, presenting serious challenges for gas analysers, which tend to be either zirconia or extractive solutions. The corrosive conditions can lead to these solutions requiring high levels of maintenance and frequent recalibrations, as the sulfur compounds can attack the zirconia sensor and sample tubes can be clogged by the effects of sulfuric acid.

Servomex has achieved success in the Middle East, US and Europe with the Laser 3 Plus Combustion analyser, supported by the tunable diode laser system. Optimised for oxygen, it has no sample contact resulting in no corrosion of the sensor, significantly reducing maintenance and eliminating the need for cell replacement.

Gas analysis expert Servomex provides a reliable and cost-effective solution for combustion measurements at sulfur removal facilities with the SERVOTOUGH Laser 3 Plus Combustion analyser.

A traditional sulfur recovery unit (SRU) consists of a Claus section, a sulfur degassing section, a tail gas treating section and a thermal incinerator, and can achieve sulfur recovery of up to 99.9%.

The sulfur plant tail gas is routed to either a tail gas treatment unit for further processing or to a thermal oxidiser where the sulfur compounds in the tail gas are incinerated to sulfur dioxide (SO2) before the effluent is dispersed in the atmosphere.

An SRU’s tail gas contains a variety of sulfur compounds which must be destroyed by combustions

Wood Wood sulfur recovery technology consists of licensed and open-art designs incorporating 50 years of experience and ‘know how’ in the areas of revamps/upgrades; process design; equipment design/supply; layout and modular supply; safety and operations.

Included in Wood’s sulfur technology are amine treating and regeneration, conventional and two-stage sour water stripping, sulfur recovery, amine-based tail gas treating, sulfur dioxide (SO2) scrubbing, and integration of sulfur degassing and sulfur handling.

Wood has been involved in over 500 sulfur-related projects worldwide, covering a wide range of feed compositions ranging in size from 4 to over 650 tpd and sulfur recovery efficiencies meeting requirements up to and exceeding 99.98% recovery to align with the most stringent environmental requirements.

XOS In August 2019, an XOS Sindie® Online total sulfur analyser was installed at the Malchin biofuels refinery of ecoMotion GmbH. This site is one of the first biodiesel pilot plants built in Germany and the primary feedstocks are animal fats, vegetable oils, and used cooking oil. The site produces 10 000 tpy of biodiesel and must measure the sulfur in its product to ensure

April 2022 70 HYDROCARBON ENGINEERING

In 2022, two Wood-designed sulfur recovery units (SRUs) will be commissioned and started up. One is a revamped unit in the US featuring the company's acid gas burner, new thermal reactor, new Claus reactor reheaters, a new tail gas incinerator, and a revamped caustic scrubber to capture and reduce SO2 emissions to < 50 ppmv.

The second unit consists of a new Claus unit featuring Wood’s acid gas burner, and an amine-based tail gas treating unit utilising formulated MDEA to achieve World Bank SOx emission limits.

Wood aims to be an active participant in the evolving energy landscape and support its clients’ goals to extend the life of their assets. The company's high-efficiency technology improves process performance and plant efficiency, reducing maintenance costs, simplifying operations, and enhancing plant safety.

that it is below regulatory limits, typically less than 15 or even 10 ppmw.

XOS’ Sindie Online total sulfur analyser uses monochromatic wavelength dispersive X-ray fluorescence (MWDXRF) to continuously measure the sample stream and deliver results as often as every 5 minutes. The analyser uses a dynamic window module (DWM) to automatically replace the sample window,

In the last 10 years, Howden SG Turbo Compressors have prevented more than 13 million tonnes of sulphur being emitted into the air we breathe.

Customers are looking for solutions that will meet the required emission standards while minimising capital spend and operating costs.

Howden have the largest installed base of Turbo Compressors in SRU applications globally. Our equipment plays a critical role in the prevention of air pollution and acid rain. Let us implement solutions that meet environmental standards, address sustainability concerns and support the refineries to meet these global challenges.

All Howden’s turbo blower and compressor models are designed and supplied as single stage, integrally geared units and complete packages, and provide high efficiency over a wide operating range.

Find out more: www.howden.com/products Turbo.HCO@howden.com

which effectively eliminates any drift and significantly reduces the frequency of required calibrations, significantly increasing uptime and measurement stability.

Previously, the site sent samples to a remote laboratory which introduced production delays and uncertainty. By installing the Sindie Online sulfur analyser, the site obtains accurate measurement every

5 minutes, enabling it to optimise production, and be confident that the product is compliant and of high quality, while reducing gas consumption by 5%.

Almost a year after installation, the site reported that its expectations for the performance of the analyser continued to be met, with measured values consistently matching laboratory cross-checks, resulting in more efficient operations.

Zeeco Inc.

world – to validate computational models and create virtual prototypes for product development, testing and optimisation. These systems help to ensure the reliability of Zeeco products, including: nn High-intensity burners that achieve rapid combustion on minimal volumes under a wide range of reaction furnace conditions. nn Burners that operate under oxygen-deficient environments without smoke, soot, or oxygen slippage. nn Proprietary spin vanes that create a vortex recirculation zone upstream of the burner discharge and lead to a highly-stable flame front. nn Thermal oxidiser applications with patented ZEECO® FREE JET® ultra-low-NOx burners that incinerate tail gas at exceptionally low flue gas NOx levels. nn Externally-mounted ProFlame+ SRUTM scanners that reliably detect and discriminate between flames despite high-temperature processing environments common in SRU reaction furnaces or thermal oxidisers.

Since 1979, Zeeco has delivered advanced sulfur industry applications to ensure sulfur recovery units (SRUs) and related equipment comply with rigorous environmental and safety standards. Utilising expertise and cutting-edge engineering technology, Zeeco designs and supplies everything from SRU thermal oxidisers with ultra-low-NOx burners and waste heat recovery, to high-intensity burners, waste heat boilers, sulfur condensers, and soot-free inline heaters.

Zeeco drives innovation through high-performance computing (HPC) systems to perform computational fluid dynamics (CFD) and finite element analysis (FEA) simulations to accurately predict thermal reactor and tail gas incinerator package performance. Engineers assess ammonia and BTEX destruction levels, flame shape, and distributions of combustion air, fuel gas, and flue gas.

Zeeco leverages HPC systems in collaboration with its research and testing facility – the largest of its kind in the

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