PTQ Q2 2025 Issue

REFINING GAS PROCESSING PETROCHEMICALS ptq Q2 2025

CRUDE-TO- CHEMICALS CORROSION INHIBITORS

INCREASING WATER QUALITY

ADVANCING CHEMICAL RECYCLING

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Q2 (Apr, May, Jun) 2025 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY

3 Navigating tightening margins Rene Gonzalez

©2025. The entire content of this publication is protected by copyright. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means – electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner. The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included in Petroleum Technology Quarterly and its supplements the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies. Cover High complexity refineries with hydrocracking assets have the flexibility to make high-quality base oils from a wider variety of crude oils. Photo courtesy of Tüpraş. 87 Enterprise-wide optimisation across hydrocarbon processing assets Jun Yi, Pei Su and Yonglei Wang Galaxy Sky-grand Technology Co., Ltd . Weijun Yang PetroChina Jinxiang Mao Sinopec Ricky Hsu Independent Consultant 94 Technology In Action 5 ptq&a 9 Synergistic multifunctional corrosion inhibitors for high-acid crudes Amutha Nagarajan, Ghousya Gulzareen Khannam, Kannan Perumal, Sathees Kesavan, Hitesh Bagaria and Nimeshkumar Patel Veolia Water Technologies and Solutions 16 Thermodynamic solution for evaluating crude compatibility Asok Tharanivasan and Michelle Wicmandy KBC (A Yokogawa Company) 23 Advancing adoption of chemical recycling Artem D Vityuk BASF Corporation 33 Impact of hydrocracker catalyst changes on crude oil selection Bilge Karahan, Merve Çinbar and Nilay Aktaş Tupraş Peter Nymann Topsoe 39 Meeting the challenge of tramp amines in crudes Joel Lack Baker Hughes 45 Increasing refinery recycled water quality and usage Christina Möring, Johan Hutsebaut and Caroline Bird Solenis 51 Enhancing refinery profitability through rigorous catalyst evaluation Tiago Vilela and Nattapong Pongboot Avantium 55 Key profit drivers for sustainable crude-to-chemicals complexes John Melancon, Parveen Kalia, Shankar Vaidyanathan, Ed Reyes and Michelle Barber Fluor Corporation 65 Pathway to autonomous operations in refining and petrochemicals Tom Fiske Yokogawa 73 Hydrogen-rich gasoline offers an alternative to high octane costs John Burger and Don Byrne HRC Fuels George Hoekstra Hoekstra Trading 79 Hybrid digital twin for DHDT unit performance monitoring S K Shabina, Ranjith Kumar Bojja, I R Choudhury and Sarvesh Kuma Research & Development Centre, Indian Oil Corporation Limited

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Make every molecule matter

At Shell Catalysts & Technologies, we understand how small, unseen chemical reactions can affect the health of our loved ones, neighbours, and the planet at large. That is what motivates us in our mission to Make Every Molecule Matter. Every member of our team is focused on the same goal – developing cleaner energy solutions that enable industries to tackle global climate challenges starting at the molecular level. Our experienced scientists and expert engineers collaborate with customers to create solutions tailored to your specific energy transition and performance challenges. And when they do, they use the knowledge we gained from Shell’s corporate heritage as the designer, owner and operator of complex industrial process plants around the world. Learn more at catalysts.shell.com/MEMM.

Vol 30 No 3 Q2 (Apr, May, Jun) 2025 ptq PETROLEUM TECHNOLOGY QUARTERLY

Navigating tightening margins

S trong global crack spreads in the mid-2000s drove much of the investment in refinery capacity expansions that have come online over the past decade. However, narrowing crack spreads are expected throughout 2025 due to fuel surpluses for certain market segments, such as the bunker fuel market. For example, crude oil-based bunker fuels like low-sulphur fuel oil (LSFO) and marine gas oil (MGO) are readily available and relatively inexpensive. As we look ahead to 2025, refiners will likely see sluggish demand and regional supply disruptions amid ongoing geopolitical tensions. Global crude oil demand is increasing even with alternative fuels, to almost 104.5 million bpd. The shift to higher margins petrochemical feedstocks predicates continued refinery-petro - chemical integration in China and India, boosting naphtha processing capabilities (for example, for mixed feed steam crackers) while seeking flexibility in shifting production between fuels and naphtha. Going back to the fuels business, refinery conversions for sustainable aviation fuel (SAF) production are expected to continue in Europe and North America. Blending mandates like those in the EU could grow SAF demand by five-fold in 2025. Going forward, we could see more LNG-fuelled vessels and, later, ships powered by clean methanol, clean ammonia, and biofuels to meet greenhouse gas emissions standards, as discussed in the accompanying PTQ Gas 2025 publication. Certain markets and efforts towards circularity are falling short of goals. However, they are still viable, such as the monetisation of associated process gas (APG) from flaring in upstream and midstream oil and gas production. The prob - lem is that flare sites can be widely scattered or remote, making efficient connec - tions from individual sites to a small or medium-sized upgrading facility unfeasible. It is more efficient to leverage APG as an onsite energy source, such as for fuel - ling electric generators previously powered by diesel. In the past, diesel gensets were often used for power generation, but that solution is becoming less finan - cially viable as the cost of both diesel fuel and its storage increases. In addition, the specific CO2 footprint of APG is approximately 30% lower than diesel. Some interesting refinery expansion projects to watch are in the Indian subcon - tinent, which is covered in more technical and strategic detail at the Refining India 2025 conference hosted by PTQ and IDS. As many as 11 crude oil capacity expan- sion projects could come online in India through 2028. This includes the Ratnagiri megaproject with an estimated 1.2 million bpd of capacity, where hydrocracking capacity expansions could total more than 200,000 bpd across multiple project proposals, and distillate hydrotreating capacity could total more than 600,000 bpd. Elsewhere, several refineries have come online in the Middle East within the past year, and the impact of these refineries on global markets is still evolving. In addition to plant expansions, at least 11 new refineries and expansions to exist - ing refineries are being tracked for completion by the end of 2028. They run the gamut of major refinery units typically seen in refinery operations, as well as new configurations. For the industry targeting circularity and sustainability, processing and conver- sion of plastic waste-derived pyrolysis oil down to their basic monomer for re- entry into the plastics/polymer value chain is reaching a crucial point, as discussed in this issue’s article by BASF. These are just some of the segments influencing refinery and petrochemical complexity that first movers in the industry are trying to embrace, or they will decide to pursue other pathways to profitability.

Editor Rene Gonzalez editor@petroleumtechnology.com tel: +1 713 449 5817

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PTQ (Petroleum Technology Quarterly) (ISSN No: 1632-363X, USPS No: 014-781) is published quarterly plus annual Catalysis edition by EMAP and is distributed in the US by SP/Asendia, 17B South Middlesex Avenue, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. Postmaster: send address changes to PTQ (Petroleum Technology Quarterly), 17B South Middlesex Avenue, Monroe NJ 08831. Back numbers available from the Publisher at $30 per copy inc postage.

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PTQ Q2 2025

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More answers to these questions can be found at www.digitalrefining.com/qanda

Q What strategies can be considered to meet the expanding paraxylene market? A Danny Verboekend, CSO, Zeopore, danny.verboeend@ zeopore.com Many methods to maximise the supply of paraxylene (PX) involve molecular conversions of refinery streams using heterogeneous catalysts (see Figure 1 ). Diverse raw and waste streams, based on either fossil or biomass origin, can be converted to aromatics (and therefore paraxylene) using thermo-catalytic processes in an aromatisation step. These can be currently available streams such as lights or naphtha and crude oil, but also upcoming streams of natural (bio - mass) and synthetic polymers (waste plastics). Secondly, an opportunity exists to maximise PX yields by upgrading the obtained aromatic-rich feeds, such as that done on the pyoil obtained from naphtha cracking. Herein, the trans-alkylation of heavy aromatics (C 9 +) with toluene and/or benzene represents an attractive option. Finally, within the aromatic C 8 fraction, isomerisation reactions may be executed to maximise the PX yield at the expense of eth- ylbenzene and the lesser desired xylene isomers. Importantly, the preferred catalysts for this reaction are zeolite-based, giving rise to a relatively high shape selec - tivity to xylenes based on the tight fit of such aromatics in the very narrow zeolite pores (diameter of 0.5 nm, which is a similar size to a xylene molecule). Strikingly, this tight fit also gives rise to transport and access limitations, which implies that only the external surface of the zeolite crystals, hence about 10%, is effectively used in catalysis. One way to overcome such limitations is to use more

accessible (mesoporous) zeolites, which feature either much smaller crystals and/or intra-crystalline mesopores (size range 2-50 nm), increasing the zeolite’s external surface and, importantly, giving rise to sizable benefits in catalytic applications in terms of activity, selectivity, and lifetime. Yet, similar to fluid catalytic cracking (FCC), hydrocrack - ing, and dewaxing, syntheses of the required accessible zeolites are typically executed in the persistent presence of unscalable unit operations and/or the use of costly (organic) ingredients, hampering their widespread implementation. Based on the apparent and urgent need for commercially viable, accessible (mesoporous) zeolites, Zeopore was founded. A Keith Couch, Sr. Director, Business Development & Integrated Projects, Honeywell UOP, keith.couch@ honeywell.com The PX market continues to grow with increased demand for beverage bottles, food packing, and textured polyester yarns, a market truly driven by bottles and shirts. China has driven much of the growth in PX to feed its fibre production. Whereas a single train PX unit was ~600 kMTA as recently as 2010, as PET trains have increased in size, single train PX complexes are now ~2,400 kMTA. This has driven an economy of scale that almost requires a crude-to-chemi - cals complex to feed it. Around 2011, the investment wave of PX units built in Korea consumed most of the world’s remaining merchant heavy naphtha. This put an end to the historical cycle in the aromatics market. Since then, most PX complexes have been integrated with either a dedicated new refinery or associated with a firm intentionally reducing its exposure to gasoline markets. The latter takes a committed move. The production of PX from refinery feedstocks pulls much of the C 7-C10 molecules out of the gasoline pool so it can be reformed into aromatics. This strands a lot of C 4s and light naphtha that can no longer be soaked up into a residual gasoline pool. The result is typically another set of invest - ments to alkylate the C 4s or shedding these materials to the merchant market that could involve the following options: • Go big: Economy of scale matters in the PX world. Most firms will need to fill up at least a world-scale PET plant to be competitive. • Controlling feedstock supply: The days of competing with merchant mixed-aromatics feedstocks are over. These plants have the highest cost, followed by those that buy merchant heavy naphtha. These are the assets that have the hardest time to compete. • Integrating the value chain: The PX market is about bot- tles and shirts. As economy of scale and crude-to-chemi - cals have taken off, there needs to be an integrated value chain to truly compete. • Embrace the latest tech: While PX technology has been

Lights and naphtha

Synthetic or natural polymers

Crude oil

Aromatisation

C+ aromatics

C+ trans- alkylation

Ethylbenzene isomerisation

Benzene, Toluene, Xylenes

MX + OX to PX isomerisation

Figure 1 Catalytic conversions (in green) to convert streams to paraxylene-containing aromatic streams. Each conver - sion involves a zeolite-based catalyst

PTQ Q2 2025

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in the market since the early 1970s, large advancements in the technology have driven step-change lower coefficient of performance (COP) and economy of scale since 2014 to date. Latest designs, catalysts, and adsorbents have reduced the energy footprint by more than 30%, and equip - ment tonnage and cost by 25% per tonne of PX. UOP’s Light Desorbent PX (LDPX) technology was launched in 2015 and now accounts for about 35% of the world’s total PX production. Older tech can be revamped but often faces the challenges of limited feedstock to take advantage of scale. • High-yield reforming catalysts: Catalyst technologies have advanced over the past five years, improving aromat - ics selectivity and hydrogen production. These are easy to change out ‘on the fly’ and provide significant PX produc - tion improvements. Q How can smaller refineries compete in an industry dominated by mega-refinery/petrochemical facilities? A Jeremy Mayol, Regional Sales Manager Additives, Catalyst Technologies, Jeremy.mayol1@matthey.com, and Marie Goret-Rana, Market Manager Additives, Catalyst Technologies, marie.goret-rana@matthey.com, Johnson Matthey Smaller refineries are already facing and will continue to face considerable challenges and fierce competition from mega-refineries that benefit from economies of scale, lower production costs, and preferential access to feedstocks. However, smaller refineries can adopt several strategies to survive and thrive, as follows: • Specialisation and diversification: Focus on high-value fuels and niche markets like biofuels and specialised pet- rochemicals, where competition is lower and margins are less volatile. Diversification can help stabilise earnings, especially during periods of weak gasoline or diesel cracks. • Leverage of geographic advantage and integration into local chains: Strategically position themselves to serve local markets, minimising competition in global refined product markets and avoiding high logistical export costs. • Operational flexibility: Leverage their size to be more agile and responsive to market fluctuations. They can leverage opportunities in both feedstocks and products. On the feed- stocks side, they can capitalise on their flexibility to process cheaper, discounted crudes. This can be especially relevant for refineries with a fluid catalytic cracking (FCC) unit, which can convert heavy, high-metal feedstocks into high-value products. These refineries can leverage specialty additives to flexibly process high metal-content feeds while maintain - ing similar FCC catalyst addition rates and product yields. On the products side, small refineries can take advantage of their size to rapidly adjust production to market demand and economic conditions. Specialty FCC additives associated with addition systems support this strategy. For example, FCC olefins additives enable FCC margins maximisation by responding swiftly to market shifts. • Operational efficiency and technological innovation: Investing in advanced technologies like digital tools to be more efficient, less energy-intensive, and reduce production

costs can help smaller refineries stay competitive. Digital tools provide real-time data insights to optimise operations and boost profitability. • Energy transition: Transition to processing alternative raw materials such as used oils or plastic waste, enhanc- ing their environmental competitiveness in regions where low carbon regulations are being implemented. Alternative feedstocks are especially well-suited for processing in smaller refineries, as they are often available regionally in limited quantities, and transporting low-energy-density feedstocks is not cost-effective. Johnson Matthey licenses multiple technologies that can support operators pivoting towards alternative feedstocks such as biomass, municipal solid waste, captured carbon dioxide, and green hydrogen. • Regulations and subsidies: Taking advantage of regu - lations that favour local players over imports, and gov - ernment subsidies for the energy transition and energy independence, can provide another competitive advantage to smaller refineries. By adopting these strategies, smaller refineries can - not only survive but thrive in a market dominated by mega-refineries. A Mike McBride, Solutions Development Lead, Honeywell UOP, mike.mcbride@honeywell.com It can be challenging for smaller refineries to compete in today’s environment. Developing threats in some regions include new global mega-complexes, declining demand for conventional refinery products largely driven by a societal desire for more sustainable transportation fuels, and contin- ued industry consolidation as many seek to achieve econo- mies of scale and adapt to changing market conditions. Smaller refiners can indeed compete in today’s environ - ment. Start by understanding the facility’s competitive position within the markets in which the refinery com - petes. Then develop a view on what the markets might look like over the next five, 10, and 15 years. Refresh SWOT (strengths, weaknesses, opportunities, and threats) analy - sis coupled with a good, innovative focus on competitive strengths and opportunities with a realistic focus on today and tomorrow. Then, develop an approach to improve com- petitive positioning to ensure a robust business for the long haul. Some opportunities for smaller refineries to improve competitive positioning may include: • Access to local fats, oils, greases, biomass, or munici - pal wastes available through local farms, timber industry or municipalities may enable the addition of biorefinery capability. • Access to the premium gasoline market. Premium demand and spreads have been quietly increasing to the point where many sites are constrained on premium pro- duction capability. Many automotive firms are respond - ing to Corporate Average Fuel Economy (CAFE) standard improvements through the proliferation of turbo-driven engines. This will increase if, as projected, the EV adoption rate slows. The demand for premium gasoline is likely to increase in many markets, which provides opportunities through the addition of incremental octane production (for example, expand alkylate and reformate production).

PTQ Q2 2025

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• Competitor shuttering. Many regional markets have a delicate balance of supply and demand with the high cost of importing products from other regions. A competitor shuttering its asset may provide the opportunity to serve its abandoned market. • Changing gasoline-to-diesel (G/D ratio). US gasoline demand is expected to decline more rapidly than diesel, whereas in the EU, this is reversed. Sites have some cut point, severity, and catalyst reload flexibility to respond to demand shifts. However, at some point, the spreads get big enough to support a hydrocracking investment in the US and perhaps FCC expansion in the EU. The refiners who are first to market on these opportunities will shore up their competitive positioning, especially if these opportunities can be coupled with a crude expansion to capture the mar- ket as competitors shutter. • Access to advantaged crudes. Regional discounts in crude oils can arise from newer discoveries, pipeline con- straints, or production volumes that limit market access. Many sites have found value in revamping/expanding capa - bilities to process discounted, higher TAN crudes, heavier crudes, or even much lighter, shale-derived crudes, • Access to petchem markets – notably propylene or aro - matics. These can be trickier options for smaller refiners who have never played in these markets. However, there is a need in NA for benzene, and FCC-based propylene is an easy opportunity for sites with pipeline access. Diversifying your product portfolio into higher margin petrochemicals could be an option. Q What incentives and technology are needed to make refinery-based cogeneration of electricity and steam profitable? A Mark Heigold, Department Manager and Associate Process Engineer, Burns & McDonnell, mlheigold@burn- smcd.com The decision to install a cogeneration (cogen) system in a refinery is primarily driven by economics. The key question is whether it is more cost-effective to generate both power and steam on-site or to purchase electricity from the grid while producing steam separately. A refinery investing in a cogen must account for the capital expenditure as well as increased fuel and maintenance costs. However, this is offset by lower direct electricity costs, potential tax credits, and increased efficiency. In North America, government financial incentives are usually linked to achieving a certain level of cogen efficiency. If the efficiency criteria can be met, associated credits can improve project economics. In the US, available investment tax credits (ITC) and Canada’s Class 43.1 heat rate cat - egories encourage cogen adoption. Carbon penalties and fuel market incentives also play a role. Refineries in Canada can avoid carbon taxes through cogen efficiency, while California’s Low Carbon Fuel Standard (LCFS) offers credits for integrating low-carbon fuels like renewable natural gas, hydrogen, or ammonia. These financial mechanisms impact feasibility, making cogen systems more attractive. Energy efficiency is the ultimate goal. Cogen systems

recover waste heat that would otherwise be lost, reduc- ing overall energy consumption. This leads to lower carbon emissions and offers additional benefits such as improved energy security and, in some cases, surplus electricity that can be sold to the grid. The choice of technology for power generation depends on the refinery’s energy demand and fuel availability. Gas turbines with heat recovery steam generators (HRSGs) capture exhaust heat to produce steam, improving fuel utilisation. Steam turbines can be added to utilise high- pressure steam for additional power generation while sup - plying lower-pressure process steam to the facility. An inte - grated gasification combined cycle (IGCC) facility gasifies refinery residues to produce syngas, which fuels a gas tur - bine combined-cycle system for electricity and steam pro- duction. Each option must be evaluated based on fuel costs, efficiency, and integration with existing refinery operations. Installing a cogen system will impact existing infrastruc - ture. With a gas turbine-based system, fuel consumption will increase since a portion of the turbine fuel is used for power generation, with the remainder credited to steam production. The electrical system must also be able to handle ‘behind-the-fence’ self-generation as well as switch back to grid supply when the turbine(s) are down for main - tenance. Refineries with existing infrastructure that can handle these requirements will find installation more eco - nomical than those requiring significant updates. A full lifecycle analysis will help determine whether a cogen provides a financial advantage over grid electricity and separate steam production. While project justification is primarily financial, regulatory benefits, reduced emis - sions, and the ability to incorporate low-carbon fuels fur- ther strengthen the case. If a cogen system can produce electricity and steam at a lower cost than grid power and standalone boilers, and incentives improve ROI, it presents a compelling economic option. A Joe Jacobs, Manager, Strategic Business Development, Becht, jjacobs@becht.com Refiners face competitive market pressures to lower pro - duction costs. Coproducing electricity and steam is a proven way to improve cycle efficiency for a refinery site. Improved energy efficiency will mean lower costs for the refiner. Electricity producers also face demand issues for the grid, with alternative energy sources having cyclical production and needing a swing supply. Building new power plants is one option to stabilise the grid; however, cost pressures are not unique to petroleum refiners. Currently, refiners nominally receive some cost incen - tives to produce electricity. These agreements have ele - ments for the refinery site to maintain electrical production at peak times as well as during electrical infrastructure maintenance periods. These agreements have tradition - ally been from opposite sides of the table where the par- ticipation is based on the transaction: electricity bought and sold. Perhaps the time is coming for more integrated arrange - ments like partnerships that allow the replacement of anti- quated fired boiler technology in a refinery for a baseload

PTQ Q2 2025

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of cogenerated steam for nominal steam production. The refinery of the future would have a swing boiler with full standalone cold restart capability to maximise coproduc- tion potential for the refinery and the grid. The digital trans - formation allows real-time integration between the refinery and the electricity producer. Energy efficiency equals lower greenhouse gas emissions. Q What optimal mass transfer/product separation con - figurations benefit the integration of catalytic reforming and aromatics complexes? A Sidhartha Aggarwal, Offering Management, Business Development, Refining Technologies & Catalysts, sidhar- tha.aggarwal@honeywell.com; Sharad Yadhav, Senior Offering Manager/Portfolio Manager – Petrochemicals, BTX, Honeywell UOP, sharad.yadhav@honeywell.com, Honeywell UOP Molecule management, particularly molecular precision, is one of the most critical aspects in optimising integrated catalytic reforming and aromatic complexes. The process begins with optimised separation in the naphtha splitter column. This ensures that all aromatic-generating mol - ecules, preferably rich in C 6 to C 8 hydrocarbons, are routed into the heavy naphtha stream while minimising lighter or non-naphthenic paraffins to reduce catalytic cracking and the resultant, lower-valued byproducts in the downstream complex. UOP’s proprietary CCR Platforming process employs specialised catalysts to maximise the conversion of heavy naphtha into aromatics. The main product from the Platforming unit is reformate, which is rich in aromatics components. In addition, byproducts such as fuel gas and co-products such as hydrogen and LPG are generated in the Platforming unit, which may have different applications depending upon the refinery configuration and needs. The reformate is further fractionated in the Platforming unit using debutaniser and/or depentaniser columns to remove low-value lighter hydrocarbons (C5 and lighter), simplify - ing downstream processing and lowering installation and maintenance costs. The C 7 - fraction from the reformate splitter proceeds to the proprietary UOP Extractive Distillation (ED) Sulfolane process, which utilises tetrahydrothiophene 1,1-dioxide (Sulfolane) as a solvent. This method effectively recovers high-purity benzene and toluene from hydrocarbon feeds, requiring less than 80% of the capital investment compared to traditional liquid-liquid extraction. Incorporating a proprietary Tatoray unit into an aromat - ics complex can significantly boost the yield of PX from naphtha. By feeding A9 and A10 byproducts with toluene into the Tatoray unit, additional methyl groups shift the chemical equilibrium from benzene production to xylenes, facilitating the production of mixed xylenes from low-value toluene and heavy aromatics. The proprietary UOP PX-Plus process selectively dis - proportionates toluene to produce benzene and xylenes, achieving a paraxylene concentration of about 90%, con - siderably higher than the 25% equilibrium achievable

through transalkylation technologies like Tatoray. The proprietary Parex process uses adsorptive separation to recover paraxylene from mixed xylenes, notably employing a solid zeolitic adsorbent (ADS-50) in a continuous format that simulates counter-current flow. The benzene-toluene fractionation (BTF) unit, featuring a dividing wall column (DWC) design, separates benzene, toluene, and xylenes in a single vessel, optimising plot size and reducing both capital and energy costs while enhanc - ing product purity. Finally, the xylenes fractionation unit is crucial for recovering xylene feed for the Parex process and light aromatics for Sulfolane. This unit includes multiple columns and is highly integrated with other plant sections for energy efficiency, utilising MD trays and proprietary High Flux tubes to maximise utilities and reduce capital investments. Q What new FCC stripper technologies are available that can deliver higher efficiency and optimised heat and pressure balance? A Rohit Agrawal, Project Development Manager, Honeywell UOP, rohit.agrawal@honeywell.com Today’s fluidised catalytic cracking (FCC) units have adopted reactor riser technologies that increase catalyst circulation rates and improve yields. As a result, the spent catalyst stripper often operates above the original catalyst flux design value, which can compromise hydrocarbon dis - placement efficiency and overall unit performance. UOP developed Advanced Fluidization (AF) spent cata - lyst packed stripping technology to improve both FCC unit yield performance and catalyst circulation (hydraulic) per- formance. UOP’s AF Packing incorporates recent advance - ments in stripper internal technology, consisting primarily of a bed of structured packing, and is the standard offer - ing for new and revamped units. AF Packing eliminates the rigid baffle design and the associated conical rolled plate construction. From a maintenance perspective, this option requires significantly less welding and post-weld heat treatment compared to baffle-type stripper technol - ogy. Additionally, structured packing is resistant to ero - sion, allowing UOP to expect the AF Packing to operate for at least two four to five-year operating campaigns, with commercial experience supporting even longer expected run lengths. AF Packing leads to significant benefits with improved yields and hydraulic performance: • Lowers delta coke operation and consequently reduces regenerator temperature. • Increases catalyst circulation (cat/oil ratio), leading to increased conversion. • Decreases dry gas yields, enhancing product selectivity to gasoline and liquefied petroleum gas (LPG). • Improves catalyst flux. • Reduces steam consumption, thus lowering cyclone velocity and main column traffic. • Enhances mechanical reliability, reducing turnaround time. More than 30 operating units have installed AF Packing for higher conversion and reduced steam consumption.

PTQ Q2 2025

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Rethinking Old Problems

More with Less

Revamp projects are difficult. Limitations imposed by plot space, congested pipe racks, and outdated equipment, to name a few, present unique challenges. Solutions that rely on excessive margins or comfortable designs lead to overspend. Now more than ever, process designers must find solutions that do more with less. P roven M ethods There is growing awareness that better scope definition earlier in the engineering phase saves time, reduces overall engineering cost, and leads to more successful projects. There is no argument that work completed during Conceptual and Feasibility phases is critical to getting a project on the right path. Engineers at Process Consulting Services, Inc. have developed a proven approach that makes the most of this precious time. At site, PCS engineers coordinate rigorous test runs, much of it through direct field measurements. Data collected is invaluable and often leads to low hanging fruit or hidden gems. Some refinery equipment performs better than design, and for various reasons others perform worse. Good test run data allows seasoned engineers to quickly identify what equipment needs investment and what equipment can be exploited. This way, solutions are developed that direct capital expense in the right areas and overspending is avoided. In one example, pressure drop measurements of a long crude oil transfer pipe showed the line could be reused, saving millions of dollars. Contact us today to learn how PCS’ proven methods can help you do more with less in your next revamp.

Projections for global supply and demand of refined products vary greatly depending on the pace of technological progress and degree of government policy enforcement associated with reducing greenhouse gas emissions. Without major advances in technology, it is hard to imagine a future without conventional fossil fuels over the next decade or two. Based on history, continued rationalization of refining assets is likely. Small, low-complexity refineries will struggle, while large, complex ones will thrive. Capacity creep through gradual improvement of refining units will continue to be a differentiating characteristic for remaining players. Focused revamps will play a critical role. Post-pandemic, inflation and a shortage of skilled construction labor have dramatically increased costs for refinery revamps. It is becoming increasingly difficult for many projects to meet corporate return on investment thresholds.

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Mitigate high-temperature naphthenic acid corrosion in enabling reliable and economical processing of high acid crudes

Amutha Nagarajan, Ghousya Gulzareen Khannam, Kannan Perumal, Sathees Kesavan, Hitesh Bagaria and Nimeshkumar Patel Veolia Water Technologies and Solutions

P rocessing ‘opportunity’ crude oil brings various pro- cess challenges, from high total acid number (TAN) to high concentrations of sulphur, nitrogen, and aro- matic compounds. Nevertheless, these crude oils remain economically attractive to refiners due to their substantial price discounts, which can significantly improve refinery profit margins. Among these opportunity crude oils, high- acid crude represents a distinct category characterised by substantial concentrations of naphthenic acids. Naphthenic acids comprise a complex mixture of cyclo- pentyl and cyclohexyl carboxylic acids. They exhibit a broad molecular weight distribution ranging from 120 to 700 g/mol and are quantified as naphthenic acid number (NAN, mg of KOH/g oil), which is a fraction of TAN. In refinery operations, naphthenic acid-induced high-temperature corrosion is par- ticularly pronounced in atmospheric and vacuum distillation units operating within 175-400°C (350-750°F). The corrosivity of such crudes is influenced by multiple critical parameters beyond temperature. These parameters include the concentration, molecular weight, and boiling point distribution of naphthenic acid constituents, as well as the quantity and nature of sulphur compounds pres- ent. Additionally, operational factors such as shear stress and material of construction significantly impact corrosion intensity. To minimise high-temperature corrosion, the use of cor- rosion inhibitors is typically a viable approach, particularly where the unit is not constructed with high-grade metall- urgies. The phosphate/phosphonate-based chemistries are relatively effective for such services. However, there is a risk of downstream fouling and catalyst poisoning. Against this backdrop, work started on the development of a syn- ergistic multifunctional corrosion inhibitor composition that consists of an organophosphate corrosion inhibitor and an organic dispersant chemistry free of any metals, sulphur, or phosphorus. Several potential candidates were extensively evalu- ated for high-temperature corrosion inhibition and fouling tendency, including their ability to keep iron phosphate dispersed. Surface characterisation, using the X-ray pho- toelectron spectroscopy (XPS) technique, has been car- ried out to show the good protective layer formed by the

corrosion inhibitor product. A synergistic formulation of a primary corrosion inhibitor and a dispersant was found to provide superior performance at 50% lower phosphorus concentration. The formulation was made into a marketable product and positioned for field trials in several refineries. Naphthenic acid corrosion and its mitigation Naphthenic acid corrosion represents a critical asset integrity challenge for crude oil refineries processing high naphthenic acid content crude oils and blends. These acids typically concentrate within the distillation operation’s temperature range of approximately 175-400°C, exhibiting particularly corrosive behaviour under high shear stress conditions. The corrosion mechanism associated with naphthenic acid inter- action on metallic surfaces exhibits considerable complexity, rendering precise prediction challenging. Understanding of corrosion mechanisms suggests that naphthenic acids interact with iron present on metallic surfaces, forming iron naphthenates. These compounds are oil-soluble and readily detach from metallic surfaces, subsequently exposing additional bare metal to acid attack. Prolonged exposure to these acids results in substantial metal degradation. Furthermore, iron naphthenates can undergo subsequent reactions with sulphur species present within the system, leading to various corrosion scenarios such as:  Isolated naphthenic acid corrosion, characterised by min- imal presence of non-reactive sulphur compounds, which has negligible impact on overall corrosion phenomena.  Combined naphthenic acid and reactive sulphur compo- nent corrosion, resulting in accelerated sulphidic deterioration.  Naphthenic acid corrosion modulated by natural inhibi- tors (hydrogen sulphide), wherein iron naphthenates react with hydrogen sulphide to produce iron sulphide, subse- quently releasing naphthenic acid that may initiate addi- tional downstream corrosion.1 Refineries may try to implement various methodologies to control and mitigate naphthenic acid corrosion, including modification and monitoring of operational parameters or integration of high TAN feedstock with low TAN feedstock. Note that the latter approach may present economic chal- lenges and potentially negatively impact refinery margins.

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was analysed by X-ray photoelectron spectroscopy (XPS) (see Figure 2 ). The peak around ~131 eV binding energy for the elemental phosphorus shows the formation of a phosphorus-based protective layer on the corrosion inhibi- tor-treated metal surface, leading to a 74% corrosion inhi - bition compared with the untreated system. Further surface characterisation of phosphorus-based corrosion inhibitor-treated metal (tested in the HVGO medium containing TAN and 1 wt% sulphur; temperature ~ 325ºC, P5 metallurgy) was studied by time-of-flight sec - ondary ion mass spectrometry (ToF-SIMS) and cross-sec - tion analysis by scanning transmission electron microscopy (STEM). Figure 3 shows the presence of phosphorus and sul- phur-based protective film/scale over the metal surface. The ToF-SIMS depth profile studies on the metal surface showed ~150 nm of phosphorus-based passivation layer on the metal surface, and sulphur was detected at the phos- phorus and iron oxide interface. The STEM analysis shows a ~100 nm protective layer on the corrosion inhibitor- treated metal surface. Laboratory investigation of naphthenic acid corrosion The high-temperature naphthenic acid corrosion processes in the field are very complex. They can be influenced by multiple operational and fluid compositional factors such as temperature, pressure, shear stress, naphthenic acid spe- cies and their concentration, as well as sulphur species and their concentration, in addition to unit metallurgy. To bet- ter understand the significance and interaction of all these factors, the performance of multiple corrosion inhibitors was systematically evaluated through extensive laboratory experiments designed to simulate various field conditions. The corrosion evaluation was conducted in accordance with the ASTM G184 standard method, which simulates pipeline corrosion conditions.3 The rotating cage autoclave (RCA) equipment used was fabricated in compliance with the specifications given in ASTM G184. RCA is considered a top-ranked methodology for corrosion inhibitor evalua- tion and qualification for pipeline applications. Based on the pipeline design and operating conditions, the laboratory testing protocol is set to evaluate similar field conditions for high shear stress, temperature, and pressure.

Corrosion rate increases

Corrosion resistance increases

317SS

316SS

4 10 SS

12Cr

9Cr

5Cr

CSteel

Most resistant

Least resistant

Enhancement of metallurgical specifications (see Figure 1 ) can be effective in improving corrosion resistance but may not always be feasible as it involves a significant invest - ment of capital and time. Another approach to mitigating risks associated with high- acid crude processing is the utilisation of high-temperature corrosion inhibitors (CI) and the establishment of optimised chemical dosage protocols. Furthermore, the selection and implementation of appropriate inhibitors, coupled with stra- tegic application methodologies, enables refineries to pro - cess feedstock containing elevated acid concentrations. This capability enhances operational flexibility and potentially yields improved financial performance through the process - ing of more economically advantageous feedstocks. High-acid crudes corrosion inhibition by chemical treatment Phosphate or phosphonate esters, sulphur (S) compounds, and combinations of sulphur and phosphorus (P)-based chemistries tend to inhibit corrosion at high temperatures and are commonly used as naphthenic acid corrosion inhib- itors. The corrosion inhibitor is expected to form a protective layer of insoluble phosphates and iron sulphide, protecting against the formation of hydrocarbon-soluble and corrosive iron naphthenate.2 An analysis of a metal surface to which an inhibitor treatment is applied, demonstrating corrosion mitigation, is discussed in the following section. Advanced analytical surface characterisation A heavy vacuum gasoil (HVGO) sample (TAN~1.35 and S~1.58 wt%) from a US refinery was tested for corrosion studies (325°C; 3 hr, shear stress ~30 Pa) on carbon steel metallurgy with and without phosphorus-based corro- sion inhibitor. Post-experiment, the surface of the metal Figure 1 Naphthenic acid corrosion mitigation by metal - lurgy upgrade

25 , 000

Test uid - US Renery HVGO

Corrosion rate (mpy)

20 , 000

No treatment

22.2

Phosphorous - based Cl

5.8

15 , 000

P - based Cl No treatment

10 , 000

5 , 000

200

400

600

800

Binding energy (eV)

Figure 2 XPS Survey scan of metal samples from untreated and phosphorus-based corrosion inhibitor-treated system

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ToF-SIMS depth proles of the passivation lm

Cross - section STEM images

STEM BF

FeO

0.8

0.6

0.4

0.2

x10

100

200

300

400

Depth (nm)

Figure 3 Surface characterisation of phosphorus-based corrosion inhibitor treated metal coupon

Patent-pending low-P multifunctional naphthenic acid corrosion inhibitor Although phosphorus-based corrosion inhibitors have demonstrated efficacy in mitigating high-temperature naphthenic acid corrosion, the excess phosphorus content can adversely affect catalyst performance in downstream processing units. Furthermore, the dislodgement of phos- phorus-based scale deposits from metal surfaces due to high shear conditions can result in subsequent fouling complications for downstream operations.4 For these rea - sons, new research was initiated to develop a low or non- phosphorus, non-metal-based, thermally stable, and non-fouling high-temperature corrosion inhibitor for the mitigation of naphthenic acid corrosion. To achieve the aforementioned objective, the synergies of various corrosion inhibitors and dispersant chemistries were studied to develop multifunctional products that could mitigate naphthenic acid corrosion. These were extensively evaluated for high-temperature corrosion inhibition, ther- mal stability, product corrosivity at elevated temperature, and dispersing and fouling tendencies, including their abil- ity to disperse iron phosphate and organic foulants. It was discovered that when using a combination of phosphorus- based corrosion inhibitor with a specific dispersant

chemistry, although the protective film is formed by the phosphate chemistry, the synergy of the dispersant com - ponent helped make it more effective at a much lower dosage. This enabled better corrosion inhibition at approx- imately half the phosphorus level of the conventional phosphorus-based inhibitors. This led to the filing of a pat - ent-pending treatment innovation, termed the new low-P multifunctional naphthenic acid corrosion inhibitor. The corrosion inhibition efficacy of conventional phos - phorus-based corrosion inhibitors and that of the new multifunctional corrosion inhibitor was evaluated by RCA for carbon steel and P5 metallurgy for a synthetic test fluid with a NAN ~3, at 310ºC (590ºC) and ~30 Pa shear stress. This represents the high TAN and low sulphur scenario mentioned earlier, which is typically very corrosive as there is no iron sulphide protective layer formation and the high shear stress tends to remove the protective layer. Through this analysis, it was demonstrated that the same corrosion inhibition efficacy shown by a conventional corrosion inhib - itor with 3.5 wt% phosphorus content could be achieved by the new low-P multifunctional corrosion inhibitor with only 1.7 wt% phosphorus content (see Figure 4 ). Impact of sulphur compounds on naphthenic acid corrosion The sulphur content in the crude oil can influence the naph - thenic acid corrosion at high temperatures. Based on the nature of the sulphur, it can form a tenacious iron sulphide layer on the metallurgy, providing a protective layer, or it can form a non-tenacious iron sulphide layer. The latter is typically a defective protective layer that leads to iron naph - thenate diffusion into the fresh metal surface, increasing the corrosion severity.5 In either case, the data presented in this section demonstrate that the new low-P multifunc - tional corrosion inhibitor can form a tenacious protective layer on the iron sulphide layer while demonstrating excel - lent corrosion resistance from naphthenic acid. Two HVGO samples from two US refineries (total sulphur content of >1.5 wt% and TAN >1) as well as a bottom resi - due from the atmospheric distillation unit of an Asian refinery (total sulphur of ~3 wt% and TAN ~0.5) were tested using

C10 18 P5

Blank

Conventional Cl (3.5% P)

Conventional Cl (1.7% P)

Low-P multifunctional Cl (1.7% P)

Figure 4 Naphthenic acid corrosion inhibition of conven - tional CI vs low-P multifunctional CI

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Test uid

Sulphur (%, ICP)

TAN (mg KOH/g)

Crudes oil / region Venezuela Venezuala D iluted Persian Gulf

API 16.0 17.3 18.9 21.1 21.1 22.1 23.5 29.7 30.9 33.8 38.8 45.3 57.8

Volatile P, ppm

1.35 1.55 0.7

1.58 1.94 3.1

HGVO-1 US renery HGVO-2 US renery CDU residue - Asian renery

0.705 0.391 0.515 0.992 0.161 0.409 0.669 1.201 1.216 2.303 1.477 1.229 1.623

Mexican Chad

Egypt Iraq

Persian Gulf Iran 1

Iran 2 UAE

Kazakhstan Qatar

% P contribution

HVGO-1 US renery

HVGO-2 US renery

CDU residue Asian renery

12% Predator <

No treatment

Low-P multifunctional naphthenic acid corrosion inhibitor (Predator*)

Figure 5 RCA – corrosion studies of the field samples

Crude feedstock > 88%

the previously described RCA corrosion study (310ºC tem- perature, ~30 Pa shear stress) (see Figure 5 ). Despite the presence of a significant level of sulphur compounds in the test fluids, it is possible for the high-temperature and high- shear stress conditions to disrupt the protective iron sulphide layer and cause sulphidic corrosion. This increased corrosion was observed on the test metal coupons in the absence of treatment. However, the application of the new low-P multi- functional CI treatment (Predator * ) was able to mitigate the corrosion, achieving greater than 70% inhibition. Mitigation of downstream impact from phosphorus and other contaminants During the refining process of high-acid crudes, it is antic - ipated that naphthenic acid corrosion products, along with the dislodgement of protective iron sulphide and phos- phate layers, may result in fouling of the heat exchangers, atmospheric and vacuum distillation unit trays, and pump- around sections.6 Furthermore, these corrosion products may potentially contaminate and deactivate catalysts in the catalytic conversion unit. In the case of fouling due to the presence of phospho- rus, the source of phosphorus is typically not only from the naphthenic acid treatment chemistries. However, a majority of phosphorus concentration may originate from crude oil feedstock (including upstream additives), imported feeds,

lube oil wastes, and gasoline slop tanks. A field study was conducted at an Asian refinery where severe fouling occurred on the distillation trays in the heavy kerosene boiling range. The deposit analysis indicated a high level of phosphorus. The crude slate was tested for total phospho- rus and volatile phosphorus, and the results showed that more than 88 wt% of the total phosphorus content of the deposit was attributable to the crude feedstock (see Figure 6 ). As for the phosphorus contribution from the corrosion inhibitor treatment, it was assumed that all of the phos- phorus from the chemistry was carried over into the heavy kerosene boiling range. Despite this conservative assump- tion, the phosphorus contribution from the inhibitor was less than 12 wt%. Contaminants other than phosphorus, such as silica, sodium, calcium, arsenic, lead, nickel, vanadium, iron and more, are also commonly found in crude and other feed- stock. These can be potential contaminants, poisons, and foulants for the hydrotreater and other downstream units.7 It is recognised that fouling and catalyst poisoning Figure 6 Phosphorus contribution from crude oil feedstock vs corrosion inhibitor

Hydrotreater feedstock characterisation 1

Average test value for

Approx. molar ppm level in light gasoil

Parameter

Unit

Naphtha

heavy naphtha

Kerosene

Light gasoil

TAN

mg KOH/g

0.05

0.12

0.16

0.13

570 410 530 730 340

Basic N

ppm N

42 16 46

24 15 61

Br #

g Br₂/100 g

17 50

230,000

CO SH

ppm ppm ppm wt%

203

265

217

100

Pyrrole

0.18

0.2

0.41

0.78

59,000

Table 1

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