Catalysis 2023 Issue

catalysis ptq 2023

UPGRADING DIESEL IMPROVING CATALYST

SURFACE CHEMISTRY

HYDROTREATERS PTQ supplement

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3 Finding the best catalyst Rene Gonzalez

5 ptq&a

2023 www.digitalrefining.com

19 Optimising FCC economics against changing market dynamics Heather Blair, Xunhua Mo, Marie Goret-Rana, Todd Hochheiser, Rick Fisher

and Paul Diddams Johnson Matthey

25 Co-processing renewables in a hydrocracker Peter Andreas Nymann and Pronit Lahiri Topsoe

31 Increasing refinery profitability via propylene maximisation Nate Hager, Abigail Devaney, Ally Payne, Stephen Amalraj and Bani H Cipriano W. R. Grace & Co.- Conn. 37 Lessons from FCC history: through Covid and post economic recovery Jacqueline Pope Bates, Melissa Clough Mastry and Alexis Shackleford BASF

43 Improved diesel hydrotreating catalyst loading scheme Tiago Vilela and Nattapong Pongboot Avantium 51 Advances in catalyst sulphiding and passivation Randy Alexander and Paul Temme Reactor Resources 55 Benefits of simultaneous mesoporisation/metal incorporation Danny Verboekend and Martin d’Halluin Zeopore Technologies 60 Reactivated catalysts can offer sustainability benefits in TGTUs Brian Visioli Evonik Catalysts

65 Welcome to Ketjen

Cover: Product recovery complexity benefits from well-designed catalyst/reactor configurations. Photo courtesy of LUKOIL Neftohim Burgas.

©2023. 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.

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Finding the best catalyst

catalysis ptq

2023

P ursuit of high-margin products, including olefins and aromatics, requires higher refinery complexity and integration with petrochemical infrastructures. This year’s annual publication of PTQ Catalysis 2023 reflects these evolving trends, as well as unexpected developments such as diesel profitability and the cata - lytic systems used in their processing. New catalyst formulations discussed in this issue are further synchronised with reactor improvements. In certain cases, catalysts have been developed as a stand-alone solution to avoid capital investment for higher reactor capacity, larger compressors, and pre- treatment requirements, such as with the current opportunity to increase diesel demand. Transportation fuels output is projected to level off, but not so fast. High margins currently seen with fossil fuel-based middle distillates (i.e., diesel) seem to contradict this projection. Going forward, ‘co-processing’ of second- and third-generation biofuels in tra- ditional refinery units such as the FCC and hydrocracker could keep the trans - portation fuels margins competitive vs electric-powered vehicles. For example, the US-based Energy Information Administration (EIA) projects that renewable diesel capacity in the US could more than double through 2025. However, the EIA noted that India and China hold the promise of more than doubling global biofuel demand growth in the long term. Proven catalyst formulations, such as for ULSD production, have been serv- ing refiners worldwide for nearly 20 years. However, recent enhancements, such as new pore structures, allow the processing of heavier refractory feedstocks containing a wider range of contaminants. Increasing cycle length and reducing annualised shutdown costs compels continuous investment to deal with new con- taminants challenges, such as co-processing fossil fuel-based hydrocarbons with biofeedstocks. It is no secret that finding the right combination of catalyst and reactor internals is essential for enhancing catalyst activity, selectivity, and stability and mitigating catalyst changeout frequency while ensuring reliable operation. In addition, CFD reactor and flow modelling allow process technology and catalyst developers to obtain a better understanding of feed quality and tailoring of catalyst systems. Whatever catalytic conversion process is under consideration (FCC, hydrocrack- ing, hydrotreating), the common thread involves fouling and contaminants removal, such as metals, sulphur, and nitrogen. Another common thread in the downstream catalysis lexicon involves a catalyst vendor’s ability to offer a tailored combination of catalysts to meet conversion and selectivity while taking into account equipment design, hydrogen availability, and cycle length. New parlances unfamiliar to refiners a generation ago are now mainstream, such as co-processing of second- and third- generation renewable feedstocks. The FCC unit is one of the best conversion units for co-processing unconventional feedstocks, but more intense co-processing through the FCC unit could significantly impact catalyst deactivation. To manage these types of challenges, we are seeing catalyst suppliers provide a wider range of technical support capabilities, including FCC unit monitoring and modelling of new feedstocks under consideration. Above all, with competitive refinery and petrochemical suppliers having to find creative ways to optimise profitability while reducing a facility’s carbon footprint, it is imperative to apply best practices toward molecular and energy management in the development of best-in-class catalysts and processes.

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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 Publisherat $30 per copy inc postage.

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catalysis q&a

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

Q Maximising cycle duration of hydroprocessing units has always been important to refiners, but what other step-out gains can we see from catalyst developments in terms of volume swell, PNA saturation, and HDN activity while achieving high HDS performance? A Brian Watkins, Global Technology Manager, Advanced Refining Technologies LLC (ART), brian.watkins@grace. com ART’s DX catalyst series has been used in ULSD applica- tions for over 16 years, while ART’s 425DX catalyst contin- ues to be used worldwide for middle distillates. The recent addition of 430DX to this line of catalysts allows refiners to process tougher feeds, meet tighter specifications, improve product quality, and expand capacity with no additional capital costs. The 430DX catalyst is built on recent advancements in alumina technologies. Innovations in surface chemistry and new pore structures significantly boost HDS, HDN, and HDA activity, with improvements exceeding 15% in some applications. 430DX exhibits an optimised bimodal pore size distribution for high activity and sustained performance. 430DX offers improvement opportunities to every diesel hydrotreating unit. Its benefits have been demonstrated on both straight-run and cracked stocks and at low and high operating pressures. Figure 1 compares 430DX to its predecessor 425DX in an ULSD protocol using a feed con- taining 15% cracked stocks. 430DX shows a clear activity gain in the low-pressure ULSD test and further extends its advantage in the higher-pressure test. This increased activ- ity enables the refiner to exploit the additional activity by processing more opportunity feedstocks as well as increas- ing the relative cycle length of the hydrotreater. Researchers have previously identified surface acidity as a key property for improved catalytic performance. It is gen- erally accepted that there is a strong relationship between the role of increased surface acidity, increased pore volume and surface area to improve the reaction rate for reactions controlled through ring saturation, such as nitrogen and hard sulphur removal.

200

HDS HDN

175

150

125

100

AT405 CDXi

420DX

425DX

ICR316

430DX

Figure 2 ULSD catalysts from ART Hydroprocessing

Changes in surface acidity have also been shown to affect the interaction of active metals with the alumina surface during impregnation. This phenomenon has been exploited in the design of 430DX, as seen by the significant increase in HDN activity and by utilising the ART hydrocracker pretreat support tailored to ULSD service. This catalyst improves upon the legacy impregnation technology lever- aged in 425DX, whereby a chelate is used to bind to the cobalt ions in the impregnation solution and reduce inter- actions with the alumina support. The chelate/ion complex stays intact on the catalyst, which allows the molybdenum to sulphide at a lower temperature, promoting the forma- tion of Type II active sites. 430DX features an optimised loading of cobalt and tuned chelation to further enhance activity compared to 425DX. Combining a modified alumina carrier with improved surface acidity and a larger pore diameter gives a catalyst

Conditions: 1.0 LHSV, 600 PsiH & 2000 SCFB H/oil Feed: 30% FCCLCO with 28.7 API and 1.78 wt% sulphur

Conditions: 525psi, 1.05 LHSV, 2,000 SCFB Feed: 31.9 API, 1.41 wt% S, 440 wppm N

HDN

430DX 425DX

HDS

All CoMo

All NiMo

SmART systems

Temperature improvement, ˚F

Figure 1 Comparison of 430DX to its predecessor 425DX

Figure 3 Catalyst selection and placement can be tailored

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that is custom tailored for demanding service at low and medium pressures. While the acid sites give 430DX better performance for both HDS and HDN activity, they are not strong enough to initiate any cracking reactions under typi- cal hydrotreating conditions. Figure 2 compares the line of ULSD catalysts from ART Hydroprocessing. 430DX can be coupled with the new 550DX (NiMo) cata- lyst within the proprietary SmART Catalyst System. This method fully utilises existing assets within a refinery’s indi - vidual constraints. Figure 3 shows how catalyst selection and placement can be tailored to provide the optimum bal- ance of maximum HDS and hydrogen consumption. A Steve DeLude, Becht Advisor, sdelude@becht. com, Jeff Johns, Becht Advisor, jjohns@becht.com, Jeff Kaufman, Becht Advisor, jkaufman@becht.com Catalyst activity improvements over the years have allowed operators to pursue various options to improve profitability and operating flexibility. While increasing cycle length and reducing the annualised shutdown cost can be significant, most refiners find that increasing throughput (debottle - necking), processing more difficult feedstocks, changing feed fraction cutpoints (yield optimisation), modifying operation to improve blending flexibility (improved product quality through higher hydrogenation), and/or higher vol- ume yields offer better overall value than simply pursuing a long cycle length strategy. Catalyst vendors have pursued multi-catalyst systems and new modelling techniques to tailor catalyst loads to specific refinery objectives. This situation makes it very important for the refiner to discuss in detail with potential catalyst suppliers their preferred operating strategy, feed options, and product quality improvement opportunities when considering their next reactor catalyst load. A Andrew Layton, Principal Consultant, KBC, andrew. layton@kbc.global CoMo catalyst was the typical distillate catalyst with high HDS but has improved in terms of available active sites and better surface areas contacting through Type II and equiva- lent catalyst active area changes. In many cases, these catalyst types also minimise H 2 consumption. To process feeds high in N 2 and boost cetane and cloud point, different catalysts became more important. NiMo catalysts improve Arosat (aromatics saturation) and HDN (most important in high N 2 ), cracked and heavier feeds with additional Type II metals/base interaction. NiMo HDS/ HDN reactions occur more through ring saturation than CoMo catalysts. Sometimes NiCoMo catalysts are a better fit. Improvements in catalyst ex-situ regeneration have enabled better catalyst re-use without sacrificing activity, even for Type II catalysts. While massive metal catalysts for high Arosat and HDS have a higher cost and higher H 2 consumption, these catalysts deliver a large increase in potential activity and aromatic saturation capability. This type of catalyst can be considered when a sufficiently high partial pressure of hydrogen is available and for some lubes operations.

Providing the reactor design is flexible enough to con - trol bed temperatures adequately, isomerisation catalysts are now used in the bottoms beds to improve cold flow properties. The cloud reduction/isomerisation catalysts are also improving to reduce yield loss resulting from cracking reactions. Most vendors offer tailored solutions, though massive metal catalysts currently have limited suppliers. Each round of development affects the relative catalyst ranking. Thus, the catalyst selection should not be based on one vendor for too long without comparing catalysts from multiple vendors. Note that maximising cycle length may now conflict with minimising energy use and carbon emissions as longer run length can mean more fouling, require high-pressure operations, and increase compression costs. Thus, opti- mum cycle length should be re-evaluated for both new and existing units. A Peter Andreas Nymann, Senior Solution Specialist, Topsoe, PAN@topsoe.com Higher activity catalysts like HyBRIM and HySWELL not only improve HDS activity but also improve the removal of nitrogen-containing hydrocarbons and the saturation of aro- matic components.* The higher HDN and HDA activity leads to lower product density (higher API), which leads to better cetane index and greater volume yields. The higher degree of aromatic saturation also provides additional end-point reduction, enabling the processing of higher boiling material in diesel hydrotreaters while still meeting the T95 specifi - cations. Higher activity may also facilitate the upgrading of lower-value streams like LCO and CGO in hydrotreaters to produce high-quality diesel. Higher saturation of aromatics and removal of nitrogen in FCC feed pretreaters improve FCC yields and product quality or alternatively enable co- feeding of lower quality feeds in the FCC. *Note: HyBRIM and HySWELL are marks of Topsoe. Q Besides improved catalyst systems, what advances in reactor internals are improving efficiency and throughput while also mitigating the effect of fouling and catalyst poisons? A Dinesh-Kumar Khosla, Global Market Manager Heavy Ends, HDC, Axens, dinesh-Kumar.khosla@axens.net Finding the right combination of catalyst and reactor inter- nals is essential for reliable and profitable reactor operation. In units featuring fixed-bed reactors, along with optimum catalyst design, overall reactor/catalyst performance can be enhanced by using high-efficiency reactor internals. Axens’ proprietary EquiFlow reactor internals ensure a uniform gas/liquid distribution and optimum mixing in the reactor, thereby minimising channelling and hot spots to ensure optimal use of the entire catalyst inventory in the reactor. This enhances catalyst activity, selectivity, and stability, and minimises catalyst changeout frequency while ensuring safe and reliable operation. EquiFlow distributor trays employ a dispersive system

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Vacuum tower cutpoint delivers profits

Cutpoint Concerns

poorly designed heaters may experience coking with COT below 700°F (370°C).

Crude unit vacuum tower performance is often critical to a refiner’s bottom line. e vacuum tower bottoms stream is valued far below the gas oil cuts, so most refineries look to minimize it. Many vacuum columns are also designed or revamped to produce a diesel cut, recovering diesel slipped from the atmospheric column that would otherwise be downgraded to VGO product. Good vacuum column performance can maximize the profitability of downstream units by removing distillate hydrotreater feed (diesel) from FCCU or hydrocracker feed (VGO) and removing VGO from coker feed (resid). One important measure of vacuum column performance is VGO/resid cutpoint. e cutpoint is the temperature on the crude TBP curve that corresponds to the vacuum tower resid yield. Vacuum column cutpoint depends on three variables: 1. Flash zone temperature 2. Flash zone pressure 3. Stripping section performance (if present) Flash zone temperature is driven by vacuum heater coil outlet temperature (COT). Increasing COT increases cutpoint. Vacuum heater outlet temperature is typically maximized against firing or coking limits. When processing relatively stable crudes, vacuum heaters with better designs and optimized coil steam can avoid coking even at very high COT (800°F+, 425°C), but

Flash zone pressure is set by vacuum system performance and column pressure drop. Lower flash zone pressure increases cutpoint until the tower shell C-factor limit is reached, at which point the packed beds begin to flood. Vacuum producing systems are mysterious to many in the industry, so a large number of refiners unnecessarily accept poor vacuum system performance. With technical understanding and a good field survey, the root causes of high tower operating pressure can be identified and remedied. In columns with stripping trays, stripping steam rate and tray performance are important. Stripping steam rate is limited by vacuum column diameter (C-factor) and vacuum system capacity. Any steam injected into the bottom of the tower will act as load to the vacuum system, so vacuum system size, tower operating pressure, and stripping steam rate must be optimized together. Depending on the design, a stripping section with 6 stripping trays can provide between zero and two theoretical stages of fractionation, which can drive a big improvement in VGO yield. Although the variables for maximizing vacuum tower cutpoint are simple, manipulating them to maximize cutpoint without sacrificing unit reliability is not. Contact Process Consulting Services, Inc. to learn how to maximize the performance of your vacuum unit.

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located below a chimney tray to ensure close-to-ideal vapour/liquid distribution throughout the catalytic bed underneath. EquiFlow quench systems (Hy-Quench-XM, Hy-Quench-NG) feature a more compact design.* This results in smaller reactors in grassroot configurations and increased catalyst volume for existing reactors. These quench systems provide higher thermal efficiency over a wider range of operating conditions, resulting in longer catalyst cycles and/or higher throughput operation. To mitigate the effect of fouling, the EquiFlow smart fil - tering tray system (Hy-Clean) limits recurrent pressure drop problems while ensuring a perfect gas/liquid distribution in reactors.* It will prevent plugging of the bed by catching and retaining feed impurities that are often responsible for crust formation between the different catalyst layers. Notably, with the use of Hy-Clean, there is no additional pressure drop compared to conventional distributors or quench sys- tems. Overall, Hy-Clean will enable a significant increase in catalyst cycle length, leading to higher profitability. Reduction in reactor operating temperature and pressure drop with Axens’ EquiFlow reactor internals also result in lower CO 2 footprint associated with specific unit operation. *Note: EquiFlow, Hy-Quench-XM, Hy-Quench-NG, and Hy-Clean are marks of Axens. A Jeff Johns, Becht Advisor, jjohns@becht.com, Jeff Kaufman, Becht Advisor, jkaufman@becht.com, Steve DeLude, Becht Advisor, sdelude@becht.com, Gene Roundtree, Becht Advisor, groundtree@becht.com Improved understanding of feed quality, reactor and flow modelling through reactor systems (CFD modelling) has allowed licensors and catalyst vendors to improve their internals and tailor their catalyst systems. Improved feed filtration systems reduce particulate and fouling on top catalyst beds. Improved distribution trays/internals and quench mix- ing allow better utilisation of loaded catalysts and reduce the risk of partial bed bypassing and/or hot spot formation. These increase the potential operating range for the reac- tor. In addition, the best new internals designs take up less space (allowing more room for active catalyst). They are designed for easy assembly and disassembly, reducing unit downtime during a turnaround and catalyst replacement. We also note that when new internals are installed in existing reactors, the upgrade should strongly consider new bed temperature indicators (TIs) for better tempera- ture control and reactor monitoring. Finally, graded/tailored catalyst loads, including specifically designed materials for fine particulate and/or maximum metals trapping, allow sustained operation with high catalyst activity and reduced fouling/pressure drop. A Andrew Layton, Principal Consultant, andew.layton@ kbc.global Since 1990, flow distribution has become increas - ingly important as product quality moves to ppm levels. Distributor tray design has changed to mitigate the impact of levelness and flow rate issues using better chimney

design. Adding spray nozzles to the trickle bed flows has improved coverage. Distributor trays often lose effective- ness over time due to thermal cycling, poor gasketing, poor construction, and few sites following optimum checking procedures during changeout. This situation has led to poor performance and activity losses exceeding 50%, often a bigger effect than changing to a better catalyst. The design of the beds has also been improved to optimise mass velocity and bed height. For example, increasing bed depth will cause some loss of good distribution as no bed is perfectly loaded, and the impact worsens as the bed gets longer. The bed loading procedures have improved with the advent of faster, more effective dense loading machines. New unit designs take turnaround and loading needs into account, including improved distributor tray access and, sometimes, more direct access to each bed rather than top loading only. This is also a better option from a safety view- point. In addition, the newer units no longer use interbed dump tubes, which created maldistribution issues. A vari- ety of approaches are now used to mitigate fouling issues in the reactor, including: • Separate foulant collection trays • Multiple bed grading with differing sizes, higher surface area, high metals capacity • Scale traps, or surface area enhancers, can be justified in severe cases if they increase surface area in the right spot with modified design and size, depending on the foulant • Bypass devices, which alleviate pressure drop by permit- ting partial bypass as pressure drop builds. Note that tackling a fouling problem in the reactor is a mitigation instead of a solution to the root cause. To improve operations, the following upstream factors should be examined: • Analyse and size-check foulants • Modify procedures to minimise foulant movement • Upgrade construction materials • Optimise filter design and focus on the right streams to filter, but not necessarily all • Minimise tankage feed • Solve upstream corrosion issues, usually at the primary fractionator • Improve desalter designs • Careful use of chemicals and consideration of down- stream effects • Collectively, this forms part of the unit’s KPI monitoring to track reliability. A Torkil Ottesen Hansen, Senior Technology Director, Topsoe, TIH@topsoe.com Examples of reactor internals that improve reactor per- formance by means of reduced fouling and pressure drop build-up include dedicated scale catchers like Topsoe’s pro- prietary HELPsc that can be installed in the reactor head to capture particulates brought in with the feed before they plug the catalysts beds. Another example would be improved distributor trays with capacity for sediments without obstructing the distribution. Continuous development of reactor internals technology will permit use of more complicated feeds in the future. The

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reactor internals will, in this connection, contribute rela- tively more to the combined reactor performance. In recent years, some focus areas have targeted renewable feeds fouling and coking potential as well as dealt with the high exotherms. It was necessary to rethink some of the other- wise very successful features used in the ULSD wave and fossil feed processing in general. Q What hydrocracking reactor catalysts are demon- strating optimal mid-distillate selectivity, better yield structures, and more efficient use of hydrogen? In combi - nation, which of these catalyst systems seems to be the most flexible in adjusting to feed quality variations and heavy feeds such as DAO and HVGO molecules? A David T. Dang, Senior Proposal Engineer, ART Hydroprocessing, David.dang@chevron.com Generally, hydrocracking catalysts with low zeolite con- tent are selected for maximum mid-distillate selectiv- ity. However, an integrated catalyst system with both hydrotreating and hydrocracking catalyst is required to achieve optimum catalyst activity and product selectiv- ity in a hydrocracking unit. The catalyst system should be customised for each customer unit to achieve the desired product yields and properties. Considerations for the optimum catalyst system include: • Hydrotreating catalyst is used to remove most feed con- taminants, such as metals, sulphur and nitrogen, and to condition the feed (pretreating) for hydrocracking • A layered hydrocracking catalyst system (such as hydro- cracking catalysts with different zeolite contents) can be used to optimise reaction zones for maximising mid-distil- late yield, minimising naphtha yield and LPG make • The amount of hydrotreating and hydrocracking catalysts needed depends on several factors such as feed properties, conversion target, product yields, and product properties. In addition, hydrocracking catalyst selection depends on the configuration of the hydrocracking unit, such as single stage once through (SSOT), single stage recycle (SSREC), two stage recycle (TSREC), as well as the unit operating pressure. • For feed quality variations, specifically with heavy feeds such as DAO and HVGO, the hydrotreating catalyst should be carefully selected to address additional feed contami- nants and increased feed conditioning. Moreover, increased hydrocracking catalyst activity and stability should be con- sidered to address higher cracking severity and fouling tendency of heavy feeds to ensure cycle run length target. An integrated catalyst system with hydrotreating and hydrocracking catalyst is required to achieve optimum catalyst activity and product selectivity in a hydrocracking unit

We have developed and continue to expand a hydrotreat- ing and hydrocracking catalyst portfolio to cover a wide spectrum of feedstocks and targeted products from maxi- mum distillate to maximum naphtha for different hydro- cracking unit configurations at different operating pressures. This is important when successfully selecting the optimum integrated catalyst system for many middle distillates selec- tive hydrocracking units. Furthermore, leveraging advances in research and development (R&D) in residuum hydropro- cessing leads to production of excellent demetallisation catalysts, which have been incorporated into hydrocracking units to allow for processing feeds with significantly high metals such as DAO. A Steve DeLude, Becht Advisor, sdelude@becht.com, Jeff Kaufman, Becht Advisor, jkaufman@becht.com Becht’s SMEs are aware that many catalyst suppliers are developing catalysts focused on reduced gas make, higher selectivity to middle distillates, improved final product properties (such as cold flow and cetane), and/or improved hydrogen use efficiency. Catalyst optimisation becomes a greater challenge when also combined with processing more difficult heavier feedstocks such as DAOs and HVGO streams. With these heavy streams, the ability to maintain high catalyst activity for HDS, cold flow improvement, and/ or cetane boost may be compromised by catalyst poisoning, coke deposit formation, and pore mouth plugging. The refiner must work closely with the catalyst supplier to identify the best catalyst option (including multi-catalyst systems) for their unit and specific objectives while recog - nising feed variations and/or quality constraints. A Andrew Layton, Principal Consultant, KBC, Andrew. layton@kbc.global Typically, hydrocracking catalyst systems are a combination of catalyst types based on feed type, feed contamination, selectivity, conversion, and unit design. The unit designs vary, depending on the combination of 1-3 stages with or without bottom product recycling. The hydrocracking cata- lyst selection can target different products such as naphtha, distillate, lubes, or some level of aromatic saturation. Stage 1 reactors generally use varying levels of metal contaminant removal catalyst based on feed metal concen- tration levels. If necessary, they also use antifoulant grading catalyst/inerts that have high metal adsorption potentials, different grading sizes, and high surface areas. The next catalyst bed typically consists of varying amounts of NiMo or NiCoMo catalyst. The NiMo catalyst is designed to sufficiently remove N2 to avoid impacting the performance of hydrocracking cata- lysts downstream. NiMo also improves aromatic saturation with HDS following more the ring saturation route. Units which require /prefer higher aromatic saturation sometimes used NiW but now also have a choice to use varying quan- tities of massive metal catalysts, which some vendors carry. These catalysts also require a minimum concentration of H 2 pp to be effective and consume more H 2 . Stage 2 reactors, or downstream beds, contain most of the cracking catalyst. The number of stages is determined

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A Peter Andreas Nymann, Senior Solution Specialist, Topsoe, PAN@topsoe.com Topsoe’s proprietary D-Sel series has been selected as the best catalyst for maximum mid-distillate production based on pilot plant studies carried out by third-party pilot plant test facilities. The performance seen in the tests has been confirmed in several operating hydrocrackers around the world for several cycles. Middle distillate has lower hydro- gen content than lighter fractions and a high selectivity to middle distillates, therefore significantly contributing to more effective use of hydrogen. The ability of hydrocracking catalysts to provide optimal performance can be unlocked by applying the appropriate grading/HDM catalyst selec- tion to help prevent contamination of poisonous compo- nents present in heavy fractions such as DAO and HVGO. The high-boiling materials are more refractive than lower- boiling feedstocks. They require high-activity pretreatment catalysts based on the proprietary HyBRIM or HySwell technology, where the HDN and hydrogenation activity has been optimised for heavy molecular hydrogenation. Q In building the petrochemical value chain, how much further can we see the FCC unit being used to increase ole- fins production with the wide range of feedstocks currently available, including waste plastics-derived pyrolysis oil? A Mel Larson, Division Manager, Business Planning, mlarson@becht.com The answer is less about ‘how much further’ and instead

both by feed type and necessary conversion level. High conversions tipping 75% and requiring high N 2 feeds are likely to appear in Stage 2, at the very least. Two types of cracking catalyst exist: amorphous silica alu- mina and alumina silica crystalline zeolites. Amorphous silica alumina shows lower cracking activity and targets more kero/diesel production. In comparison, alumina silica crystal- line zeolites achieve higher activity and target more naphtha production. Thus, amorphous catalyst may predominate die- sel maximisation as limited by achieving adequate activity. The heavier feeds will always favour some type of NiMo catalysts in the lead beds, and a larger percentage of this ‘pretreat’ catalyst will be required as the feed gets heavier and higher in N 2 . If feeds are heavier than DAO/HVGO, both catalyst particle and pore size may increase, making fixed bed units unsuitable. After the interstage H2 S/NH 3 removal, a noble metal catalyst may be used for high-con- version naphtha production units during the downstream stage. Several catalyst vendors offer a tailored combination of catalysts to meet conversion, selectivity, HDS, HDN, and Arosat needs while taking equipment design, H 2 availabil- ity, and cycle length into account. To differentiate between vendors and confirm their proposals, comparative data for catalyst systems can be requested. For example, H 2 consumption data can vary widely. Alternately, pilot plant data compared to a ref- erence catalyst may also be available if requested early enough.

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shifting the fuels plants only, if location allows, to a more sustainable petrochemical feedstock provider. The FCC currently plays a dual role as both fuels and petrochemical provider. As transportation fuel demand declines, both the reformer and FCC operating modes will shift directionally to meet BTX, styrene, and olefin market demand. The next step, which is already in deep R&D analysis, is how to adjust the FCC to more of a ‘crude-to-chemical’ engine in a ‘single’ unit as compared to other technolo- gies. Future FCC operations may include more recycling of product back through additional catalytic/thermal process- ing steps than currently practised. Additionally, if the rules change, the FCC will be the location where synthetic oils can be cracked with the potential addition of partial burn and hydrogen for further circular unit value. This last point may be decades off. However, the system and infrastruc- ture are already present, with selected additions to move in this direction. A Sanjay Bhargava, Principal Consultant, KBC (A Yokogawa Company), Sanjay.bhargava@kbc.global FCC gasoline is a major component of refinery-produced gasoline. Therefore, minimising FCC gasoline production can be an important step for oil refineries to reduce Scope 3 emissions. One way to reduce FCC gasoline is to convert it to propylene, as the demand for propylene is expected to increase significantly. Therefore, FCCs could become an additional source of propylene to meet the demand. Currently, FCCs produce about 4-8 wt% propylene on

feed and have the potential to produce over 15 wt%. As a result, FCCs present the industry with a significant potential to produce more propylene while, again, reducing Scope 3 emissions. Olefin production in FCCs can be increased by several methods. Some of these include: • Operational changes with higher severities (higher riser outlet temperatures) • Naphtha injection or FCC naphtha recycle • Catalyst modifications to more olefin selective catalysts (such as smaller cell size with lower Al 2 O 3 ) •· Catalyst additives (C 3= selective ZSM-5) • Mechanical changes with available licensor technologies to accommodate higher severities. Waste-derived pyrolysis oil can also serve as a feed- stock to FCCs. These include olefinic and aromatic-free feedstocks for FCCs and will produce naphtha and olefins in FCCs. However, the contaminants in pyrolysis oil, such as nitrogen, oxygen, chlorides, iron, and calcium, are sig- nificantly higher in pyrolysis oil than typical FCC feedstocks and, therefore, need pretreatment for contaminants before consideration as an FCC feedstock. If left untreated, the contaminants will cause increased corrosion and fouling in the downstream equipment and a significant increase in catalyst consumption due to catalyst poisoning. More environmentally friendly pathways that produce lower CO 2 emissions are available for olefin production, such as waste plastics-derived pyrolysis oil facilities. However, each alternative has its pros and cons. For exam- ple, pyrolysis oil conversion to olefins requires significant

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electrical energy that may not be all green and has its own pollution problems from ash and other materials. Further, these facilities are expensive to set up, operate, and main- tain. KBC believes the energy transition will take time. Thus, FCCs will play a significant role in the C3= olefin production market while co-existing with alternative pathways. Q What are some of the optimal strategies for process- ing (or co-processing) second- and third-generation renewable feedstocks? A Sophie Babusiaux, Hydroprocessing Technology Advisor, sophie.babusiaux@axens.net, Axens Lucas Vergaras, Principal Technology Engineer, lucas.verga- ras@axens.net, Axens Processing and co-processing renewable feedstocks is part of today’s main refineries’ strategies to reduce the carbon footprint of their activities. As defined by the European Union, second- and third-generation biofuels are produced from feedstock that does not compete directly with food and feed crops, such as wastes and agricultural residues (wheat straw, municipal waste), non-food crops (miscan- thus and short rotation coppice), and algae. The starting point strategy to integrate these feeds into a refinery is first to identify the local availability and indi - vidual feed challenges. Then, depending on the conversion/ hydroprocessing platforms available at site, look for the most suitable unit to cope with these in terms of existing hardware and impact on products. To be sure, more than 50 years of providing solutions in optimising refinery refin - ing schemes throughout the world delivers the repository of experience, know-how, and methodology to conduct detailed dedicated studies in a constantly evolving legisla- tion framework. Processing second- and third-generation biofeeds rep- resents specific challenges to the operation, for both new units and retrofits, either in co-processing or stand-alone mode. The design shall consider robust and proven solu- tions. We have developed solutions over the past 30 years to prevent pressure drop, loss of activity, corrosion, and other nuances that have emerged in the processing of renewable feedstocks. A Steve DeLude, Becht Advisor, sdelude@becht.com The optimal strategy is dependent on each site’s specific configuration, level of exposure to GHG emission-related costs (penalties) and/or biofuel production incentives, the logistical considerations related to the available biomass Processing second- and third- generation biofeeds represents specific challenges to the operation, for new units and retrofits, either in co-processing or stand-alone mode

feedstocks, the cost of the feedstock, and corporate capital availability/investment hurdle rates. The mandates of the Paris accord established require- ments for carbon intensity and GHG emission reductions that impact energy firms, regional/national governments, and investors. As part of the transition to lower emissions, traditional fossil fuel-based transportation fuels will be substituted by a combination of electric vehicles and bio- derived and renewable fuel sources. Existing refining and petrochemical assets are seen as key infrastructure in the energy transition equation, as much of the existing pro- cessing and distribution infrastructure can be repurposed for this new reality. This change in the marketplace will drive traditional refin - ers to examine processing and configuration options to align with the new feedstock and product profile, as well as energy input options. Those entities that are able to meet the changes in this dynamic market while remaining profit - able will continue as long-term viable enterprises. Biofuel- related strategies seen in the industry range from: • Full biofuel integration with dedicated biofuel units pro- viding fully fungible final product blend components • Partial integration and co-processing approach with bio- feeds brought on-site and pretreated adequately to match with the site’s existing units. • Third-party pretreatment arrangement or an owned, dedicated facility with feed specifications strictly monitored to ensure meeting co-processing/blending requirements • Purchase of biofuel blend components via open market • Purchase of GHG offsets from other entities. Finding an optimal strategy requires fully analysing each specific situation and identifying the range of options that could achieve the desired business goals. The progression of biofuel processing technologies from the current level to those in development is more catalyst- related than process-related. The steady progression of catalyst advancements has improved hydrogen selectivity and isomerisation to final products. As catalyst technologies further improve, opportunities exist for processing more challenging feedstocks and moving from biofeeds in com- petition with food sources to those which are non-edible. Europe’s Annex IX describes some of these bespoke bio - feeds, with consideration given to the use of non-edible cover crops using non-food-producing lands. The chang- ing feedstock quality imposes increasing levels of contami- nants and lower carbon contents. Processing these feeds requires consideration of how to remove the contaminants (including water) and capture the maximum amount of hydrocarbon products. The future transition to these new feeds requires con- sideration of thermal pretreatment processes linked with refinery post-treatment to make fungible fuels. (For addi - tional details, see Sayles and Ohmes, Conversion to a green refinery, Decarbonisation Technology , Nov 2022). Refinery configuration and biofeed considerations determine the ease of integration. In general, more complex refineries offer greater opportunities for biofeed integration. In conclusion, the consideration of co-processing is depen - dent on the refinery configuration, feedstock selection,

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catalyst application, and location. Optimised process designs are just one aspect of the overall solution, with biofeed sup- ply logistics very often being the overall controlling factor determining the most attractive co-processing opportunity. A Joris Mertens, Principal Consultant, KBC, joris. mertens@kbc.global Renewable feeds are either lipids (vegetable oils and ani- mal fats) or lignocellulosic material. The main strategic challenge around processing these renewable feeds is feed procurement. The first HVO/HEFA plants were mainly processing palm oil. However, the EU and, to a lesser extent, the US are nar - rowing the possibility to process such controversial feeds that pose substantial land-change issues. At the same time, REDIII, ReFuelEU legislation in Europe, and similar initia - tives in the US and elsewhere have further incentivised the demand for lipid-based mid-distillate production from HEFA technology, and specifically SAF. In about five years, only a limited amount of waste oils and fats is expected to be available for new projects. Despite its attractive lower cost and fewer feed sup - ply challenges, co-processing in existing units does not address the long-term (post-2030) decarbonisation chal- lenge, which will require a deeper cut in the carbon inten- sity of fuel than co-processing can deliver. Theoretically, technologies using lignocellulosic wastes should pose less of a concern with feed availability. However, raw lignocellulosic stock is much less energy dense. Therefore, they must be sourced from shorter dis- tances, typically less than 200km, which brings feed supply assurance to the forefront of strategic considerations. Pre- processing lignocellulosic material, for example pelletising or pyrolysis, can largely address the energy density issues but may add complexity to the feed supply chain. In addi - tion, technological maturity and required capital cost are more challenging for processes using lignocellulosic feeds. In addition to feed and technology readiness and cost, an optimised strategy needs to consider the product yield structure, which varies widely depending on feed type and technology, including catalyst technology. While the catalyst type impacts HVO yields significantly, with potential differ - ences up to 5%, unit configuration and catalyst type will dra - matically affect the SAF yield of Fischer-Tropsch complexes. A Stefan Brandt, Market Development Director, Energy Transition, W.R. Grace & Co., stefan.brandt@grace.com The terms second- and third-generation renewable feedstocks are not defined globally. In a briefing of the European Parliament in 2017, second-generation biofuels were “derived from waste and agricultural residues (such as wheat straw and municipal waste) or non-food crops (such as miscanthus and short-rotation coppice).” 1 Third- generation renewable feedstocks are often referred to as being related to algal biomass, for example. While there are several process units capable of process- ing second- and third-generation feedstocks, the flexibil - ity of the FCC unit is well suited for the co-processing of unconventional feedstocks. However, challenges exist in

Figure 1 Testing the miscibility of second-generation renewable feedstock in VGO

the industry to establish a continuous supply of renewable feedstock components, especially for second- and third- generation renewable components. Availability of some of these is expected to grow over the coming years. Therefore, any strategy for co-processing these feedstocks needs to start with a reliable sourcing plan. The optimal strategy for co-processing renewable feed- stocks in an FCC unit is always related to a deep under - standing of the properties of the feedstock component in terms of storage, miscibility, physical and chemical proper- ties and its impact on the operation and yield structure of the FCC unit. Thorough characterisation and catalytic pilot plant testing are recommended to identify the opportuni- ties and challenges. Second-generation renewable feedstocks typically exhibit higher variation in quality compared to first-gener - ation renewable feedstocks derived from edible oil sources. Additionally, miscibility with conventional feedstock can be challenging (see Figure 1 ). The FCC unit can cope with feedstock quality variation because of its flexibility in oper - ation and catalyst design adaptability. Nevertheless, the variability of the renewable feedstock component might put additional emphasis on the regular FCC unit monitoring. Depending on the nature of the renewable feedstock, hardware modifications might be required to prevent reli - ability risks from co-processing. Technology licensors have developed hardware solutions to minimise these risks and optimise the catalytic conversion of the combined feed. The FCC unit, with its flexibility in catalyst formulation and replacement, is able to adjust to challenges coming in with various feedstock contaminants. Renewable feedstocks bring other contaminants to the FCC unit than crude-derived feedstocks. At low co-processing percentages, depending on the operation, the effect on catalyst deactivation is often unnoticed. However, increased co-processing rates will ultimately put more emphasis on the risks associated with new contaminants in the FCC unit. FCC catalyst suppliers can provide solutions and recommendations based on the individual refinery strategy, operation, and objective.

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