PTQ Q3 2024 Issue

REFINING GAS PROCESSING PETROCHEMICALS ptq Q3 2024

ADVANCED ANALYTICS

CORROSION CONTROL MEMBRANE SEPARATION

FIRED HEATER ECONOMICS

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HONEYWELL UOP IS CURRENTLY SURPASSING ALL TECHNOLOGY PROVIDERS IN THE VOLUME OF CO ₂ CAPTURE CAPACITY INSTALLED PER ANNUM. *

*Source: Guidehouse Insights

Q3 (Jul, Aug, Sep) 2024 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY

3 Capturing high ROI when producing SAF Rene Gonzalez 5 ptq&a 15 Hydrogen recovery from ROG Part 2: membrane separation and compression Zach Foss Divigas 21 Navigating corrosion challenges in column overhead systems Rodolfo Tellez-Schmill and Soni Malik KBC (A Yokogawa Company) Ezequiel Vicent OLI Systems 27 Ultra-low entrainment spray nozzles for use in packing wash applications Alejandro Lago and Ashwin Patni Lechler Inc. 35 Hybrid model of gasoline blend Gadi Briskman, Ariel Kigel and Tom Rosenwasser Modcon-Systems Ltd. 41 Co-processing renewable feeds in hydrodesulphurisation units: Part 2 Cristian S Spica OLI Systems 49 Transforming packed column efficiency Shwu Tyng Goh and Thomas Linder Sulzer Chemtech 53 Controlling FCC SOx emissions with SOx reduction additive technology Hongbo Ma, Xunhua Mo, Marie Goret-Rana, Charles Kanyi and Carl Keeley Johnson Matthey 59 Sour gas and liquid treatments: Sulphur recovery and removal Cyndie Fredrick Merichem Technologies 63 Data-driven approach to steam-to-carbon ratio optimisation for the HGU Mert Akçin, İbrahim Bayar, Berkay Er, Gizem Kayar Öcal and Muratcan Özpınar SOCAR Turkey 71 Carbon cost driving refineries to rethink fired heater specifications Shilpa Singh and Rupam Mukherjee Engineers India Limited 77 Deactivation of FCC catalysts Warren S Letzsch Warren Letzsch Consulting PC 82 Blue hydrogen a low-carbon energy carrier: Part 2 Himmat Singh Scientist & Advisor 89 Technology in Action

©2024. 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 Increasing SMR efficiency: How advances in fired heater technology are increasing capacity and production margins. Photo courtesy of Integrated Global Services (IGS)

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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 29 No 4 Q3 (Jul, Aug, Sep) 2024 ptq PETROLEUM TECHNOLOGY QUARTERLY

Capturing high ROI when producing SAF

R efiners can co-produce renewable diesel (RD) and sustainable aviation fuel (SAF) using shared hydrotreaters and linked processing assets. This is feasi- ble because both fuels have similar production pathways and can be derived from the same feedstocks, such as vegetable oils, animal fats, used cooking oils, and other lipid-based biomass. ‘Older’ facilities already have existing infrastructure to support SAF production, including water treatment, sour water strippers, flare systems, and sulphur plants. For example, the recently reported doubling of SAF production at TotalEnergies’ Grandpuits refinery brings the site’s annual produc - tion capacity to 285,000 tons (almost double the capacity announced in 2020). At the recent 2024 AFPM Annual Meeting, Honeywell UOP’s Keith Couch noted: “There are great opportunities to repurpose old assets because infrastruc- ture already exists at decades-old refineries in Europe and USA.” Overall, co-pro - ducing RD and SAF is not only technically feasible but also economically attractive. However, aviation fuel standards are stringent, and obtaining certification for SAF produced alongside RD can involve complex regulatory approvals. SAF has stricter specifications compared to RD, especially concerning freeze point and thermal stability, which may require additional processing or more selec- tive catalysts. Regardless, refineries see the opportunity to adjust their output ratios based on market demand for RD and SAF. The primary difference in final products comes from carbon chain length and specific blending requirements for aviation fuel, which has stricter specifications for freezing point and energy density. The technology involved with hydroprocessed esters and fatty acids (HEFA) derived from biological sources is expanding to produce RD and SAF. Refiners can control product yield by adjusting process parameters such as temperature, pressure, and catalytic conditions. Utilising various feedstocks in a single process streamlines operations and maximises feedstock flexibility and utility. Refining facilities with units dedicated to processing renewable feedstocks for RD and SAF production also need to plan for low-value intermediates and waste products, such as organic residues, wastewater, glycerin, naphtha, and light gas- oils. There is anecdotal evidence that additional investments in RD, SAF, and other transportation fuels are partly due to uncertainty in the electric vehicle (EV) market. For example, Ford reported a $1.3 billion loss on EVs in the first quarter of 2024. In a research paper on Renewable Diesel and SAF by Fitzgibbon et al at McKinsey & Co, it was noted that: “Not all refineries earmarked for conversion will realise their ambitions, which could ultimately limit the number of potential conversions in the United States to as few as 30.” In any event, US RD and SAF capacity is pro - jected to reach 230,000 bpd by 2035. Current SAF production only supplies about 0.1% of global jet fuel demand. However, even though SAF production costs are higher than those of conventional jet fuel, capital is more available to develop a focus on low-carbon energy and sustainable transportation. Regulations and mandates also support SAF production. For example, fuel sup- pliers must ensure that 2% of fuel made available at EU airports is SAF in 2025, rising to 6% in 2030, 20% in 2035, and gradually to 70% in 2050. Some industry observers believe the emphasis on green energy and ‘virtue signalling’ is compel- ling financial institutions to invest in various products for the transportation sector, including SAF. With incentives like the SAF credit at $1.25 for each gallon of SAF in a qualified mixture, we are likely to hear about many new technological break - throughs in SAF production.

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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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PTQ Q3 2024

Flexibility is profitable

Flexibility Matters

tray vapor loads and internal liquid reflux rates. Keeping the upper pumparounds loaded can also help avoid low pumparound return or tower overhead temperatures that condense water and cause salting or corrosion problems. It may even make sense to turn off a lower pumparound. L ONG - TERM SOLUTIONS inking longer-term, cost-effective revamps can add critical flexibility to allow for wide swings in unit throughput and crude blends while still operating in control. e right process design enables operators to consistently:

In uncertain times, refineries can maximize profit (or at least minimize loss) through flexible operations. Crude units are the first link in the refinery processing chain, and making large changes in crude diet or throughput stresses even the most state-of-the-art unit. S HORT - TERM STRATEGIES Certain operating strategies can maximize reliability, yields, and product qualities. Some practical short- term options include: • K EEP THE BOTTOMS STRIPPING STEAM

At turndown, consider maintaining normal crude tower and vacuum tower bottoms stripping steam rates and lowering heater outlet temperature to control cutpoint. is allows the stripping steam to do the work while heater firing is minimized to protect the heater tubes at low mass velocities. L OWER THE PRESSURE Lowering tower pressures at turndown lowers the density of the vapor, which keeps trays loaded and can avoid weeping and loss of efficiency. Lower pressure also lowers draw temperatures, increasing pumparound rates and hopefully avoiding minimum flow limits for pumps and tower internals. M OVE HEAT UP In multi-pumparound towers, shifting heat to the upper pumparounds at turndown increases

•

Control desalter inlet temperature,

• Control preflash column inlet temperature and naphtha production, • Control pumparound return temperatures and rates independent of pumparound heat removal requirements, and • Precisely control vacuum column top pressure. is advice is, of course, generic. To discuss challenges unique to your own crude/vacuum unit, give us a call. Process Consulting Services believes crude units should have flexibility. We believe that revamp solutions should be flexible too - one size doesn’t fit all. We look forward to working together to find the most cost-effective and reliable solution to your crude processing problems.

•

3400 Bissonnet St. Suite 130 Houston, TX 77005, USA

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pt q&a

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

Q Can you comment on the shift in FCC product econom- ics beyond 2025? A Corbett Senter, Marketing Manager, Europe, Middle East, and Africa, BASF In the last few years, fluid catalytic cracking (FCC) econom - ics have been very favourable, Tightness in the transporta - tion fuels markets has led to a strong incentive (margins) for producing these products. This was more than enough to offset weaker propylene margins, as the supply of propyl - ene exceeded the expected demand in the market. The years beyond 2025 could lead to a shift in the market in a couple of significant ways. In North America and Europe, it is believed that gasoline and diesel demand (often >70% of the product produced by an FCC) has already or will soon peak. This is based on predictions of higher amounts of electric vehicle (EV) penetration in these regions. Steps such as the Inflation Reduction Act in the US and adherence to the EU Commission’s proposed Fit for 55/ RED III targets have shown that leadership in these areas remains committed to meeting CO2 reduction targets despite energy security concerns, which arose in 2022. Other parts of the world – Asia, the Middle East, Africa, and Latin America – show a more favourable growth outlook for these transportation fuels, which will provide upward pressure on global demand. A few key questions which should be asked in the next few years are:  Will EV growth keep up with projections? Growth continues to be positive, but supply chain disruptions and dependence on tax incentives in some areas have raised some doubts that previously did not exist. v Can co-processing of alternative feeds emerge as a sustainable (financially and environmentally) method of reducing the CO₂ footprint of products made from FCC? This would allow internal combustion engines (ICE) more of a place in a world with increased emissions legislation. w When will viable refined product from new FCCs reach the market? Multiple FCC startups are expected soon, which will increase refined product supply in the global market and decrease margins for FCCs globally. x Can hybrids emerge as a viable solution to compete with battery-only EVs? These offer reduced emissions with lighter batteries and will not be completely reliant on a charging network. While many questions exist regarding future FCC eco - nomics, FCCs are better positioned than other processes due to their flexibility. Pairing the proper operation and con - figuration with the correct catalyst strategy will allow FCCs to meet a variety of product targets. For example, FCCs which wish to maximise gasoline production could use a catalyst designed for high conversion to gasoline (such as BASF Luminate) or a catalyst that utilises multiple zeolite

frameworks to maximise alkylation unit feed production (such as BASF Fourte or Fourtune). Alternatively, an FCC which has a goal to maximise lighter olefin production, such as propylene, can utilise olefin pro - duction additives in combination with a base catalyst. This can generate the precursors needed to perform effectively with the additive (such as BASF MPS). An FCC unit is also flexible in that it can handle feeds of different qualities, and flexibility also exists within FCC catalyst technologies. There are specific solutions that can deal with common FCC feed contaminants, such as nickel (BASF Boron Based Technology) and vanadium (BASF Valor). Everyone in the industry is clearly concerned about the future of FCC economics. However, there is reason for opti - mism, as the flexibility of the process provides an opportu - nity for FCCs to adapt to whatever lies ahead. Luminate, Fourte, Fourtune, MPS, and Valor are marks of BASF. A Rainer Albert Rakoczy, Technology Advisor Fuels, Clariant Catalysts The original purpose of the FCC process and an FCC refin - ery was to focus on the production of high knock-resistant gasoline. Due to the energy transition, individual trans - portation by passenger cars will be fully electric-driven or plug-in hybrid cars. Additionally, so-called fleet effects by having more vehicles with lower consumption on the road, as older cars get substituted by the latest high mileage achieving models. With this shift, the overall gasoline mar - ket will shrink. Refiners will, therefore, need to focus on lighter prod - ucts, which are mostly light olefins, and the inclusion of the potential to condition cracker naphtha towards steam cracker feedstocks (fuel to chemicals). Enhancing light products can be achieved by reformulation of the applied FCC catalyst cocktail as an interim solution, However, sooner or later, the addition of a second riser reactor is much more efficient. To streamline cracker naphtha cuts as a steam cracker feed, a variety of catalysts can be offered from Clariant’s proprietary HDMax Series to saturate ole - fins and aromatics and even open the cyclic compounds. HDMax is a mark of Clariant Catalysts. Q How can AI capabilities improve machinery perfor- mance challenges? A Philippe Mege, Digital Services Factory Manager, Axens, Philippe.MEGE@axens.net There are several ways for AI to significantly enhance machinery performance, such as real-time monitoring by providing online recommendations to operators or con - trol systems. Axens, through its proprietary Connect’In monitoring solution, has developed dedicated recommen - dation dashboards for asset optimisation based on client

PTQ Q3 2024

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constraints and targets. Machine learning algorithms have been built and trained on historical data combined with first principles laws. These recommendations can also be managed in a closed loop through advanced process con - trol, optimising performance and preventing issues from escalating. Targets for machinery can be energy efficient by adjusting power consumption based on demand and oper - ating conditions and not at fixed parameters anymore, as could often be the case. Another application developed by Alfa Laval and inte - grated into the Connect’In solution is the Performa mod - ule dedicated to adjusting feed-effluent heat exchanger parameters to predict when operating conditions are likely to lead to damage or failure. By identifying potential issues before they occur, issues can be prevented and/or mainte - nance can be scheduled proactively, minimising downtime and reducing the risk of unexpected breakdowns. Connect’In is a mark of Axens. A Lisa Krumpholz, Managing Director, Navigance GmbH (a subsidiary of Clariant Catalysts) Machine learning algorithms in AI can significantly improve performance challenges in three key areas: continuous data stream analysis, real-time anomaly detection, and failure root cause analysis. Navigance harnesses the power of AI algorithms to automate data preprocessing, enrich data, and continuously analyse data streams, ensuring ongo - ing monitoring of machinery operations. By screening and interpreting vast amounts of plant data in real-time, along with dedicated algorithms, anomalies and suspicious machinery conditions can be precisely pinpointed, enabling plant teams to detect early signs of failures and devia - tions, facilitating proactive maintenance, and minimising downtime. Moreover, it enables a transition from preven - tive to condition-based maintenance, where maintenance decisions are based on the actual condition of assets. Additionally, AI-driven data analysis provides invaluable support in root cause analysis by analysing historical data and identifying patterns or correlations leading to failures. Q What options are available for increasing the number of higher octane gasoline components? A Pierre-Yves Le Goff, Global Market Manager, Reforming and Isomerisation, Axens, Pierre-Yves.LE-GOFF@axens. net, Yoeugourthen Hamlaoui, Global Market Manager, Axens, Yoeugourthen.HAMLAOUI@axens.net, and Bijay BARIK, Principal Technology Engineer, Axens, Bijay. BARIK@axens.net Several technologies are available for generating high- octane gasoline components. We are not reviewing all options in this instance, only the most important commer - cial technologies available today. Beginning with C₅/C₆ isomerisation, and depending on unit configuration, different catalysts can be proposed, ranging from zeolite to sulphated zirconia and up to the highest performance level with chlorinated alumina cata - lyst. For a given catalytic solution, depending on the feed and whether a high or low amount of C₅ component (vis

targeted octane) is present, the ensuing process flow dia - gram can be significantly modified. This modification can include the addition of a deisopentaniser upstream from the reaction section or the addition of a deisohexaniser (DIH) downstream from the reaction section. To reach the highest level of research octane number (RON), separation with a molecular sieve section can also be proposed. Going from the once-through configuration with zeolite to a unit based on chlorinated alumina with a DIH, the octane can increase from 80 RON up to 88 RON. With this technology, the RON is achieved by the produc - tion of multibranched C5/C6 paraffins and does not contain any aromatics or olefins. Reforming is another process for generating high-octane components. Isomerisation schemes can vary from one unit to another, but reforming process flow diagrams are all quite the same, with the major difference between units being the unit pressure. The oldest units can run at high pressure (30 barg). To maximise gasoline and hydrogen production, the most recent designs run at ultra-low pressure (3 barg) with a continuous regeneration (CCR technology) to ensure the highest time on-stream factor. The highest achievable RON with isomerisation is around 90-91 and about 102 with CCR reforming due to the presence of aromatics. A third solution to generate high-octane hydrocarbon is alkylation, which generates a chemical reaction between isobutane and C₄/C₃ olefins in the presence of an acid-type catalyst. The most common and safest alkylation units are sulphuric acid units. Indeed, hydrofluoric acid is quite a toxic and dangerous chemical. To generate an iso-C₄-rich stream, a C₄ isomerisation unit can be used. This unit uses a chlorinated alumina catalyst. A key advantage of alkylate is the absence of aromatics and its low RVP, making alkyl - ate an attractive blending component for the gasoline pool. A fourth solution is the use of FCC gasoline, the main constraint of this stream is the presence of sulphur. A dedicated hydroprocessing scheme such as Axens’ pro - prietary PrimeG technology can be used, allowing for sul - phur removal while minimising the olefin saturation, thus minimising octane losses. A new solution combines Axens’ Prime-G+ and GT-BTX PluS, which offers a unique solution to reduce octane loss to a very low level for the gasoline pool. The technology is especially important in countries upgrading fuel specifications to meet environmental requirements. It can be applied in new or retrofits of exist - ing operating units to maximise profit. Aside from pure hydrocarbon technology, another path - way to generate high-octane molecules is to produce oxy - genate components. For example, again, on an acid-type catalyst, it is possible to generate methyl/ethyl tertiarybu - tyl ether (MTBE, ETBE) by a reaction between methanol/ ethanol and isobutane. As for alkylate, the key advantage of oxygenates is their low Reid vapor pressure (RVP), mainly for MTBE, but some regulations limit the use of oxygenates, such as the MTBE ban in the US. PrimeG, Prime-G+ and GT-BTX PluS are marks of Axens. A Grant Severyn, Technical Service Specialist, Americas, BASF, Hernando Salgado, Technical Service Manager,

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AHEAD A long history of looking

For nearly a century, Grace catalysts have kept fuel and petrochemical feedstocks flowing from the industry’s largest refineries to the trucks, trains, planes, and ships that keep our world running. We are leveraging our long history of innovation in fluid catalytic cracking to develop products that enable lower carbon fuels and help meet the challenges of the energy transition.

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1.5

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Figure 1 Propylene to butylene selectivity of traditional ZSM-5 vs specialty MFT zeolite

Europe, Middle East, and Africa, BASF, Melissa Mastry, Director, Global Technology and Technical Services, BASF Multiple strategies can be utilised to increase FCC gasoline octane. First, increasing the octane of the ‘as-produced’ naphtha is an obvious choice, either by formulating a base catalyst with reduced hydrogen transfer to preserve high octane molecules, adding ZSM-5 additives also, or a com- bination of both. Of course, process condition adjustments, such as increasing reactor outlet temperature (ROT), can also increase the as-produced octane. Second, producing high octane blending components is another common choice. The desired blending component is alkylate, having a RON value typically ranging between 92 and 98 (a function of feedstock used between – C₃, C₄, or C₅). Historically, refiners have used an olefins additive, includ - ing ZSM-5, in FCC units to capture value from the mar- ket’s demand for increased light olefins for alkylation and higher-octane gasoline components. The ZSM-5 zeolite is designed to selectively crack gasoline-range molecules into propylene (C₃=) and, to a lesser extent, butylenes (C₄=). In general, C₄= alkylate has a higher road octane ([RONC + MONC] / 2) value than C₃= alkylate, and C₄= alkylate is less cost intensive to produce. As an example, alkylate made from C₃= and isobutane can have a road octane of up to 92, whereas alkylate from C₄= can have a road octane of up to 98. Therefore, C₄= alkylation is the preferred method for most refiners operating alkylation units. Since ZSM-5 zeolite tends to generate more propylene than butylenes (see Figure 1 ), there are strong incentives for FCCs, which feed to alkylation units, to increase C₄=/C₃= selectivity through the base catalyst technology to generate higher-octane alkylate species. FCC catalysts can be tuned to effect such change. Recent technical advancements have made this even more possible, with some refiners having taken it upon themselves to expand their alkylation units to fully utilise the benefits that improved technologies can offer. Fourtune and Fourtitude FCC catalysts for vacuum gasoil (VGO) and resid applications, respectively, utilise BASF’s Multiple Framework Topologies (MFT) technology (Figure 1) to maximise butylenes yield and selectivity over propylene.

The multiple zeolite frameworks have optimised acid site density and strength to ensure selective butylenes yield over propylene, as well as enhanced porosity to reduce dif- fusion limitations and minimise saturation reactions. The mechanism behind the success of such butylenes-maxi - mising catalysts involves both generation and preservation (avoiding saturation) of C₄ olefins while preserving high- octane molecules in the gasoline range. Fourtune and Fourtitude catalysts have been used in multiple commercial FCC units with stand-out performance in C₄=/C₃= selectivity (up to 1% volume increase in butyl - enes yield at constant propylene yield) and FCC naphtha octane for gasoline blending (up to 2 RONC increase) com- pared to alternative suppliers in unit operating data. These changes have allowed refiners to increase their refinery gasoline octane by two methods: improved octane of FCC- generated naphtha and an increase in alkylate production. Fourtune and Fourtitude are marks of BASF. A Jignesh Fifadara, Evonik Catalysts, Global Business Executive, HPC Catalysts and Sustainability, Evonik There are several methods to increase the octane rating of gasoline. However, each has its own advantages and limi- tations. Some of the methods include:  Blending of higher-octane components (alkylates, isomerates, or reformates) with lower-octane gasoline to increase gasoline pool octane rating. v Blending with an alcohol-based additive (ethanol) since it has higher octane ratings than gasoline and can be blended in certain proportions. w Addition of aromatics (benzene, toluene, and xylene) in small amounts, which have higher octane ratings compared to straight-chain hydrocarbons. x Investment in an isomerisation process that converts straight-run hydrocarbons into branched chain hydrocar- bons, which typically have higher octane ratings. y Addition of fuel additives focused on boosting octane can also be utilised but can be restrictive due to environ- mental concerns. z Optimising catalyst systems within an FCC gasoline hydrotreater to minimise octane loss while operating at higher severities to meet sulphur specifications.

PTQ Q3 2024

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While blending is a common method used to increase the octane rating of gasoline, there are usually concerns about high costs, availability, and environmental concerns. Due to that, optimising your catalyst system in the gasoline hydrotreater provides the most control to produce high- quality octane gasoline. A Subramani Ramachandran, Technical Service Director, Asia, Ketjen, Patrick McSorley, FCC Technical Service Engineer, Ketjen, and Junghwa Yoon, FCC Technical Service Consultant, Ketjen Refiners have a multitude of options for increasing overall octane barrels output from the refinery, either by increasing FCC gasoline RON and/or by increasing the output of high- octane blend components such as reformate, alkylate, and isomerate. Typically, FCC operators have multiple opera- tional handles to further maximise overall octane barrels from their FCC asset. While short-term operational moves like maximising riser outlet temperature (ROT), maximising CTO (impact depends on conversion level), and deployment of ZSM-5 additives can provide a short-term boost, they tend to move a carefully optimised FCC operation/cata- lyst system to an overall sub-optimal operating point. Our approach in such cases is to work closely with the refiner to design and implement a catalyst reformulation that can provide the necessary octane barrel shifts that the refiner is seeking while maximising overall profitability. Two such case studies of maximising overall octane barrels with dif- An existing customer using the Denali catalyst was looking to further maximise C₄= yields without significant penalty in gasoline volume from their FCC unit along with improved bottoms yields. The Denali family of catalysts incorporates our latest ZT-600 zeolite technology. It provides enhanced coke selectivity and superior activity retention, which directionally lowers hydrogen transfer at similar activity. A reformulated Denali catalyst was designed with direction- ally lower RE content while compensating for the lower resultant activity by enhancing the active-matrix content in the catalyst. Figures 1 and 2 show the key benefits of the reformulated Denali compared to the base. Not only was the reformulation able to provide the desired C₄= increase at minimal gasoline volume loss, but the overall octane bar- rels increase was achieved at lower slurry yields. Traditional approaches to light olefins selectivity optimisation have typically centred around RE-level optimisation, incorporat- ing different shape-selective activity with varying molecu- lar selectivities. In addition to these levers, optimisation of active-matrix content and type is an additional handle from a catalyst formulation standpoint to tailor the system hydrogen transfer index. While matrix components provide bottoms cracking along with activity enhancement, their ability to provide these benefits without enhancing hydro - gen transfer increase (HTI) provides an additional degree of freedom to achieve targeted molecular selectivities. fering yield objectives include: • Maximising net octane barrels • Maximising alkylation (alky) barrels. Maximising net octane barrels

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Maximising alky barrels Alternatively, depending on individual refinery configura - tions and economics, maximising alky barrels might be an overriding objective in certain regions. In this case study, the refiner was employing an Action catalyst, which is proven in the industry for its capability to maximise C₄= and C₄ olefi - nicity while providing excellent bottoms cracking. To meet their need, they were supplementing it with conventional ZSM-5 additive additions to increase the desired C₄ olefins. Action+ catalyst was proposed to Ketjen’s refinery partner, which employs a novel stabilisation technology (ZT-500). This new stabilisation technology provides a superior bal- ance between activity increase and HTI compared to con- ventional rare earth modification. This approach allows refiners to maximise C₄= yields at similar C₃= yields at comparable activity (see Figure 3 ), effectively maximising alky barrels more than conventional catalyst (plus additive) approaches would allow. For conventional FCC units oper- ating in maximum fuels mode, tailored approaches such as Action+ result in a significant increase in alkylate octane bar - rels due to a higher octane potential of C₄= relative to C₃= in an alkylation unit while achieving the above at a net lower wet gas volume, compared to conventional approaches. In summary, the FCC unit remains an important vehicle for maximising high-octane gasoline components. Optimal solu- tions will be refinery-specific, depending on economic driv - ers, and there is no one-size-fits-all. As the prior two case studies demonstrate, approaching the challenge holistically Figure 2 Slurry yields vs net octane barrels compared to incumbent catalyst

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gasoline octane with minimal LPG increase is Johnson Matthey’s Isocat HP additive. Standard ZSM-5 additives have a low silica:alumina (Si:Al) ratio. By increasing the alumina content of the ZSM-5 particle, there are more acid sites for catalytic cracking reactions. Independent of the alumina content, the shape selectivity of the ZSM-5 crystal also promotes isomerisation reactions to increase branch- ing and, hence, octane in the gasoline stream. Isocat HP additive is designed to have a very high Si:Al ratio, so it has a lower activity for cracking but maintains the shape selectivity of the ZSM-5 crystal to promote isomerisation and increase gasoline octane. This additive is used in FCCs where LPG processing is limited, but an increase in gaso - line octane is still required. SUPER Z, ZMX-B-HP, and ISOCAT HP are marks of Johnson Matthey . Q What opportunities do you see for the integration of biorefineries with steam crackers? A Yoeugourthen Hamlaoui, Global Market Manager, Axens, Yoeugourthen.HAMLAOUI@axens.net By integrating refineries and steam crackers, it becomes possible to take advantage of several sources of feedstock and increase the plants’ profitability. Refinery off-gases (ROGs) are used as feedstocks in the steam cracker after being treated in the different steps required to remove contaminants and maximise olefins recovery. Such a configuration allows for enhancing ethyl - ene and propylene yield by valorising low-value byproducts. On the same principle, naphtha produced by the refinery can be used in the steam cracker as a feedstock. This naph - tha maximises profitability. The hydrogen produced by the steam cracker can be valorised on the refinery side by any unit consuming it. On the one hand, for any existing integrated refinery with steam cracking, it could be relevant to consider switching from fossil naphtha to bio-naphtha, as the integrated scheme is already in place. The main counterpart standing in the way is economics, as currently the cost of bio-naphtha does not look attractive without appropriate regulation. On the other hand, the biorefinery is mainly oriented towards sustainable aviation fuel (SAF) production. Bio- naphtha is then a byproduct, which could be valorised but produced at quite low quantities. However, opportunities for integration of biorefineries with steam crackers seem quite limited. A Hans-Christoph Schwarzer, Head of Business Development Ethylene, Clariant Catalysts Although we do not foresee the true integration of biore- fineries with steam crackers, bio-based oil could be co-fed into a steam cracker after purification and stabilisation, like what is currently being established in chemical plastic recycling. Instead of being incinerated or ending up in land - fills, mixed plastic waste can be converted to pyrolysis oils, which can be used as feedstock for the sustainable produc- tion of chemicals. In this emerging field, producers are faced with continu - ously changing contaminants and contaminant levels in a

A ction A ction +

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7.5

6.5

Ecat FST C= (wt%)

Figure 3 Maximising alky barrels with Action+

and partnering with a catalyst technology provider will pro- vide the best outcomes in terms of achieving the desired yield and product quality shifts while maximising overall unit profitability. Various catalytic handles are available with advances in catalyst technology, and a partnership approach is the key to sustained success in a dynamic environment. DENALI and ACTION are marks of Ketjen. A Heather Blair, Senior Technical Service Engineer at Johnson Matthey There are a few operational methods available to increase higher-octane gasoline components. The first is to increase FCC riser temperature; an increase of ~13-15°F yields an octane increase of 1.0 RON, and a 25°F riser increase yields a MON increase of 1.0. Decreasing FCC feed gravity will also increase gasoline octane; a decrease of -1.7 API (+0.1 g/cc density) will increase gasoline RON by 0.6. Reducing the rare earth content of the base catalyst will also increase gasoline octane, but it comes at the expense of gasoline yield. The ability to change feed quality, adjust riser tem - perature, or change catalyst properties is not always pos- sible. An alternative method to increase gasoline octane is to utilise a ZSM-5-type additive. ZSM-5 additives increase the octane first by cracking C6 to C 10 straight-chain gasoline olefins into LPG olefins. This increases the propylene and butylene feed to the alkylation unit, increasing alkylate as a high-octane blending compo- nent. The cracking of the lower-octane gasoline species also concentrates the gasoline stream to higher-octane material. ZSM-5 has a secondary effect of increasing the gasoline octane. As ZSM-5 deactivates and loses cracking activity, older ZSM-5 particles isomerise straight-chain gasoline molecules to more highly branched molecules, increasing the octane of the gasoline stream. When ZSM-5 is used long term a significant boost in gasoline octane is observed. Johnson Matthey provides multiple types of ZSM-5, such as the standard Super Z family that cracks into both propyl- ene and butylene, with more selectivity towards propylene. The second family is ZMX-B-HP, which has more selectivity towards butylene than a standard ZSM-5 product. propyl - ene processing or sales outlets, but there is a significant economic benefit for butylene. The last ZSM-5 product with the unique ability to increase

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a feed that originates from diverse types of plastics. The previously noted HDMax catalysts and Clarit adsorbents answer the need for flexible and economical solutions to remove a wide range of impurities, regardless of process configuration or plastic waste feedstock, allowing plastic recyclers to achieve pyrolysis oil compatible with steam crackers. For bio-based oils, we see similar challenges also resulting from continuously changing contaminant levels that originate from diverse and varying sources of bio - mass. As for plastics-based pyrolysis oils, these challenges can be overcome, for example, by adaptable oil upgrading technologies. Clarit is a mark of Clariant Catalysts. Q With more emphasis on a CO₂ tonnage per dollar investment basis, which metrics matter in pursuing oppor - tunities in petrochemicals or low-carbon fuels? A Melissa Mastry, Director, Global Technology and Technical Services, BASF For petrochemicals, multiple metrics can be considered when pursuing a target related to CO₂ tonnage per dollar investment. First and foremost, the carbon intensity of the feedstock is a critical parameter to bring into any project assessment. Low-carbon intensity feedstocks can include bio-based feedstocks, clean hydrogen, and recycled mate- rials such as recycled plastics and waste. If considering petrochemical-based feedstocks, the source is important. For example, if extracted from tar sands, the carbon intensity will be higher than a petrochemical x KETJEN Renewables POSTER_210mmx146mm.pdf 1 4/30/24 3:29 PM

source extracted from a conventional oil well. In addition to the feedstock’s raw materials, it is crucial to consider the energy efficiency of the production process, the emissions (particularly CO₂ and methane) created during production, whether the process uses carbon capture and storage, and the transportation/storage of the feedstock. Storage can be an important factor, especially consider - ing the temperature-sensitive nature of some feedstocks, particularly those coming from pyrolysis processes. Similar metrics can be applied to low-carbon fuel standards. Ultimately, the best investment will depend on a variety of factors, including the regulatory environment, market demand for the products, and the geographical and logisti - cal details of the project location. Q What options are available for recovering hydrogen lost in fuel gas? A Rainer Albert Rakoczy, Technology Advisor Fuels, Clariant Catalysts In the past, many RFU streams were directly lined towards combustion without considering hydrogen content. An out - standing exception could be recognised in refineries short on total hydrogen. They operate a central RFU utilisation point, collecting all purges mainly from hydroprocessing and separating the hydrogen by means of permeation through a membrane or pressure swing adsorption with molecular sieves. In many cases, lining hydrogen-containing fuel gas from the process off-gas to the reformer or pre-reformer can also be an option.

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Hydrogen recovery from ROG Part 2: membrane separation and compression

Using next-generation separation membranes to recover unused hydrogen

Zach Foss Divigas

R efinery off-gas (ROG) streams will be a crucial source of hydrogen (H2) in refineries as product regulations and crude processing requirements drive increased H2 demands. The need will further increase as energy com- panies look to limit heavy sources of carbon within their operations to meet net zero goals by 2050. As refiners shift from steam methane reformer (SMR)- produced grey H2 to green or blue, costs will rise, increasing the necessity for downstream H2 recovery and purification to remain economically viable. Part 1 in PTQ Gas 2024 previewed sample ROG streams produced from several types of units for their poten- tial separation and purification via Divi-H, a proprietary next-generation H2 separation membrane. It demonstrates separation costs as low at $0.015/kg H₂ separated, with

return on investments (ROIs) exceeding 2,400% over the life of the product when compared to grey H₂ production. Part 2 will analyse its effectiveness in hydrotreaters, hydro- crackers, isomerisation units, and catalytic reformers. Hydrotreaters and hydrocrackers Hydrotreaters and hydrocrackers are similar use cases with a few key variables. ROG pressure can vary between these units depending on the level of reaction severity needed to meet product specifications and the composition of the feedstock. The gasoil hydrotreater, for example, can operate at pressures five times higher than the naphtha hydrotreater. This high-pressure operation makes its ROG ideal for mem- brane separation. There is a significant driving force in the

Stream

Feed

Permeate

Fibre type

Feed purity

Permeate Recovery

Total

Lifetime separation cost ($/kg)

flow rate pressure pressure

purity

module

(NM 3 /hr)

(bar)

cost

GO hydrotreater

20,000

135

High throughput

75%

95.31%

93.45%

$800,000

$0.015

95% purity

– single stage

GO hydrotreater

20,000

135

High purity

75%

99.00%

93.34% $10,480,000

$0.200

99% purity

– single stage

GO hydrotreater

20,000

135

Balanced and high purity – two stage

75%

99.91%

88.94% $18,560,000

$0.371

99.9% purity Hydrocracker 95% purity Hydrocracker 99% purity Hydrocracker 99.9% purity

10,000

120

Balanced

50%

95.07%

90.77%

$2,320,000

$0.138

– single stage

10,000

120

High purity

50%

99.04%

89.99%

$2,480,000

$0.147

– single stage

10,000

120

Balanced and high purity – two stage High throughput

50%

99.90%

85.43%

$5,920,000

$0.370

Diesel hydrotreater

15,000

80%

95.19%

94.53%

$1,520,000

$0.036

95% purity

– single stage

Diesel hydrotreater

15,000

Balanced throughput

80%

99.03%

94.48%

$2,720,000

$0.064

99% purity

– single stage

Diesel hydrotreater

15,000

High throughput and high purity – two stage

80%

99.90%

89.44% $12,880,000

$0.320

99.9% purity

Naphtha hydrotreater 30,000

High throughput

65%

95.06%

92.34%

$2,160,000

$0.032

95% purity

– single stage

Naphtha hydrotreater 30,000

High purity

65%

99.06%

92.67% $26,880,000

$0.397

99% purity

– single stage

Naphtha hydrotreater 30,000

Balanced and high

65%

99.91%

85.36% $38,080,000

$0.592

99.9% purity purity – two stage Table 1 Hydrotreater and hydrocracker analysis – no compression

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feed, and H 2 product pressures are high enough to feed to downstream hydrotreaters without need for any additional compression. It also tends to have higher H 2 purities in the ROG, with concentrations up to 70-80 mol%. For each hydrotreater and hydrocracker case, perme- ate purities from 95-99.9% were considered (see Table 1 ). When there is flexibility in the purity of produced H2 , membrane separation is incredibly beneficial. On average, a 99.9% purity H 2 stream requires five times the mem - brane Capex investment of a 95% purity stream. These H2 streams leave the membrane systems at a lower pressure than the feed to be sent either directly to any downstream unit operating at lower pressures or to recycle compressors. Ancillary equipment, including valves, piping, and pressure control, would add ~50% to the module cost. The high-pressure ROG streams produce a purified H2 stream that is still at high pressure. These streams could easily be recycled to lower-pressure systems without any recompression required. For a stream like the naphtha hydrotreater ROG, the H 2 permeate would only be between 7-17 bar. It would almost certainly need to be recom - pressed to either be recycled back to the source unit or uti - lised elsewhere in the refinery. It is important to keep in mind that another benefit of membrane separation is that the retentate stream (the H2 poor stream) leaves the membrane system at a near-feed pressure, allowing for a variety of different recovery and recycle opportunities. Assuming there is available H2 recycle compressor capac- ity, the costs of recompression to get the H 2 stream back up to feed pressure can be considered. For this analysis, we will look at the H 2 recovery over the life of a membrane unit (five years) and assume a unit uptime of 95% (to be conservative) with total H 2 production. The cost of H2 sep- aration will then be compared back to the cost of producing new H 2 via a grey H 2 steam methane reformer (SMR) pro- cess (with an estimated price per kg of $1.80) to find the breakeven point:

Where BEP days = breakeven point (days) C mem = Capex cost of membrane modules ($) C anc = Capex cost of ancillary equipment ($) C H2gen = Cost per kg fresh H2 generated ($/kg) R H₂rec = Rate of H₂ permeate production (kg/hr) P comp = Compression power required (kW) E cost = Electricity cost ($/kWh)

With the processing units shown in Table 2 , all options show a positive ROI but are highly variable depending on stream conditions and required purities. This demonstrates the criticality of designing the membrane system only to the required purity rather than automatically matching the 99.9% purity attainable from a pressure swing adsorption (PSA) system. The total H₂ recovery values vs the amount spent in mem - brane system Capex and compression Opex are significant, with the naphtha hydrotreater 95% purity case recovering more than $121M in H 2 value with only a $3.2M Capex investment and $1.8M in compression costs over the mem- brane life. Figure 1 is a visual comparison of each case vs the cost of new H₂ from a grey SMR H2 plant, including the Opex cost for compression back to feed pressures. Isomerisation unit, catalytic reformer, FCC The isomerisation unit typically has much lower ROG flow rates than the hydrotreaters and hydrocracker to upgrade low-quality naphtha into higher-quality gasoline blending components. The catalytic reformer is one of the few units in the refinery that produces H2 as a side product to its main reactions. It frequently supplements the SMR in H 2 production for the refinery. H2 from this ROG stream is typ- ically captured via PSA, and this stream will be reviewed for future comparison to PSA separation costs. H 2 recovery from the fluid catalytic cracker (FCC) was not assessed. A combination of it is low operating pres - sure (2 bar) and low H₂ purity (<10%) make it less ideal for membrane separation processes. The stream would require compression to at least 15 bar before feeding to the mem - brane module, and the H₂ permeate stream would require additional compression to be useful. While the separation

Stream

Recovery (kg/hr H 2)

Compressor

Module cost + ancillary +

BEP

H₂ value

Total Capex

Total Five-year

power

(months) over five

Opex over ROI

required (kW) compression ($/kg)

years

five years

GO hydrotreater 95% purity GO hydrotreater 99% purity GO hydrotreater 99.9% purity Hydrocracker 95% purity Hydrocracker 99% purity Hydrocracker 99.9% purity Diesel hydrotreater 95% purity Diesel hydrotreater 99% purity Diesel hydrotreater 99.9% purity Naphtha hydrotreater 95% purity Naphtha hydrotreater 99% purity

1,262 1,260 1,201 405.3 404.9 384.4 1,021 1,020 965.9 1,621 1,626

751.5 430.7

$0.07 $0.33 $0.63 $0.27 $0.30 $0.68 $0.09 $0.17 $0.55 $0.17 $0.62 $0.96

0.75 9.78

$94.5M $94.3M $89.9M $30.4M $30.3M $28.8M $76.5M $76.4M $72.3M $121.4M $121.8M $115.8M

$1.2M

$2.5M $1.4M $3.9M $1.0M $1.3M $2.0M $1.4M $3.3M $2.7M $7.9M $1.8M $4.7M

2,454%

$15.7M $27.8M

450% 184% 572% 505% 166%

1,156.6

18.69

311.5 387.9 588.2 426.4 981.7 801.7 2388 535.3

6.86 7.40

$3.5M $3.7M $8.9M $2.3M $4.1M

19.13

1.76 3.22

1,967%

940% 229% 985% 189%

16.02

$19.3M

1.65

$3.2M

19.42 29.72

$40.3M $57.1M

Naphtha hydrotreater 99.9% purity 1,546

1,414.7

87%

Table 2 Hydrotreater and hydrocracker economic analysis with recompression to feed pressures

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