PTQ Q4 2023 Issue

REFINING GAS PROCESSING PETROCHEMICALS ptq Q4 2023

PROCESSING RENEWABLE RESOURCES

CERAMIC COATING APPLICATIONS EFFICIENT CARBON CAPTURE

FCC-BASED PETROCHEMICALS

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Q4 (Oct, Nov, Dec) 2023 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY

3 Cost factors to consider in 2024 Rene Gonzalez 5 ptq&a

19 An economically attractive carbon capture solution for FCC Jan de Ren, Sakthivelan Durai, Raul Zavala and Erick Bennet Honeywell UOP 29 Catalyst testing for renewable fuels and chemicals Giada Innocenti, Kai Dannenbauer, Jochen Berg, Xavier Sanz and Ioan-Teodor Trotus hte GmbH 35 Transforming refineries’ opportunities through FCC Lucas Dorazio and James Fu BASF Corporation 43 Crude to chemicals: Part 1 – The basic concept of crudes Kandasamy M Sundaram, Ujjal K Mukherjee, Pedro M Santos and Ronald M Venner Lummus Technology 51 Olefin purification: Why selecting the right adsorbent matters Florence Pennetreau and Todd Burkes Evonik Catalysts Steffen Görlich PCK Refinery 57 Closed-loop sampling systems can lower fugitive emission levels Matt Dixon Swagelok Company 63 Identifying high catalyst losses Warren Letzsch Warren Letzsch Consulting PC 69 Simulation VGO and waste lubricating/cooking oil co-hydroprocessing Mohamed S El-Sawy, Fatma H Ashour and Ahmed Refaat Cairo University Tarek M Aboul-Fotouh Al-Azhar University Samia A Hanafi Egyptian Petroleum Research Institute 79 Big changes in the US octane market George Hoekstra Hoekstra Trading LLC 85 Managing life cycle assessment and life cycle thinking in refining Berkem Ç, Sarp Akarsu M and Esenboğa E E Tüpraş 89 Optimising fouled distillation units Soun Ho Lee Valero Energy Corporation 97 Estimating natural gas demand at a petrochemical complex Uğurcan Tozar, Mert Akçin, Murathan Bağdat, Dila Gökçe Kuzu, Nesip Dalmaz and Kemal Burçak Kaplan SOCAR Türkiye 103 Assessing LNG feed gas depressurisation Tek Sutikno Fluor Enterprises 109 Enabling safe FCC unit operational changes through ionic modelling Cristian Spica OLI Systems, Inc. 115 Control corrosion in refineries and petrochemical plants Berthold Otzisk Kurita Europe Mohamed Hudhaifa Kurita AquaChemie 119 Technology in Action

Cover World-scale petrochemical facilities such as the Formosa Point Comfort plant along the Texas Coast continue to push the envelope targeting energy efficiency and GHG reductions.

Photo courtesy of Lummus

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Vol 28 No 5 Q4 (Oct, Nov, Dec) 2023 ptq PETROLEUM TECHNOLOGY QUARTERLY

Cost factors to consider in 2024

H igh construction costs in the petrochemical industry can be attributed to fac- tors impacting the design, procurement, and commissioning of petrochemical facilities. It is no secret that high construction and operational costs are seen in every industry and commercial sector. However, the ‘hybridisation’ of the hydro- carbon processing industry seen with the integration of the biochemical processing industry (such as fast pyrolysis integrated with hydrotreating) complicates planning. Intricate petrochemical processes, equipment, and safety considerations demand extensive planning and engineering expertise, driving up costs. Refining and pet - rochemical facilities must adhere to numerous regulations and environmental stan- dards. Complying with these often requires additional design elements, specialised equipment, and safety measures, contributing to higher costs. Depending on the complexity, these facilities often need significant site preparation and infrastructure development, such as building access roads, utility connections, and waste disposal systems, and the associated costs can be substantial. Skilled craftsmen and other specialised labour are essential for all construction phases, often commanding higher wages due to the specialised nature of the work and potential risks involved. Additionally, labour shortages in certain regions can ramp up costs. At RefComm Galveston 2023, it was noted that there is a shortage of labourers available for the installation of refractory in FCC transfer lines, while the increased usage of structured packing in main fractionators is calling for a higher level of skill to avoid damage during installation. More expensive specialised materials that may have been overlooked during pre- planning are compounding revamp and turnaround budgets, including the need for higher amounts of quality, steel such as 316 S.S., and specialised alloys, such as Monel, that are more resistant to corrosion by many aggressive agents (such as high TAN crudes). Higher complexity requires advanced process control systems. In the long term, these multiple layers of control system investments mitigate operational costs. The most recent advanced capabilities, including AI and machine learning capabilities, require extensive training and vendor support. Implementing these engineering controls and safety measures can add to the overall construction costs. In any event, delays in project timelines can lead to increased costs due to prolonged labour, equipment rentals, and other ongoing expenses. Changes in project scope, design, or requirements can also result in additional costs. Then, the market’s economic fluctuations, currency exchange rates, and geo - political factors must be considered. Extended delays in transporting large and heavy equipment to remote or challenging locations can incur substantial costs. Difficulties in accessing remote areas can further complicate logistics and increase costs. The refining and petrochemical industry also competes with other industry sectors for financing. Securing financing for petrochemical projects can involve high inter - est rates or complex financing structures. ‘Virtue signalling’ investments involving decarbonisation technology can facilitate financing for multibillion-dollar projects to justify the production of high-margin products from SAF to specialised polymers. Downstream projects often have long construction and commissioning periods, during which labour, equipment, and other expenses accumulate because of the product supply and distribution challenges seen since the global pandemic. Scaling up or down the capacity of a facility due to market or regulatory factors also impacts costs. In summary, high construction costs result from the complex nature of strin- gent regulatory requirements, the need for specialised materials, labour, safety con- siderations, as well as external economic and logistical factors.

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PTQ Q4 2023

Heater coking is not inevitable

For many refiners, heater coking in Crude and Vacuum Distillation Units (CDU/VDUs) is a common occurrence. Many units around the world are shut down every two years, every year, or even every six months to deal with chronic heater coking. However, with the right design features driven by a solid understanding of heater coking mechanisms, fired heater run length can be extended beyond five years, even with relatively challenging crudes. e two primary drivers of heater tube coking in CDU/ VDU services are oil film temperature and residence time. Secondary factors such as crude coking tendency, solids content, and blend instability can further accelerate heater tube coking. So, which heater design parameters will maximize heater run length and avoid shutdowns for high heater tube metal temperature or high heater pass pressure drop? M ASS FLUX IS KING Mass flux (lb/s/ft 2 or kg/s/m 2 ) is found by dividing the mass flow through a heater tube by the tube’s cross- sectional area. High mass flux begets high velocity and suppresses coking in several important ways. First, high mass flux means that the fluid moves through the tube faster, minimizing residence time. Second, high velocity results in high heat transfer coefficient, which minimizes internal oil film temperature. Finally, high mass flux creates high wall shear inside the tube, minimizing build-up of solids or asphaltenes. Avoid Fired Heater Coking

H EAT FLUX CAN SURPRISE Heat flux (BTU/hr/ft 2 or kcal/hr/m 2 ) measures the amount of heat absorbed through a given outside surface area of a heater tube. High heat flux raises tube metal temperature and causes high oil film temperature inside the tube. Popular fired heater design programs use a well-stirred firebox model and calculate peak heat flux by applying a simple multiplier to the average heat flux. In reality, heater design parameters such as firebox height/width ratio, burner type, burner sizing, burner placement, and air/flue gas flow patterns can result in actual peak heat fluxes that are much higher than the “calculated” peak heat flux on the heater datasheet. Localized areas with very high heat flux will coke and suffer from high tube metal temperature. Of course there are many other variables that must be considered, such as pass arrangement, vertical or horizontal tubes, cylindrical or box or cabin, coil steam, etc. Problems stemming from blend instability are becoming more common as refiners are increasingly mixing light shale crudes with heavy crudes. As the crude begins to vaporize, asphaltenes can precipitate out of unstable mixtures and coat the heater tubes, forming coke and creating hot spots. Even with challenging crudes, refiners have achieved Crude Heater and Vacuum Heater run length goals through careful design and respect for the basics of coking. Contact Process Consulting Services, Inc. to learn more.

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pt q&a

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Q At what plants are you seeing best available burner technology being applied to lower emissions? A Grant Jacobson, Division Manager, Fired Heaters, Becht, gjacobson@becht.com Two segments of owner/operators are investing in new burner technology: u Those experiencing higher energy prices are tending to move in this direction to improve Opex but are also captur- ing improving emissions. v Those who have made carbon-neutral pledges on a timeline are working on plans to meet these commitments. Old and large (high duty) fired equipment is being targeted for these investments to lower emissions to help in these efforts. A Andrew Layton, Principal Consultant and Toshiaki Momoki, Senior Staff Consultant, KBC During the 1990s, or even earlier, environmental regula- tions changed. Regulatory agencies shifted their focus to reducing NOx in emissions as the specifications for NOx in flue gas became more stringent. As a result, advancements in burner design helped improve burner fuel efficiency and turndown and also reduced particulates and carbon mon- oxide (CO). N₂ in the air is the primary source of NOx (organic N₂ in heavier fuels is a secondary source). High flame tempera - tures are favourable to produce NOx from N₂. Reducing the flame temperature is one way to lower NOx, but this action conflicts with minimising particulates and CO in the flue gas, favoured by high flame temperatures. Thus, the burner design must strike a balance. Low NOx burners can be divided into at least two stages of development: u ‘Low’ NOx burners that target ~40-50 vppm NOx at 3% excess O₂ v ‘Ultra low’ NOx burners that target ~10-20 vppm at 3% excess O₂. As the target drops towards 10 vppm NOx and around 50 vppm CO, the design features include air and fuel stag- ing and sometimes flue gas recirculation. Some modern ultra low NOx designs use lean premix with fuel staging without flue gas recirculation. Since the new burners may sometimes be bigger than the existing burners, furnace floor modifications may be nec - essary. The new burners may also have smaller tip holes, which means gas pretreatment to remove liquid droplets and other foulants is often included in the upgrade to con- trol burner fouling. Most furnace systems can and often do use ‘ultra low’ NOx burners. Some petrochemical plants with radiant wall burners use low NOx burners. Several well-known and pro - ficient burner vendors produce these types of burners and have offices worldwide.

Q What efficiency factors are making the removal of mercaptans and acid gas from natural gas more efficient? A Carmella Alfano, Lead Technology Engineer, Carmella. ALFANO@axens.net Géraldine Laborie, Gas Technologies & Sweetening Expert, Geraldine.LABORIE@axens.net, Axens Depending on the type of acid gas that needs to be removed, many factors can play into the efficiency of acid gas removal. High pressure and low temperature can increase the efficiency of both H₂S and mercaptan removal. For CO₂ removal, as kinetics are the factor that needs to be considered, an optimised temperature at high pressure can make the removal more efficient. Another factor that can increase efficiency is the contact time in the absorber. This can be optimised by selecting the appropriate number of trays or type of packing. It is espe- cially important when selectively removing H₂S. The last major factor to consider for increasing acid gas removal efficiency is solvent selection and composition. In the proprietary AdvAmine technology developed by TotalEnergies, IFP Energies nouvelles, and Axens and exclu - sively licenced by Axens, the solvent is selected based on either total acid gas removal (DEA or EnergizedMDEA) or selective removal of H₂S (MDEA). The solvent composi - For CO₂ removal, as kinetics are the factor that needs to be considered, an optimised temperature at high pressure can make the removal more efficient tion is then optimised to maximise the rich loading and minimise the Capex and Opex. When mercaptan removal is also required, total acid gas plus mercaptan removal can be achieved using the proprietary HySWEET technology, which uses a hybrid-based solvent. This technology is developed by TotalEnergies and exclusively licenced by Axens. Operational factors must also be considered: ensuring the proper regeneration of the solvent is imperative, regular solvent sampling to make sure the concentration is correct, and proper solvent filtration to avoid any foaming issues. A Marcello Ferrara, Chairman, ITW Technologies, mfer- rara@itwtechnologies.com, Cristina Ferrara, Senior Process Engineer, ITW Technologies, cferrara@itwtech- nologies.com When running an amine unit, some of the most common ana- lytical parameters that are monitored to check performance include free amine and HSS content on the amine side and

PTQ Q4 2023

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H₂S/mercaptans content on the gas side. The absorber delta P, among the others, will dictate unit capacity. A common way to address reduced efficiency is to mea - sure HSS on the circulating amine, increase amine make- up, and/or perform amine reclamation whenever the HSS content exceeds defined values. Normally, a 1.5 wt% HSS content is targeted in the circulating amine. While the bespoke approach increases operating costs (such as amine, reclamation, and disposal costs), it will not address HSS/amine degradation products deposition into the unit. Reclamation and/or amine make-up increase will affect the circulating amine but cannot address any fouling inside the equipment, with specific reference to the absorber/regenerator. HSS/amine degradation products will deposit inside the unit during amine circulation and accumulate in tower internals. Trays/packing fouling will dramatically reduce tower efficiency and acid gas removal. Trays/packing fouling will also have a major impact on foaming because the gas will preferentially find its way along the not-fouled portion of the tower internals, thereby increas - ing its velocity. It is well known that foam will expand upon A common way to address reduced efficiency is to measure HSS on the circulating amine, increase amine make-up, and/or perform amine reclamation whenever the HSS content exceeds defined values increasing gas velocity, not to mention that the fouling itself and the solids (HSS/amine degradation products) will con - tribute to stabilising the foam. Foam formation will further reduce gas removal efficiency and lead to capacity reduction. We indeed have seen many cases wherein increased antifoam injection did not bring any help to foam mitiga - tion. Therefore, lower acid gas removal efficiency must be addressed differently by keeping in mind that the conven - tional approach is costly and will lead to a capacity reduction. By applying ITW Online Cleaning technology, the entire amine unit can be cleaned in 24 hours on a feed-out/feed- in basis. This is, therefore, a powerful optimisation tool for the entire amine unit, which can resume production after 24 hours under clean conditions, getting the value of enhanced acid gas removal efficiency and reduced energy consump - tion (the reboiler and the lean/rich exchangers will also be included in the cleaning). Q What strategies can be considered to integrate ethyl- ene plant furnaces and gas turbines to improve the facil- ity’s energy balance and efficiency? A Berthold Otzisk, Senior Product Manager – Process Chemicals, Kurita Europe GmbH, Berthold.otzisk@kurita- water.com In steam cracking furnaces, product yields are reduced

when coke deposits inside radiant coils are formed. This has a direct impact on the energy balance in the down - stream section because efficiency losses and side reactions like CO or CO₂ formation can then be observed. Glass ceramic coatings on the furnace tube surface reduce catalytic coke by forming a very thin layer of diffu - sion barrier. This improves the on-stream time of a furnace before decoking is required. The use of sulphiding agents is an alternative. Sulphiding agents with DMDS or Kurita Cut-Coke are well-known, cost-effective, and proven coke inhibition technologies. Typical dosing rates are 20-100 ppm sulphiding agent injected into the dilution steam dur - ing normal operation conditions. Kurita Cut-Coke is a poly - sulphide with a high flash point of 100°C and a significantly lower, more pleasant odour compared to DMDS. Ethane, LPG, and unconverted oil (UCO) from hydro - crackers require continuous treatment with the sulphiding agent. Naphtha feed from the crude distillation unit already contains sulphur, so a continuous coke inhibition treatment is not needed. If all cracking furnaces (including naphtha cracking furnaces) are treated with the sulphiding agent for 2-4 hours after decoking operation, longer runtimes and lower CO and CO₂ concentrations in the downstream section can be achieved with this pretreatment. This has a direct impact on a better energy balance with lower energy costs. Gas compressor fouling may require an unscheduled shutdown. A fouled compressor operates at higher than desired suction pressure to maintain the desired discharge pressure with a loss in efficiency. In most cases, thermal degradation to coke, free radical polymerisation, and Diels- Alder condensation are the causes of fouling. Wash oil, wash water, and powerful antifoulant programmes with dispersants and fouling inhibitor components avoid or sig - nificantly reduce fouling. This ensures lower energy costs and higher product yields. A Frederico Epstein, Study Manager, HSB Solomon Associates LLC, frederico.epstein@solomoninsight.com Ethylene crackers with gas turbine (GT) integration are among the most energy-efficient in the business. Despite that, an analysis of the feasibility of that type of integra - tion will not always show the option as economically viable, depending on different factors. The primary factor affecting the feasibility of those proj - ects is the availability of electrical power at low costs. Generally, the GT/cracker integration is not present in locations where reliable electrical power is available at a reasonable cost. In contrast, the need for reliable internal power generation in a market with high energy costs will drive the feasibility of those projects. Beyond decisions regarding the availability of power and energy costs, an important consideration is the moment of the investment decision in the asset’s life. Despite a considerable array of energy efficiency improve - ments available to operators, preheat systems for boiler feed water and combustion air, integrated gas turbine or cogeneration units, or waste heat boilers (for example), installation of these capital-intensive options within the

PTQ Q4 2023

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operating life cycle of the olefins unit may be cost-prohibi- tive or not feasible due to plant layout. A common characteristic when evaluating the most efficient olefins units globally is designed-in efficiency. Strategically, if energy efficiency is expected to be a criti- cal element in a facility’s licence to operate or in the overall return on investment (ROI), the most economic and effec- tive method to ensure this is to incorporate it in the engi- neering, procurement, and construction (EPC) phase of a project. This ensures a holistic view of the facility’s energy balance, whereas individual projects like those previously described impact energy intensity only incrementally. Though it is inherently challenging to implement these incremental effi- ciency improvements after sustainable operation has been established, constraints imposed by environmental and regulatory concerns, or perhaps economic incentives, may very well create the right conditions of feasibility. In summary, though there are any number of valid incre- mental options to pursue to strengthen an olefins plant’s energy performance, the best option strategically is to build in that energy efficiency at the earliest project stage. Q What contaminants removal strategies are available for commercial-scale co-hydroprocessing of renewable feedstocks? A Scott Sayles, Becht Advisor, Becht, sayles@becht.com The transition from fossil to renewable feeds is occurring around the world. Renewable feedstocks contain a wide variety of contaminants and concentrations depending on the source. Containments depend on the type of renew- able feed, such as from seed oils or animal fats and/or the These contaminants either adversely affect catalyst activity or cause fouling or corrosion. Removing them takes two major pathways both of which are referred to as pretreatment: u Physical removal v Hydrothermal. Physical removal uses conventional separation technolo- gies such as centrifuge and water washes to remove the contaminants. These units or pretreatment units (PTUs) are similar to those used for food preparation, and the technol- ogy stems from that work. The use in fuels operations has resulted in some upgrades and changes to improve reliabil- ity and performance. Hydrothermal pretreatment utilises heat and water to remove the contaminants. This emerging field of technol- ogy has advantages over the more traditional processes. Combining the two methods offers a flexible and effec- tive way to clean renewable feeds for processing via hydrotreating. These pathways assume a conventional type of biomass. Common contaminants are: u Alkali metals (Na, K, P Ca, and others) v Free fatty acids (FFA) w Chlorides, both organic and inorganic x Moisture y Chlorophyll z And others.

fixed-bed approach to hydroprocessing. The use of an ebullated bed combined with the hydrothermal treatment offers an emerging technology that creates a system with continuous catalyst replacement and produces a renewable product stream from a wider range of renewable feeds. A Chris Wallace, Vice President of Technology and Senior Vice Corporate Vice President, Filtration Technology Corporation, cwallace@ftc-houston.com Hydrotreating organically derived renewable feedstocks has numerous challenges, and catalyst technology and process changes to mitigate these challenges are rapidly occurring. One of these challenges involves unwanted con- tamination – suspended solids, dissolved solids, suspended and dissolved water, and phospholipids – in the feedstock. Two primary concerns about contamination control in co- processing renewable feedstocks are: u Protecting the catalyst from molecules that poison the catalyst and cause catalyst deactivation. Examples include phosphorus (from phospholipids), alkali metals (potassium and sodium), iron (due to corrosion of steel piping, trans- portation and storage), silicon (from dust and soil), and chlorides. v Protecting the catalyst bed from premature catalyst fouling due to suspended solids fouling of the fixed-bed catalyst reactor. Common examples are residual particles from the conversion of plants and animals to oils and fats, iron oxides or corrosion products from storage, transporta- tion and piping due to the high total acid number of some feedstocks and silicon from dust and soil from harvesting, transportation and storage. In renewable feedstock co-processing, it is common for refineries to convert an existing hydrotreating unit to newly licensed renewable conversion technologies utilising spe- cialised catalysts. Most existing units already have filtration vessels designed to protect the fixed-bed catalyst from premature fouling by contaminants not removed by the guard bed (if present). In some cases, new units are being built, and filtration equipment should be carefully specified in the design. Both established refineries and new plants face a common challenge: renewable feedstocks tend to

Organically derived renewable feedstocks have higher TSS concentrations than traditional feedstocks and can vary significantly by feedstock type, source, and level of pretreatment

PTQ Q4 2023

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catalyst life via proper catalyst protection with filtration equipment optimised for the plant’s unique situation. After all, a strategy in concept is only as good as its out- come in reality. A Joris Mertens, Principal Consultant and Ujjval Bhatt, Senior Staff Consultant, KBC The pretreat section’s main objective is to remove phos - phatides/phospholipids (gums) and other impurities. Phosphatides are biochemical intermediates in the growth of plant cells that are naturally present in oils. Not only do they contain phosphor, a severe catalyst poison, but they also can trap metallic ions that cause problems in storage and processing. The conventional feed pretreat configuration consists of an acid degumming and washing step, followed by a dry pretreatment step with cold filtration (taking place at 90-100ºC and low pressures). The degumming consists of making the gums oil-insoluble by hydrating them in an acid environment using, for example, citric acid. The resulting components are removed by adsorption on bleaching earth. Product phosphor content is typically specified to be below 2 ppm, while the combined metals (Ni, V, Si, Na, Al, Fe, and more) content should be below 10 ppm. The quantity and the nature of the phosphatides in the raw co-processed feed depends on the origin of the feed, and some of the phosphatides are more difficult to remove than others. Therefore, the design of the pretreatment unit will depend on the quality of the feed, which varies signifi - cantly depending on the source. (Vegetable) oils obtained after treatment with water (such as olive oil) tend to con- tain relatively limited amounts of phosphor, below 20 ppm, Others, such as heavily processed but also soybean oils, are much richer in phosphor and/or other poisons. In addition, waste animal fats may contain traces of polyethylene (for example, from ear tags) that need to be removed. This is done in an additional crystallisation step. Difficult feeds may, therefore, require methods which remove phosphatides that acid degumming does not hydrate. That can involve, for example, using EDTA or more aggressive technologies that break down the P-containing molecules. In brief, the first step in developing a strategy involves understanding the feed quality (range), as this will determine the investment cost of the pretreatment section. Equally important, however, is the strategic decision to either han- dle pretreatment in-house or to outsource it. Co-processing is normally done in limited amounts, up to 10% of the total feed rate. Therefore, the capital cost will be relatively high, which will likely make outsourcing a consideration. A Jaap Bergwerff, Global Renewables Business Development Director, Ketjen, Jaap.Bergwerff@ketjen. com Above all, each combination of feed and reactor configura - tion is unique. In our 20 years of experience in renewables co-processing, we have learned that generating the best catalyst system for each cycle requires a true partnership between the unit operator and catalyst technology supplier.

Canola Oil 3%

Other 1%

Corn Oil 15%

Yellow grease 18%

Soybean Oil 50%

White grease 4%

Tallow (beef) 7%

Poultry 2%

Common organically derived feedstocks for renewable fuels

have much higher concentrations of suspended solids, which are problematic for filtration equipment not specifi - cally designed for the new feedstock blend. The level of suspended solids in renewable feedstock is significantly higher and more comparable to the feed qual - ity in a gasoil hydrotreater (100-250 mg/L) than in a diesel hydrotreater feed (1-15 mg/L). As such, the equipment should be designed accordingly. It is safe to assume that the filtration equipment in any existing hydrotreater feed application was sized primarily based on the total feed flow rate. In the case of renewable feedstocks, the solids concentration will govern the vessel sizing along with the careful selection of filter technology, filter media, and media flux rate. Fortunately, refineries have a few options: • If the existing filtration equipment was previously sized appropriately or generously and the internals of the ves- sel allow for modification, the vessel can be modified to increase the surface area and dirt-holding capacity to achieve reasonable filter life while maintaining adequate catalyst protection. This can be done on-site at the plant without impacting the ASME code stamp on the vessel. • Existing equipment can be replaced with a new vessel properly sized for the solids content rather than flow rate. The new equipment design should rely on laboratory eval - uation of the feedstock and correlate with proper filtration media/filter technology selection. To address unique challenges and optimise contamina - tion removal strategies at refineries and renewable plants, FTC studies different feedstocks and blends in its Research & Development Center. It collaborates with refining cus - tomers to understand their feedstock blends and effluent quality needs with the common goal of achieving targeted

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For inorganic contaminants, such as Si and P, guard bed catalysts are applied to break down the organic matrix and accommodate the inorganic component. In these materials, the balance between reactivity and accessibility is essential to minimise the slip of the components to downstream cat- alyst beds, achieve maximum uptake capacity, and protect the downstream catalysts along the cycle. For HDO, optimal selectivity is critical to minimise the for- mation of CO/CO 2 /CH 4 , which results in maximum hydro- carbon yields and a minimum inhibition effect on the HDS and HDN reactions. For organic contaminants, such as amides and unsaponi- fiables, the key is to apply catalysts with sufficient hydroge - nation activity while at the same time preventing undesired side reactions. Finally, the activity of the main hydroprocessing catalyst is important since a superior activity allows you to accom- plish the same activity within a smaller volume. In specific cases, by applying a bulk metal catalyst, reactor space can be created for a larger guard bed volume, allowing for the acceptance of a higher concentration of contaminants. A Gitte Nygaard, Senior Solution Specialist for Renewable Fuels, GTIN@topsoe.com and Federico Francisco Cristófoli, Sales Director, FFCR@topsoe.com, Topsoe A/S Renewable feedstocks are bringing a new set of contami- nants into the hydroprocessing units when co-processing. Although at first glance they look familiar, the renewable contaminants are placed in other chemical complexes and, therefore, require a different guard technology. Specialised renewable guard and grading catalysts for the pick-up of contaminants from renewable feedstocks have been developed over the last decade We need to distinguish between raw and pretreated feedstocks. Most raw renewable feedstocks come with vast amounts of contaminants. Therefore, these feeds need to undergo pretreatment to get the contaminants down to acceptable levels before hydroprocessing. Often, the renewable feedstocks will be a minor part of the feed blend, so it is more economically feasible for the refiner to buy already pretreated renewable feedstocks instead of investing in their own pretreatment facilities. Raw renewable feedstocks may also be unstable, so pretreat- ment outside the hydroprocessing unit and proper storage need to be ensured to prevent operational issues while processing. A comprehensive catalyst grading system is needed to handle these contaminants, as well as the well-known con- taminants in the fossil feedstocks. Specialised renewable

guard and grading catalysts for the pick-up of contami- nants from renewable feedstocks have been developed over the last decade. There are two major strategies for making the grading system in the industry as today. The first one is to try to pick up all contaminants with the same type of grading cata- lyst as in fossil service. This is beneficial for units with very little flexibility since this will require the smallest volume for grading, which is considered suitable when co-pro- cessing relatively small amounts of renewable feedstocks. The drawback is that these types of grading systems only provide a very limited opportunity for the refiner in terms of quantity of renewable feedstocks and feed flexibility. Furthermore, skimming during the cycle may be required to achieve the desired cycle length for the bulk catalyst. The second grading strategy is to apply a more complex grading system comprising of several specialised guards and grading catalysts. This system provides much larger feed flexibility for the refiner and can allow more renew - able feedstocks to be co-processed. This type of grading system will, however, require slightly more space in the reactor, where typically 20-50% more volume for grading is needed, depending on the desired feed flexibility and quantity of renewable feedstocks. This will, however, often eliminate the drawback of having to do a skimming during the cycle. One of the most challenging contaminants for conven- tional hydroprocessing catalysts is phosphorus, which is found in phospholipids in vegetable oils. Phospholipids react quickly at the top of the reactor, forming a crust that causes pressure drop and frequent shutdowns. Topsoe has developed a new series of catalysts specially designed to handle complex renewable molecules, such as phospholipids. One example is TK-3000 PhosTrap, a novel catalyst technology that can trap phosphorus deep inside the catalyst pellet, preventing crust formation and pressure drop. This catalyst can extend the cycle length and improve the performance of the hydroprocessing unit. Using selec- tive grading catalysts like TK-3000 PhosTrap is a simple and effective way to remove contaminants from renew- able feedstocks when co-processing them in conventional refineries. Q Where do you see refinery reactor and catalyst tech - nology advancing in tandem towards processing a wider variety of crude feedstocks and intermediates? A Scott Sayles, Becht Advisor, Becht, ssayles@becht. com Processing renewable feeds using hydroprocessing tech- nology requires the removal of contaminants using a PTU (see Question 4 ) and then further removal using a guard bed reactor. The guard bed reactor typically contains a bed (or beds) of catalyst to remove the remaining contaminates and then deoxygenation reactions to create the alkanes for further processing. The catalyst in each bed is specific to the functionality required to complete the reactions. Figure 1 shows the renewable feed processing steps. Of interest are the processing and treating steps in the process.

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Feeds

Pretreat

Storage

Processing

Treating

Blending

Figure 1 Processing renewable feeds using hydroprocessing technology

A Giada Innocenti, Application and Project Manager, hte GmbH, giada.innocenti@hte-company.de, Ioan-Teodor Trotus, Team Leader Refining, hte GmbH, Ioan-Teodor. Trotus@hte-company.de The processing of a wider variety of crude feedstocks and, in general, the processing of more challenging feedstocks is going to be tackled by the existing refineries in most cases by utilising more efficient catalytic systems. The goal would be to repurpose the existing reactor technology to maxi- mise the yield of the target product. The real challenge that all the refineries will have to overcome is understanding how the feedstock behaves on the offered catalysts and/or in the pipelines and pump systems. As feedstocks become more challenging, models become less reliable, and it becomes more and more important for refineries to test the performance of the catalytic systems on the market in combination with real feedstocks. Testing is ideally performed on a smaller scale to mini- mise the costs associated. Testing will not only allow the best catalyst set to be selected but also uncover eventual issues in processing using a smaller amount of feed and develop solutions. Most often, hydroprocessing and FCC catalysts have been tested in separate experimental programs to optimise each one in isolation. However, with state-of-the-art test- ing equipment, one can also consider performing FCC pre - treatment and catalytic cracking experiments in tandem to evaluate the impact of pretreatment conditions on the FCC unit’s performance. This can also be employed to determine on a laboratory scale whether, in the co-processing of fossil and renewable feeds, the feeds should be blended before the FCC pretreatment unit or if it is more advantageous to blend the renewable feed with a hydrotreated fossil feed. In our view at hte, the future of reaction technology will involve more testing cut out specifically for the targets and boundary conditions of each refinery. A Darrell Rainer, Technical Service Advisor, Darrell. Rainer@ketjen.com , Cliff Avery, Global FCC Process Specialist, Cliff.Avery@ketjen.com , and Jon Strohm, Advisor R&D, James.Strohm@ketjen.com , Ketjen The FCC unit is already one of the most versatile units in the refinery, but we see an increasing demand for flexibility in the coming years. There will be increased interest in pet- rochemicals, particularly from renewable and circular feed- stocks. These changes in product demand and feedstock variability also demand improvements in catalyst design and FCC injectors, regenerator (low to high delta coke), the main column, and the high-pressure system. Regarding feeds, refiners are looking into co-processing recyclable and renewable oils. These feedstocks can range

Catalyst systems are designed to provide the following functionality: • Guard bed • Hydrotreating • Dewaxing or isomerisation. The guard bed reactor catalyst or trap catalyst function- ality is to remove the contaminants not removed in the pretreatment system, or PTU. The trap catalyst is distin- guished by high surface area and low catalyst activity. The objective is to operate the trap bed or guard bed system for the maximum length of time before breakthrough occurs. Developments in trap bed catalysts have extended the life of the system, improving on-stream time. Once the contaminants are removed, catalyst function- ality for hydrogen addition is in the next catalyst bed(s). These catalysts have the following reaction paths: • Decarboxylation • Decarbonisation • Hydrodeoxygenation. The conservation of renewable hydrocarbons in the Catalyst development has led to hydrodeoxygenation reactions producing water instead of CO or CO₂. These improvements increase the selectivity of converting renewable feeds to final products product is the desired goal of the catalyst. The first two reactions, decarboxylation and decarbonisation, produce CO and CO₂, which do not capture the carbons into the final fuel. Catalyst development has led to hydrodeoxygenation reactions producing water instead of CO or CO₂. These catalyst improvements increase the selectivity of convert- ing renewable feeds to final products. The alkanes produced have high cetane but poor cold flow properties. Improving the cold flow properties requires isomerisation or dewaxing of the alkanes. The dewaxing

reactions occur in two types: • Cracking and isomerisation • Isomerisation.

The cracking and isomerisation catalyst are useful to pro- duce SAF, while the isomerisation catalyst is more selective to renewable diesel. Catalyst improvements continue in the dewaxing area to increase selectivity and cold flow prop - erty improvement.

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from naphtha to resid boiling-point range hydrocarbons and contain atypically high levels of contaminant met- als, such as K, P, Ca, Fe, Mg, and Si. To address the chal- lenges associated with these new feeds to the FCC unit will require the co-development of reactor and catalyst tech- nologies. Biogenic oils such as vegetable and used cooking oils (FOG-oils) and biomass pyrolysis oils (bio-oils) contain high levels of oxygenates and alkali metals. Additionally, bio-oils may feature elevated levels of water/TAN, thermally unstable and insoluble in conven- tional FCC feeds. Other feedstocks, such as waste plastic- derived oils, can contain high levels of contaminant metals, halides, and olefins and can have a large portion of the oil in naphtha and LCO boiling range, more than typical FCC feeds. Viable catalyst solutions must address the require- ment for high metals tolerance, deoxygenation activity, and acceptable coke selectivity while maintaining desired prod- uct selectivities. Managing enhanced corrosion risks during storage and transportation of highly oxygenated feedstocks with lower pH associated is also important Handling and storage can also be problematic, poten- tially requiring stabilisers and/or emulsifiers due to the reactivity of olefins in plastic oils or the poor solubility of bio-oils in conventional feeds. Separate feed storage and new injection strategies, particularly for bio-oils, may be required. Managing enhanced corrosion risks during stor- age and transportation of highly oxygenated feedstocks with lower pH associated is also important. Injection of thermally unstable feeds with high free water content may require separate injection nozzles to account for lower feed injection temperatures and volume expansion associated with free water in bio-oils or lower boiling compositions of plastic oils. FCC unit licensors continue to develop technology solutions in these areas to support feed flexibility. As part of decarbonising the FCC unit, technology pro- viders are developing new reactor technologies, includ- ing increased flue gas feed atomisation to reduce steam demand, oxy-combustion coupled with CO₂ capture from the regenerator, and reactor designs with improved thermal efficiencies. These enhancements in reactor design have a direct impact on catalyst requirements. Oxy-combustion may result in higher severity in the regenerator, which will require highly stable catalytic materials, while the integra- tion of conventional CO₂ capture technologies may require improved catalytic materials for sulphur management within the FCC unit. Additionally, improvements in thermal efficiencies and reduced steam for feed atomisation will require low coke-selective catalyst technologies to fully take advantage of reactor improvements.

Co-development of innovative process and catalyst solu- tions is necessary to fully address challenges associated with increasing feedstock and product slate flexibility for the FCC unit. Collaboration between technology providers, process chemical providers, catalyst vendors, and the refin - ery is required to navigate the energy transition success- fully and profitably. Q What cost-effective strategies are available to allow diversification of fuels refineries towards the petrochemi - cal value chain? A Pierre-Yves Le-Goff, Global Market Manager Reforming and Paraffin isomerisation, Pierre-Yves.LE-GOFF@axens. net , Arnaud Cotte, Aromatics Product Line Manager, Arnaud.COTTE@axens.net , Axens Considering the potential reduction of gasoline consump- tion, linked to the growth of car electrification, while there is a still growing demand for petrochemicals, some refiners may consider shifting part of their reformate production to petrochemicals. Among the various options available, some necessitate marginal capital expenditure. The first option, if the reforming unit has some activity and cycle length margin or coke burning extra capacity, is to lower the naphtha initial boiling point to maximise the number of benzene precursors and increase the reactor temperature to increase aromatics production. This being done, it is possible to implement an aromatic extraction unit to produce petrochemical-grade benzene, while the raf- finate can be sent as chemical naphtha to a steam cracker to generate olefins or dropped to the gasoline pool for vol - ume or specification requirements. If the toluene can be removed from the gasoline pool while maintaining the gasoline pool specification, a toluene disproportionation unit can be considered. Depending on the catalyst choice, a mixed xylene stream or a paraxylene- rich stream can be produced, together with petrochemical- grade benzene. If the gasoline demand and specifications can be met with only a C₉+ cut, the mixed xylene-rich stream can be eventually extracted and sold on a petrochemical basis. This short introduction only gives a flavour of the pos - sibilities a refiner may consider when evaluating a move to petrochemicals. A Andrew Richardson, Johnson Matthey, andrew.rich - ardson@matthey.com A range of strategies exist to allow diversification of fuels at refineries toward petrochemicals cost-effectively. Johnson Matthey’s ZSM-5 additive products can be used to convert gasoline-range molecules into propylene and C₄s, both valuable chemical intermediates. Other strategies include the deployment of technologies to produce blending com- ponents for decarbonised fuels, which can drop into exist- ing refinery process streams without modification, allowing diversification toward decarbonised fuel products. JM’s proprietary FT CANS and BioForming technologies can produce drop-in low-CI molecules suitable for use across the gasoline, kerosene, diesel, and BTX markets.

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