PTQ Q4 2022 Issue

REFINING GAS PROCESSING PETROCHEMICALS ptq Q4 2022

CATALYST SELECTION ECONOMICS

INCREASING NEEDLE COKE YIELDS CAPITAL PROJECTS

FCC UNIT TROUBLESHOOTING

MAKE EVERY MOLECULE MATTER

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Q4 (Oct, Nov, Dec) 2022 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY

7 Diversification strategies beyond 2023 Rene Gonzalez

9 ptq&a

23 Biogas to biomethane

Diego Di Domenico Pinto Hovyu B.V. Ralph H. Weiland Optimised Gas Treating, Inc.

29 High throughput experimentation meets chlorine chemistry Enrico Lorenz, Moritz Dahlinger, Tobias Zimmermann and Jean-Claude Adelbrecht hte GmbH Markus Frietsch Gasmet Technologies GmbH

37 Navigating environmental complexities at pace Ken Chlapik, Dominic Winch and Chris Murkin Johnson Matthey

43 Needle coke – overcoming quality challenges in a resurgent market Marcio Wagner da Silva Petrobras John Clark Coke Consulting Company 55 Future refinery complexes built using an integrated approach Amit Sarna and Sachin Srivastava KBC

63 Demystifying digital transformation Jason Maderic and Mike Howells Emerson

69 Rejuvenate profits and support sustainability with reused catalysts Ioan-Teodor Trotus and Jean-Claude Adelbrecht hte GmbH Michael Martinez and Guillaume Vincent Evonik 77 Considerations for repurposing a fuel-grade coker into a needle coker Karen Cais and Srini Srivatsan Wood plc

83 Fast response to urgent need for a wastewater solution Dominique Tassignon Mobile Water Services (MWS)

87 Economics of refining catalysts George Hoekstra Hoekstra Trading LLC 93 Design of sulphur recovery units Osama Bedair Consultant

101 Technology in Action

Cover Fluid Catalytic Cracking unit, UOP, Courtesy of UOP FCC Technology Services

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Vol 27 No 5 Q4 (Oct, Nov, Dec) 2022 ptq PETROLEUM TECHNOLOGY QUARTERLY

Diversification strategies beyond 2023

I n the current era of sustainability and transition to ‘green energy’, EIA reports of over 105.6 million bpd global refining capacity seem astonishing. In fact, Global Data estimates that worldwide crude distillation unit (CDU) capacity is projected to grow over 10% from 2022 to 2026. Some markets like California plan on banning gasoline-powered vehicles by 2035. Other markets like India and China are pushing on to higher gasoline production and petrochemical diversification. I t was reported by the IEA that several world-scale refining projects were sched - uled to be online by 2022 or 2023 in Asia and the Middle East. The projects include Al Zour, Kuwait – 615,000 bpd; Jieyang, China – 400,000 bpd; Jizan, Saudi Arabia – 400,000 bpd; Rongsheng Phase II, China – 400,000 bpd: Lianyungang, China – 320,000 bpd; Duqm, Oman – 230,000 bpd; and various other expansions and restarts. The complexity of the projects reflects strategic plans for chemical produc - tion while processing a wider variety of feedstocks. Targeting high margins revenue streams like polypropylene leads to the short- est time intervals between project launch and achievement of stable cash flow. But higher capital outlays are necessary for many instances due to tightening environ- mental standards (such as Scope 1 and Scope 2). North America, Europe, and other mature markets are on track to phase out hydrocarbon-based fuels to make way for electric vehicles (EVs), while other markets like China are on track to ‘ride the train both ways’. They are expanding distillate production (marine diesel, SAF) and high-octane gasoline production for high compression engines in vehicles (for their expand- ing middle class) while also dominating the global manufacture and exportation of EVs, batteries, and solar/wind-powered systems. Nonetheless, petrochemicals and plastics demand is benefiting markets in most regions, where most petrochemical production is consumed to manufacture plastics from olefins such as ethylene and propylene, and onto polyethylene (PE) and polypropylene (PP), respectively. M oreover, hydrocarbon processing facilities, including recently shut down refinery infrastructure, may fit well into the oil and gas industry’s ‘Plan B’. The plan is a de facto option for participating in pyrolysis oil production from the chemical recycling of plastic waste, providing feedstock for the PE (from ethylene) and PP (from propyl- ene) production pathway. Why, if this pathway is already open through the oil and gas value chain? Mandates like the EU Directive on Single-Use Plastics predicate mandatory recy- cled content in all plastics packaging and implement an extended producer respon- sibility scheme that makes plastics producers cover the cost of waste management and cleanup. Refining assets can play more than just a peripheral role in this emerging value chain. For example, in this issue’s Q&A section, Mitrajit Mukherjee, President, Exelus, said catalytic processing of plastics-rich waste streams in a hydrocracker is a preferred alternative. The advantage of using the hydrocracking approach is the ability to handle all types of plastic waste (including PVC and PS), which allows a wider variety of materials to be recycled. L ike challenges with reconfiguring process assets for renewable feedstock pro - cessing, assessing plastic waste-derived feedstock qualities, contaminants, and processing options is still at an early stage. Refiners may have a narrow window to acquire financing from sustainability-focused investors to invest in pretreatment facilities or explore partnerships with third-party entities to supply pretreated plastic waste-derived feeds, to be discussed in future 2023 issues of PTQ .

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PTQ Q4 2022

www.digitalrefining.com

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

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

Q In view of the recent wave of refinery closures, includ - ing five in the US during 2021 and other closings, what technologies and market strategies are emerging to keep plants operating? A Scott Sayles, Manager Renewables and Alternate Feeds, ssayles@becht.com, Mel Larson, Manager Strategic Consulting, mlarson@becht.com, Robert Ohmes, Division Manager Strategic Business Planning, rohmes@becht. com, Becht: US capacity lost by refinery shutdowns or conversions will approach 1.5 MMBPD by 2024. Capacity increases in Asia will exceed these closure capacities, as well as planned clo - sures/conversions in the EU market. For those assets that have been repurposed, their focus is on producing renew - able diesel and/or sustainable aviation fuel (SAF) blend - stock, often at a lower capacity. Hence, the product mix is shifted more towards distillate fuel products plus renewable co-products and away from traditional transportation fuels and byproducts. From a market strategy perspective, remaining refiners are concentrating on several possible scenarios. The first strategy is to focus on their existing operation and con - figuration to continue to produce transportation fuels and petrochemicals and delay decisions on energy transition- related investments. For those entities, maintaining safe and reliable operation is at the forefront. Hence, their focus from a technology perspective is to bring to bear advanced ana - lytics and decision-making tools and processes to ensure the asset meets reliability targets while achieving produc - tion requirements. Operating companies are applying artificial intelligence (AI) and machine learning (ML) techniques to ‘bad actor’ pieces of equipment to help address root cause failures and meet on-stream availability. Other entities are examining ways to improve their crude/feedstock selection process by enhancing their entire crude decision-making work process throughout the value chain by streamlining data flows, analysis, and decision rights across planning, sched - uling, trading, operations, maintenance, and engineering organisations. Advancements in predictive models for understanding sulphidic corrosion (via Becht’s CorrExpert tool) and stream compatibility (via Becht’s Stream Compatibility tool) are available to help expand, narrow, and/or clarify the potential crude blends that are processed in a facility and adding this layer of analysis within the current crude selection and pro - cessing process. Fundamentally, these refiners are focusing on maximising margin within the existing assets to generate cash for potential future transformations of their business. The second strategy involved the active pursuit of proj - ects and investments in the energy transition. For many of the ‘closed’ refineries in the US, these assets are in the process of or have been converted and reconfigured into

renewable feedstock processing service. Though many sites have much of the hydroprocessing and utility infra - structure for such a conversion, we are observing that many sites are being challenged by the ability to secure sufficient feedstock to operate a technically and economically viable asset. Hence, refiners are already examining more challeng - ing waste feeds, such as used cooking oil (UCO) and animal fats (Categories 1, 2, and 3). A key focus is on understanding feedstock qualities, con - taminants, and downstream processing requirements, such that many entities are either building their own pretreat - ment facilities or going into partnerships with third-party entities to provide pretreated feeds. Though pretreatment technology has existed for many years within the food and waste processing industries, these are relatively new tech - nologies for refiners and require an expansion of knowledge and capabilities within their organisation to ensure the pre - treatment asset is properly designed and operated to meet up with a more traditional refining asset. Other refiners are examining ways to decarbonise through reduction of their energy requirements as well as investment in external renewable power production and carbon capture. Still others are taking a very long-term perspective and examining the processing of used plastics and novel bio - mass feedstocks to decarbonise their products further, all of which involve a combination of known and new/novel technologies. Given the number of options available, along with technology, market, and operating risks, a holistic anal - ysis early in the project cycle is critical to define the right investment pathway and clarify the market and regulatory incentives to monetise the investment. For these refiners, a careful balance must be struck between engaging internal resources in investigating these longer-term opportunities and ensuring their existing assets meet safe, reliable, and profitable operation to generate the funding needed for energy transition efforts. A Ioan-Teodor Trotus, Segment Lead Hydroprocessing, Custom R&D Solutions, hte GmbH, ioan-teodor.trotus@ hte-company.de: Refinery closures are by no means a sign that the need for refined products is doomed to disappear. More likely, closures are related either to regional factors that make it difficult to ensure profitable operation or to a lack of flex - ibility and diversity in the product slate of those refineries. Refineries capable of switching from mainly producing fuels to increased production of petrochemicals are very likely to remain profitable for years to come. Lubes production can also be a significant source of profit for refineries. Also, refineries which produce renewable diesel or sustainable aviation fuel should be able to navigate themselves in a position to charge a premium for these products over fossil- derived diesel and jet fuels. One must balance cost and revenue to be profitable, and

PTQ Q4 2022

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cost minimisation is the easy, safe bet. However, saving in the wrong place can be very costly in the long run. With the need for increased flexibility in feedstocks being used and operating conditions applied, the number of variable risk factors to be considered in unit operations can easily become too large to model reliably. One common feature of highly profitable refineries is that they perform laboratory tests to evaluate different operating scenarios on catalysts before running these scenarios in their units. Such tests can either be performed in the refineries’ own testing facilities or outsourced to third parties. hte GmbH offers highly parallelised test units for refiner - ies to accelerate their own testing capabilities, and hte also performs such tests for refineries that would outsource catalysts testing work. Performing a test before loading a new catalyst, before deciding whether to buy a fresh, new catalyst or use a reju- venated one, or before attempting to co-process a renew- able feedstock are just a few examples where experimental evidence can increase margins by tens of millions every year. A George Hoekstra, President, Hoekstra Trading LLC, George.hoekstra@hoekstratrading.com: According to American Fuel and Petrochemical Manufacturers, the US has lost 1.1 million barrels/day of refining capacity since early 2020, and other refineries are ‘on the bubble’. Valero’s CEO Joe Gorder, when asked in their April 2022 earnings conference call about the possible purchase of the Lyondell Houston refinery, sounded bearish, saying Valero’s experience in buying such assets indicates “it’s going to cost $3 billion to get it up to a Valero standard, and I look at it maybe that wasn’t exactly the best thing.” When I followed up and asked Valero’s Investors’ Relations whether the $3 billion was needed for safety, environmen - tal, reliability, or profitability improvement, they said it was for reliability and profitability. My research says refiners have been investing for safety, environmental, reliability, and diversification into other busi - nesses, but they have stopped investing in technology for the manufacture of conventional fuels for the US market. The sudden halt in conventional fuels refining investment was an abrupt change in investment strategy. According to EPA, 85 US refineries installed new FCC feed pretreaters or gasoline desulphurisers in 2000-2005 to meet the US Tier 2 clean gasoline sulfur standard, which was phased in from 2004-2006. That came immediately after a similar round of investments to meet the ultra-low sulphur clean diesel (ULSD) specification. Those investments in the first decade of this century did much more than merely comply with clean fuel specifications. In retrospect, they unquestionable paid off handsomely in higher profitability. But then investment in US fuels refining suddenly stopped. During the six-year phase-in for investment for Tier 3 gaso - line, 2014-2019, US refiners made almost none of the antic - ipated $3 billion+ capital investment that was understood by all to be needed. As a result, many US refineries today are producing less on-spec gasoline marketable in the US. In my opinion, to keep US refineries operating, profit - able, and healthy, we need an immediate reversal of this

sudden, unprecedented halt in investment in conventional fuels refining technology. Much is being made of the US losing 1 million barrels/day of crude refining capacity. But what about the record levels of US fuels exports to Mexico, Central and South America? According to a July 2022 detailed study, the US is exporting nearly 1 million barrels/ day of both gasoline and diesel to Mexico, Central and South America. Conventional wisdom says these fuel barrels are being exported because of global economics and because we cannot move them where they are needed in the US. But I wonder whether the gasoline barrels we are exporting even meet US clean fuels specifications? Regardless, unless we want our fuel supply to go the way of California’s electric grid, it is time for refiners to start investing again in fuels refining technology, starting with gasoline desulphurisation. A Kevin Clarke, Chief Strategy Officer, Imubit, k evin. clarke@imubit.com: Many refining facilities are actively considering/developing projects for the integration of renewable diesel into the flow scheme, driven by opportunities surrounding management and trading of RINs, as well as state and national govern - ment incentives, but also by growing demand for lower carbon content fuels. There is also emerging interest in using the refining complex as a green hydrogen production location or as a carbon capture and sequestration/reuse hub integrated with neighbouring energy-intensive industries. These ideas make sense because refiners have a licence to operate complex continuous process plant, often at high temperatures and pressures. They have infrastructure inbound power supply and distribution, water treatment facilities, inbound and outbound logistics and last but defi - nitely not least, a highly trained, safety-conscious work - force that will continue to be required in the future as the energy industry transitions towards low and zero-carbon operations. A Andy Howell, Executive Vice President Technology, KBC (A Yokogawa Company), Andy.Howell@kbc.global: Refineries have been under increasing pressure to increase profit margins while reducing carbon emissions. Global policies and regulations are being implemented to meet the Paris Agreement ‘zero-carbon road map’ that attempts to limit global surface temperature increases to 1.5°C by 2050. Furthermore, the rapid expansion of renewable and sustain - able energy sources such as wind, solar, and bio-energy are negatively shifting consumers’ perceptions of energy and chemical products, causing a transformation among tradi- tional energy sources. Due to the changing socio-technical landscape, mod- ern refineries have been able to diffuse niche innovations to fuel decarbonisation efforts and achieve Scope 1 and Scope 2 reductions. These innovative technologies include the development of carbon capture and storage, alternative energy supply, alternative feedstock, improved industrial processes, and waste heat usage. Following are several endogenous factors that can contribute to the success of these innovations:

PTQ Q4 2022

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Advanced software solutions: Process simulation and opti- misation software systems monitor and analyse the effect of different feedstocks and operating conditions while enhancing yield and thermal efficiency to help refineries transition from traditional fossil fuels to clean energy whilst improving margins. New business models: Traditional and new businesses such as refining, farming, and forestation are forming new alliances to restructure their knowledge base and supply chains to develop decarbonisation technologies with Scope 3 changes. Market formations: A growing number of private investors are transforming traditional refineries into renewable fuels producers to expand capacity and market share. Policy and advocacy coalitions: Lobbyists advocate on behalf of society for public policies that reduce hazardous air pollutants to improve air quality and promote public health. A Raj Patel, Senior Proposal Specialist, Haldor Topsoe A/S, rhp@topsoe.com: In the last two pandemic years, refinery closures have accounted for nearly 1 million bpd of refining capacity in the US. These refineries range in capacity from 50,000 bpsd to over 250,000 bpsd. The one market small and large refin - eries are considering and implementing is the production of renewable fuels (renewable diesel, sustainable aviation fuel, renewable naphtha). We have designed 6,000 bpsd to 50,000 bpsd renewable units in the smaller-to-intermediate size idle refineries, and more than one-third of the 350,000 bpsd total renewable processing capacity licensed by Topsoe come from idle refineries. Idle refiners are turning to renewable fuels to take advan - tage of the incentives offered by federal as well as state gov- ernments. These include Renewable Identification Numbers (RINs), Low Carbon Fuel Standard Credits (LCFS), Blenders Tax Credit, and Carbon Cap and Trade. These incentives can amount to more than $3/gal. For one of the idle refineries being revamped to renewable service using Topsoe tech- nology, these government incentives can be more than $5 million per day. Utilising an idle refinery for processing renewables is a natural fit. Compared to a standalone renewable facility, the idle refinery has a lot of equipment and facilities that can be utilised for renewable processing. A list of equipment and facilities that can be reused for renewable processing includes: • Rail, trucking, and marine facilities that can be used to bring feed into the refinery as well as send product out of the refinery • Existing facilities that can be used for required feed and product tankage • Utility facilities that can be reused in a renewables refinery • A hydrogen plant or method to bring in hydrogen, which is required for renewables processing • An existing sour water stripper and water treatment facility that can be reused for processing renewables, which will produce a significant amount of water in the chemical reaction • Pretreatment facility assets may or may not be required,

depending on the source of the feed, but some existing equipment can be utilised for this application • Sour off-gas treatment facilities, which may be wholly or partly reused in renewable service • Hydroprocessing units that can be revamped for renew- able service. Topsoe has utilised naphtha hydrotreaters, diesel hydrotreaters, FCC feed pretreaters, and hydrocrackers in idle refineries for renewable service. Converting an idle refinery to a renewable refinery is a natural fit. Q Considering the enormous amounts of thermal energy and stripping steam required for crude distillation unit (CDU) throughputs, are there any new crude oil process- ing schemes for reducing CDU operating costs? A Roberto Tomotaki, Becht, Heat Exchanger Advisor, Becht, rtomotaki@becht.com: Maintaining the crude preheat exchanger train at optimum performance. Third-party monitoring tools such as the proprietary HTRI SmartPM or Hexxcell’s Studio are two examples of industry available tools which help identify the exchanger(s) and optimum timing of the cleanings to opti - mise train performance. Once a cleaning decision has been made, the cleaning method is also very important. There have also been advancements in cleaning technology, such as ultrasonics and robotics, which return the exchangers to a rarely achieved near clean design condition. Becht’s Bundle Technology Upgrade (BTU) programme helps identify the bundle technology best suited for the current operation. Exchangers designed decades ago most likely are not the optimum design. Bundle design upgrades such as helical baffles or enhanced tubes can significantly increase the exchanger performance with relatively small incremental investment. This is especially applicable when replacing a bundle at the end of its life. A Sunil Kumar PhD, Principal Scientist, CSIR Indian Institute of Petroleum, sunilk@iip.res.in: It is reported that spirocyclic polymers with N-aryl bonds can fractionate light crude oil into light fractions consist- ing of molecules’ carbon number of 12 or a boiling point less than 200°C in the permeate and heavy molecules. The researchers say that, although additional research and development will be needed to advance this to an industrial scale, the new membrane could replace some conventional heat-based refining processes in the future by developing a hybrid energy-efficient technology consisting of membrane and distillation for crude oil refining (www.imperial.ac.uk/ news/199934/new-membrane-could-emissions-energy- refining/New membrane could cut emissions and energy use in oil refining). The application of a divided wall column (DWC) is also reported in one journal article for crude oil distillation to reduce energy consumption. However, the results have not been val - idated and compared with the actual industrial atmospheric and vacuum distillation unit (AVU) [Young Han Kim (2017): Energy Saving in a Crude Distillation Unit with a Divided Wall Column, Chemical Engineering Communications, DOI:

PTQ Q4 2022

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10.1080/00986445.2017.1379400]. CSIR-Indian Institute of Petroleum, Dehradun, has also developed a new crude oil processing method to reduce operating costs and GHG emissions. The similar topology of the developed method of an existing CDU ensures the implementation for revamping the existing and designing the grass-root. The techno-economic study using the commercial CDU configuration showed a potential to reduce the ADC bot - tom stripping steam by 80-100% and energy cost by 11-16%. The lower vapour flow rate in the section above the flash zone and higher flow rate in the stripping sec - tion provide the opportunity to increase throughput and address the poor vapour-liquid contact problem in the strip - ping section of the ADC [Kumar, Sunil, Avinash S. Mhetre, Comparative techno-economic evaluation of potential pro- cessing schemes for petroleum crude oil distillation, Results in Engineering (2022): 100480]. A Kevin Clarke, Chief Strategy Officer, Imubit, kevin. clarke@imubit.com: It has always been the case that the simplest way to cut your energy cost is to shut down the unit – obviously not a realistic approach, so the industry has focused on cut- ting energy costs by improving the efficiency of use for many decades. Many energy management and optimisa - tion systems evolved to support this process, but one area remained very hard to define: how do you know whether that last MMSCFD of fuel gas or last lb/hr of steam you con - served cost you more in unit yield recovery? Or, if you were to spend more energy, could you gain more economic value in throughput or yield recovery? And how does that change as the cost of carbon emissions increases? Offline simulation models have been built for many years, with engineers working tirelessly to try to understand this relationship, but the optimum is continuously changing with economics, feed rates, feed quality, and ambient conditions. Today, for the first time, enabled by advances in computer capabilities and artificial intelligence, the most forward- thinking refinery operators are using leading edge, deep reinforcement machine learning models to close this yield/ energy/emissions cost trade-off in real-time, in closed-loop. A Marcello Ferrara, Chairman, ITW Technologies, mferrara@itwtechnologies.com: The CDU is the most energy-intensive process in a refin - ery (also one of the largest in the whole process industry), with its performance affecting refinery-wide efficiency. Average CDU energy consumption is estimated to be over 192 TWh/y for US refineries (DOE, 2006). Among the CDU asset, the preheat train (PHT) is the most sensitive. If work - ing improperly, it will predicate a series of chain effects: extra CO₂ emissions, reduced flow, extra furnace fuel consump - tion, drop in furnace inlet temperature (FIT), production loss, and reduced throughput to the point that the refiner will shut down the fouled unit for equipment cleaning due to unsustainable fouling conditions. Formerly, Van Nostrand et al. (1981) estimated that pro- cess side fouling cost US refineries around $1.36 billion per year and $861 million due solely to PHT fouling. Currently,

these numbers, corrected for inflation and current energy costs, are superior by at least one order of magnitude. The fouling problem is so important that its mitigation in CDU operations could lead to over 15% fuel savings. As fuel con - sumption for the atmospheric column’s furnace represents around 4% of total refinery throughput, 15% fuel savings in a 500,000 bpd facility equates to more than $347 million in savings per year. Savings are even higher when considering that the car- bon tax can reach $80 per ton or more (depending on refin - ery location). ITW has developed and patented its Online Cleaning technology, which can clean an entire production unit on a 24-hour feed-out/feed-in basis. The technol - ogy will allow refineries to recover losses in one day while reducing emissions and eliminating waste. Online Cleaning technology helps target sustainability development goals (SDGs) while also serving as a tool to improve Operational Excellence, rather than an alternative to mechanical cleaning. A Jagannadh Sripada, Consultant, KBC (A Yokogawa Company), Jagannadh.Sripada@kbc.global: Due to the high-energy consumption of crude distillation units (CDU) and vacuum distillation units (VDU), energy reduction is essential to meet emission targets and reduce energy costs in the refining industry. Three key aspects of a new design or future revamp scenario(s) are as follows: Configuration Recent developments in progressive crude distillation methodology make it a viable process to be con - sidered during the design stage to potentially save utility and perhaps better yields. However, the initial Capex could be higher for such configurations, and the sensitivity of ben - efits on the type of crude should also be kept in mind. Depending on location and pricing, refineries should eval - uate their overhead vacuum configuration. Replacing the last stage of ejectors with liquid ring vacuum pump (LRVP) has been beneficial for refineries in the past, and the con - figuration is to be carefully evaluated and selected based on steam, cooling water and, electricity prices. Heat integration Optimising heat recovery from the preheat train via a revamp could include utilising spiral and plate and frame heat exchangers at select locations, adding extra heat transfer surface area to existing heat exchangers, installing new exchangers, and more. Process integration between CDU and VDU to save fuel, periodic re-evaluation of minimum approach temperature based on energy costs, and utilisation of pinch technology to identify opportunities should be beneficial to refineries. Monitoring heat exchanger fouling, online cleaning, and an optimised cleaning schedule will minimise fuel costs and emissions. Evaluating opportunities to utilise the product heat can include providing hot feed to downstream units or using that heat to preheat the crude at CDU. Distillation column optimisation Reduce the operating pressure of the atmospheric column during winters to ben - efit from lower temperature cooling water. APC can be used to automate the minimisation of pressure to great effect.

PTQ Q4 2022

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A Matthew Stephens, Senior Manager of Economic Engineering, Imubit, matthew.stephens@imubit.com: From a process optimisation perspective, we see other ways to optimise the yields of a hydrocracker aside from simply increasing conversion/severity in response to heavy feeds. In a VGO hydrocracker, profitability can be boosted at a fixed UCO yield by manipulating conversion between first and second stages. We have seen significant value in this approach without increasing conversion, and thereby a higher UCO flow can be maintained, keeping overall energy, fouling, and corrosion concerns at a lower level. Doing this, of course, requires a very accurate process model that can dynamically adjust to the varying feed quality and catalyst condition of the unit as well as market prices. A Marcello Ferrara, Chairman, ITW Technologies, mfer- rara@itwtechnologies.com: It is quite common for UCO heat exchangers to foul, given the highly waxy nature of the feed. Despite the operating solutions that can be found and developed on a case-by- case basis when trying to adjust a physical parameter, it should be noted that fouling deposition is not a physical matter and, by evidence, it will continue forming despite operating/equipment adjustments. Antifoulants can sometimes be used to mitigate this prob- lem, but they do not eliminate fouling deposition, and opera- tors frequently struggle to run until the next turnaround in a ‘run-to-death’ mode which involves losses. ITW Online Cleaning technology can solubilise UCO fouling using a tailor-made and proprietary chemical. The chemical is spe- cifically designed to dissolve and stabilise UCO fouling. An entire system can be cleaned in 24 hours on a feed-out/ feed-in basis. After Online Cleaning, the unit can immedi- ately resume production without the need for equipment opening and waste generation. A Dipankar Mitra, Senior Consultant, KBC (A Yokogawa Company), Dipankar.Mitra@kbc.global: In the current market that rewards efficient operations, many refiners are looking closely at furnace performance. In many cases, a detailed economic analysis based on yield gain and energy cost within emission limits is the appropriate, cost-effective approach to pursue. Typically, modern hydro- cracker units have proper heat integration with high furnace efficiencies and effective recovery of high-level heat. Therefore, increased conversion will likely result in less duty and emissions than upgrading lower-value heavy materials to distillates. While the increase in furnace outlet temperature directly affects fuel consumption and emis- sions, its effects extend much further. As cracking levels increase, hydrogen requirements and fractionation duties also increase. Even so, increasing conversion can be benefi- cial unless carbon costs are exceptionally high or upgrade margins are exceptionally low. To determine an appropri- ate conversion level, a comprehensive analysis should be completed. A key aspect of the hydrocracking process involves converting crude oil into valuable components, such as fuels, lubricants, and chemicals. In order to increase the

The latest high efficiency and low DP trays and the replacement of tray sections with packings usually help refiners increase throughput, but small gains in energy can also be achieved via such modifications. Q Increasing hydrocracker reactor heater temperature is a typical strategy when upgrading heavy feedstocks but should be balanced against higher energy costs and emissions considerations. Further complicating matters is fouling and corrosion of hydrocracker unit heat exchang- ers by unconverted oils (UCOs). What trends do you see in resolving increased fouling from UCOs? A Chad Perrott, Business Advisor, Albemarle Corporation, chad.perrott@albemarle.com: UCO heat exchanger fouling is common in conversion hydrocracking units with an insufficient purge. This leads to a build-up of heavy polynuclear aromatics (HPNAs). The HPNAs are most often associated with coronene and ovalene, which have a red/orange colour. These HPNAs are increasingly hard to convert when recycled through the hydrocracker because their ring count will typically increase. Historically, the only way to manage them was with increased purging of HPNAs to prevent additional con- densation reactions or the addition of adsorbents. Currently, bulk metal catalysts (BMC) such as the propri- etary Nebula or the proprietary Celestia are advanced for- mulations with up to 200% higher hydrodearomatisation (HDA) activity and hydrodesulphurisation (HDS) activity capable of saturating HPNA precursors like coronene and ovalene. Saturating these multi-ring aromatics can minimise fouling in hydrocracker UCO streams, leading to reduced UCO purge rates. In addition, overall reactor HDS and HDN activity will also increase because of the loaded BMC. Higher HDN activity results in lower reactor WABTs for equal nitrogen (N) slip to the hydrocracking catalyst. Lower hydrocracker pre-treat WABTs increase the cycle time spent in the kinetic aromatic saturation mode, thus avoiding the thermodynamically controlled regime where dehydrogenation is present and more HPNAs are produced. Therefore, the trend towards increased use of BMCs in hydrocrackers can increase profit- ability through less UCO purge and reliability through fewer fouling events. A Roberto Tomotaki, Becht, Heat Exchanger Advisor, Becht, rtomotaki@becht.com: For existing exchangers, the most immediate performance improvement is to clean them with the most effective cleaning methods. Advancements in cleaning technologies such as Ultrasonics and Thermal cleaning have allowed the return of the exchanger’s performance to near clean design conditions. Exchanger fouling can be reduced by redesigning the bundles with new technology. Becht’s Bundle Technology Upgrade (BTU) programme can help identify the bundle technology best suited for the service. Recent advance- ments in thin film antifouling exchanger coatings have led to reports of significant fouling reduction.

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A Ludo Boot, R&D Advisor, Albemarle Corporation, ludo. boot@albemarle.com: The answer to this question is very much dependent on the actual case at hand. The most applicable solution, whether pyrolysis or gasification, depends on many factors, one being capital investment. If a petrochemical company has certain assets in place, that may lead to using either pyroly- sis or gasification technologies. In terms of environmental impact analysis, LCA, GHG or GWP, there are studies showing a small advantage to one, some to another. Contaminants in waste-derived oils considered for a project can also differ, favouring either of the two technologies. These combined factors determine whether a pyrolysis or gasification technology application makes more sense for a certain case. Moreover, there may be enough space in the market for pyrolysis-based tech- nologies and gasification to co-exist in the future. A Scott Sayles, Manager of Renewable Fuels and Alternate Feeds, Becht, ssayles@becht.com: Pyrolysis is a promising technology to convert cellulous or plastic waste into an oil that allows processing into either fuels or petrochemical. Pyrolysis designs are varied depend- ing on the process basis. Some are nearing commercial operations, and others are in the pilot stage. The conversion of plastics into feedstock ready for the aromatic extractor tower to produce BTX is an example of pilot stage-level development showing some promise. The liquefaction of plastic using pyrolysis produces an oil that is the decompo- sition product of the plastic being introduced. To produce aromatics directly seems to require selective plastic pyrolysis. Gasification is a direct route, converting the plastic into a syngas which can be converted into BTX by Fischer-Tropsch, followed by cyclisation. The gasification of plastic is relatively new, but the conversion to desirable products is well proven commercial technology. Many fac- tors enter the final plans for plastic conversion into mar - ketable products. The technological risk is a key factor, as are the requirements to recover and collect the plastic from the community. The social-economic factors are difficult. Socially plastic recycling is favourable. However, capital investment and operational factors require a governmental position to ensure a future that will encourage investment. A Mitrajit Mukherjee, President, Exelus, mmukherjee@ exelusinc.com: Catalytic processing of plastics-rich waste streams in a hydrocracker is a preferred alternative. Compared to pyrol- ysis or catalytic cracking, it delivers a highly saturated liq- uid product that can be used directly without subsequent processing as a transportation fuel or fuel oil. There are five main types of recyclable plastics. Effective recycling of mixed plastics waste is a major challenge for the plastics recycling sector. The advantage of using the hydrocracking approach is the ability to handle all types of plastic waste (including PVC and PS), which allows a wider variety of materials to be recycled. To enable the use of plastics as a raw material, a suitable catalyst and optimum operating conditions are critical. One company,

hydrocracker conversion rate, the cracking bed tempera- ture of the unit can be increased, the nitrogen slip from the pretreat reactor can be reduced, or both can be done. Furthermore, reducing the nitrogen slip from the pretreat reactor will lead to fewer chances of forming incremental heavy polynuclear aromatics (HPNAs), which are known to foul process equipment and shorten catalyst life during con- version. While a variety of methods can be used to achieve high conversion, where each method offers a different yield/ economic impact, the rate of HPNA formation increases with higher conversion and heavier feedstocks. By recycling unconverted oils (UCO), HPNA formation and the per pass conversion are reduced for constant over- all conversion. Following are some of the ways industry can manage HPNA issues: • Limit feed FBP <600ºC, especially for HCGO (crack feed) • Monitor the UCO colour as it changes from white to yellow to orange to red as HPNA concentrations rise and increase bleed as much as possible • Use bulk metal pretreat catalysts to saturate/remove HPNA precursors • Saturate HPNAs by using superior hydrogenation func- tion catalysts in the second-stage cracking reactor • Employ hot, high-pressure separator design to avoid HPNA deposits on the reactor effluent air cooler (REAC), the main location where HPNAs cause problems • Adjust the unit design, such as installing liquid recycle filters, designing the separator with trays, and exporting unconverted oil with high HPNA content from the bottom while recycling material from the upper tray. A Ole Frej Alkilde, lead scientist, Haldor Topsoe A/S, ofc@topsoe.com: When the severity of a hydrocracking unit is increased by increasing the reactor temperatures and/or process- ing heavier feedstocks, the fouling tendency of the UCO increases, and ultimately the UCO can become unstable, and a solid phase will precipitate out. The reason for this is an increased content of HPNA. The conventional way to control the HPNAs is to limit overall conversion by draw- ing a UCO bleed stream from the unit, typically 2-5% of the feed rate to the unit. Other strategies are to reduce the reactor temperatures by using a more active hydrocracking catalyst, control the endpoint of the VGO feed to the hydrocracking unit, or revamp the unit by installing a hot separator, which removes the heavy product from the reactor effluent air cooler and thereby reduces the fouling. It is also possible to selectively remove HPNA by various industrially proven technologies like carbon bed absorption or advanced separation like Topsoe’s proprietary HPNA-Trim. This can reduce the UCO bleed rate from the unit by 60-80% and thereby increase overall conversion without reducing unit cycle length. Q Pyrolysis-based technology can convert plastics-rich refuse-derived fuel into extractor-ready BTX product, but the substantial energy input and processing challenges compel the petrochemical industry to consider waste gas- ification alternatives. How do you see this evolving?

PTQ Q4 2022

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