REFINING GAS PROCESSING PETROCHEMICALS ptq Q1 2023
VACUUM EJECTOR SYSTEMS
RECONFIGURING NAPHTHA SPLITTERS
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REVAMP TO THRIVE IN THE NEW REALITY
As you continue to navigate the global economic challenges that have impacted product demand, skewed feed slates, and put focus on the energy transition; it’s crucial to evaluate new and unique long- term solutions. At Shell Catalysts & Technologies, our solutions enable you to make smart investments while preserving cash through revamping, reconfiguring, or optimizing your existing assets. Our experts co-create tailored solutions for current units while keeping your margins in mind – ensuring the investments you make right now can help you maintain your competitive advantage into the future. Learn more at catalysts.shell.com/revamps
Q1 (Jan, Feb, Mar) 2023 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY
7 The dichotomy of refining Rene Gonzalez
16 Achieving Fit for 55 emission reduction targets by 2030 Fred Baars and Samiya Parvez Fluor B.V.
25 Design configurations for lowering quenched coke drum venting pressure Piotr Lorenc LOTOS Asfalt Keith Magdoza and Virendra Manral Chevron Lummus Global
29 De-mystifying vacuum ejector systems Scott Golden, Tony Barletta and Steve White Process Consulting Services, Inc.
39 Desalting chemistry and monitoring methods to help expand crude basket Mahesh Subramaniyam, Debjit Chandra, Vivek Srinivasan, Ajay Gupta and Hiten Makwana Dorf Ketal Chemicals 45 Kinetic model for TGU hydrogenation reactors: Part 1 – model development Michael A Huffmaster Independent Consultant Prashanth Chandran, Nathan A Hatcher, Daryl R Jensen and Ralph H Weiland Optimized Gas Treating, Inc. 51 Reduce emissions and improve refinery profitability J Mark Houdek, Pankaj K Singh, Srinivasan Ramanujam and Ian Clarke Honeywell UOP
59 Fouling in VDU ejector systems Jim Lines Graham Corporation
67 Reconfiguration of naphtha splitters using divided wall column technology Ratheesh S Bharat Petroleum Corporation Limited (BPCL) 71 Crude oil processing scheme for reducing operating costs in the CDU Sunil Kumar and Avinash Mhetre CSIR-Indian Institute of Petroleum 75 Value maximisation in FCC units using multispecialty catalyst formulation Somanath Kukade and Pramod Kumar Hindustan Petroleum Corporation Limited
81 Closing the sustainability cycle Marcio Wagner da Silva Petrobras
87 Universal filter for ultra-cleaning of reactor streams Fu-Ming Lee, Mark Zih-Yao Shen, Chi-Yao Chen, Maw-Tien Lee, Yin-Hsien Chen, John Lee and Stephen Yen Shin-Chuang Technology Co., Ltd. Kao-chih Ricky Hsu International Innotech, Inc .
97 To Claus or not to Claus?
Martin Taylor and Charles Kimtantas Bechtel Energy Technologies & Solutions, Inc.
Cover High-complexity hydrocarbon processing facility
©2023. The entire content of this publication is protected by copyright. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means – electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner. The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included in Petroleum Technology Quarterly and its supplements the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies.
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Vol 28 No 1 Q1 (Jan, Feb, Mar) 2023 ptq PETROLEUM TECHNOLOGY QUARTERLY
The dichotomy of refining
H igher refining margins are typically accompanied by debt-funded projects, which doesn’t seem to reflect the current business cycle, such as in mature markets, where the onus is on taking a conservative investment approach. This is driven by the transformation to non-fossil fuels, conflict in Ukraine, and other destabilising events changing market dynamics. Moreover, uncertainty over stable cash flows is exacerbated by high interest rates, supply disruptions, and regulations. Fitch Ratings (fitchratings.com) expects crack spreads for certain refiners to fall in 2023 from record high margins, such as along the US Gulf Coast. These declining crack spreads are influenced by expectations for weaker global economic growth and other related concerns, such as worries about a global food crisis, already seen in Africa, caused by severe shortages in fertiliser due to high natural gas prices. This uncertainty makes it difficult to attract capital, contributing to declining net refining capacity and product shortages, such as diesel. Nevertheless, major refinery projects in Asia and the Middle East explain why global refining capac - ity could continue increasing to 2035, including nine large active projects in the Middle East. Besides capacity and product diversity from fuels to polymers, these projects support sustainable objectives, as recently discussed at the Refining India 2022 conference in New Delhi and the ERTC 2022 in Berlin. Lowering emissions and energy costs and increasing profitability calls for a ‘re- balance’ of production capacity using the latest advances to existing technology involving crude distillation units, delayed coking units (DCUs), hydrocrackers, and FCCs. To meet these objectives, fired heater optimisation and separation efficiency continue to benefit from global technology suppliers partnering with niche repos - itories of expertise focused on specific areas (such as mass transfer efficiency, ceramic coatings applications, and neural network systems). How does this ben- efit traditional refinery units? Overall, reduced demand for fossil-based transportation fuels has resulted in DCUs operating at lower than design capacity. In parallel, the trend towards electric vehicles (EVs) has accelerated demand for synthetic graphite used in EV battery manufacturing, predicating the redesign of fuel-grade cokers to produce needle coke instead. Opportunities to co-process recycle waste plastics through a DCU further improve utilisation. Optimal performance of hydrocracking units is critical in pursuing refinery profit - ability, which benefits from the latest developments in zeolite-based catalyst to mitigate the chemistry of HPNA formation in two-stage hydrocracking units. As with other refinery conversion units, opportunities to process plastic waste-derived pyrolysis oil through the hydrocracker are emerging from the pilot plant stage. Besides high margins, petrochemical feedstocks, diesel, and sustainable aviation fuel (SAF) are crucial refinery products for the world’s economy, requiring technol - ogy capable of upgrading low-value streams like HCGO, HVGO, and DAO to distil- late range products, as large-scale commercial production of renewable diesel and SAF is still a long way off. Regardless of the project, an emerging consideration for refineries is to treat utilities such as water and hydrogen as scarce resources, as will be discussed in the Q2 2023 issue of PTQ . The dichotomy of refinery challenges and opportunities continues to play out. Even though investors in some major markets have put dividends and share buy - backs ahead of capacity gains over the past few years, other refiners are com - mitted to investing in the enormous opportunities in the petrochemical sector, as long-term global petrochemical consumption could increase by a factor of 9, against a backdrop of the sustainable refinery landscape.
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PTQ Q1 2023
Flexibility is profitable
tray vapor loads and internal liquid reflux rates. Keeping the upper pumparounds loaded can also help avoid low pumparound return or tower overhead temperatures that condense water and cause salting or corrosion problems. It may even make sense to turn off a lower pumparound. L ONG - TERM SOLUTIONS inking longer-term, cost-effective revamps can add critical flexibility to allow for wide swings in unit throughput and crude blends while still operating in control. e right process design enables operators to consistently:
In uncertain times, refineries can maximize profit (or at least minimize loss) through flexible operations. Crude units are the first link in the refinery processing chain, and making large changes in crude diet or throughput stresses even the most state-of-the-art unit. S HORT - TERM STRATEGIES Certain operating strategies can maximize reliability, yields, and product qualities. Some practical short- term options include: • K EEP THE BOTTOMS STRIPPING STEAM
At turndown, consider maintaining normal crude tower and vacuum tower bottoms stripping steam rates and lowering heater outlet temperature to control cutpoint. is allows the stripping steam to do the work while heater firing is minimized to protect the heater tubes at low mass velocities. L OWER THE PRESSURE Lowering tower pressures at turndown lowers the density of the vapor, which keeps trays loaded and can avoid weeping and loss of efficiency. Lower pressure also lowers draw temperatures, increasing pumparound rates and hopefully avoiding minimum flow limits for pumps and tower internals. M OVE HEAT UP In multi-pumparound towers, shifting heat to the upper pumparounds at turndown increases
Control desalter inlet temperature,
• Control preflash column inlet temperature and naphtha production, • Control pumparound return temperatures and rates independent of pumparound heat removal requirements, and • Precisely control vacuum column top pressure. is advice is, of course, generic. To discuss challenges unique to your own crude/vacuum unit, give us a call. Process Consulting Services believes crude units should have flexibility. We believe that revamp solutions should be flexible too - one size doesn’t fit all. We look forward to working together to find the most cost-effective and reliable solution to your crude processing problems.
3400 Bissonnet St. Suite 130 Houston, TX 77005, USA
+1 (713) 665-7046 firstname.lastname@example.org www.revamps.com
More answers to these questions can be found at www.digitalrefining.com/qanda
Q How can the refining industry supply the aviation industry’s growing demand for sustainable aviation fuel (SAF)? What are the most efficient pathways? A Yvon Bernard, Renewables Product Line Business Development Manager, Axens, Yvon.BERNARD@axens. net Today, governmental authorities, refining companies, and the aviation industry are collectively exploring differ - ent technology pathways to substitute fossil-based jet fuels with SAF. A single solution will not fulfil future SAF demand. Rather, a combination of different technologies for every available feedstock around the world is required. Among the seven pathways currently certified under the ASTM D-7566 specification for synthetic kerosene to be blended into Jet A1 pool, Axens provides mature tech - nology for three main pathways (HEFA-SPK, FT-SPK, ATJ- SPK) via the following solutions: • Vegan, the hydroprocessed esters and fatty acids (HEFA- SPK) pathway. This is a flexible solution to produce renew - able diesel and SAF through the hydrotreatment of a wide range of lipids (renewable vegetable oils and animal fats). • Gasel, the Fischer-Tropsch (FT-SPK) pathway, converts synthesis gas (H₂+CO) from various origins into a flex - ible slate of lower carbon fuels, including SAF. To provide renewable synthetic gases from biomass, Axens developed BioTfueL, which unlocks SAF and advanced biofuels pro - duction from energy crops and agricultural and forestry res - idues via a thermochemical and Fischer-Tropsch pathway. • Jetanol, the ethanol-to-jet pathway (ATJ-SPK), is the pro - cess by which low-carbon ethanol is converted to SAF via different steps: dehydration, oligomerisation, hydrogena - tion, and fractionation. Axens also provides a solution combining Futurol and Jetanol to produce renewable fuels. Futurol uses enzymatic conversion to produce advanced ethanol (2G) from ligno - cellulosic biomass (energy crops, agricultural and forestry residues). The common threads running through these technolo - gies are flexibility, reliability, and the realisation of decades of technology development, demonstrating that Axens is ready to meet the challenges of scaling up SAF capacity in the coming years to provide low-carbon fuels into the market. Q Projected diesel shortages could become a crisis if winter conditions are severe, potentially knocking out already strained power grids. What strategies should refiners rely on to increase distillate-range material? A Michael Allegro, Technical Services Specialist, BASF, email@example.com Sites with both hydrocracking and FCC can shift the VGO feed towards hydrocracking when distillate material is
preferred over gasoline. While this can reduce the operat - ing capacity of the FCC, it can also create a need to process UCO from the hydrocracker. In these operating modes, bottoms upgrading capability in the FCC is a key need for the refiner. Those units would also likely benefit from a more distillate-focused operating mode for the FCC and, depending on the duration, a catalyst tuned to produce more LCO. A Joris Mertens, Principal Consultant, KBC (A Yokogawa Company), joris.mertens@kbcglobal The availability of electrical power in January/February 2023 causes concern throughout Europe. However, in Europe, where mid-distillates generate very little power, power availability concerns are not driven by a shortage of diesel but rather by a potential lack of natural gas. The absence of a substantial part of the nuclear power gen - eration park in France further exacerbates this situation. Despite this, diesel is in short supply because of the self- imposed reduced distillate supply from Russia. The ability of refineries to switch from naphtha to diesel is limited by the facility’s design. Arbitrage, trading, and international groups are better positioned to capitalise on soaring diesel prices. In addition, it is well known that refiners can maximise diesel produc - tion in the short term, primarily by adjusting fractionator cut points. This option should be built into the refinery LP and site operational optimisation procedures. Severity reduc - tions on cat and hydrocrackers shift product selectivity from lighter to middle distillate products. However, they risk reducing the yield of high-value products (FCC light olefins) or increasing lower-value residuals (on the hydrocrackers). As a result, KBC observed through performance improve - ment studies that refiners often leave money on the table due to a variety of very technical (such as failing advanced control), communicative, and organisational issues (such as inadequate data collection and monitoring, or poor shift team handover). Meanwhile, investing significant capital to maximise die - sel yield is probably not worth consideration. In spite of soaring diesel prices, the surge of hybrid and fully electric vehicles should not be ignored. The shortage of diesel will probably not persist long term. A Mel Larson, Manager, Strategic Business, Becht, mlar- firstname.lastname@example.org There are three major steps around the FCC: Minimise diesel in FCC feed through better fractionation monitoring Maximise C/O at lower riser temperature Lower cutpoint of naphtha into LCO. The challenge here is that more LCO will add severity and demand to the exist - ing DHT system and, thus, possibly shorten catalyst run length. The economics of the shifts need close analysis.
PTQ Q1 2023
Q Do you see growing investor interest in process- ing plastic waste-derived pyrolysis oil through refinery assets, such as hydrocrackers? Against this backdrop, how prepared are refiners to invest in contaminants removal systems (for pretreatment of the pyrolysis oils)? A Michael Allegro, Technical Services Specialist, BASF, email@example.com Advanced plastic recycling is becoming an important part of many long-term refinery strategies. One key consider - ation is how the legislation will pan out. Will plastics-to- fuel be an economical route, or is full plastics circularity the end goal? With many refineries configured to maximise transporta - tion fuel products, the yield of plastic precursors on a lb- per-lb basis of waste plastics may not be high enough to meet the circularity targets likely to be mandated. However, if fuels produced from waste plastic oils can qualify for renewable credit, the conversation about utilising refinery assets becomes much more attractive. Contaminant removal is a major challenge for refiners considering processing plastic pyrolysis oils (pyoils). Aside from the associated Capex, these systems may come with unique maintenance requirements, large plot spaces, high Opex, and new environmental impacts that refineries are not prepared to bring inside their battery limits. Additionally, there is uncertainty about waste availabil- ity, which could require refiners to purchase from multiple sources. This can lead to increased variability in pyoil qual - ity, which could make investing in the appropriate contami - nant removal systems more complicated. A Fu-Ming Lee, Maw-Tien Lee, and Tzong-Bin Lin, all Senior Consultants, Shin-Chuang Technology, and Ricky Hsu, Founder, International Innotech, Inc., ricky_hsu@ msn.com Interest is growing in converting waste plastics, including PE, PP, PS, PET, ABS, and PVC, into pyrolysis oil through steam cracking, cat cracking, or hydrocracking. However, several problems are encountered: Lack of pretreatment systems for removing heavy metal contaminants from the feed, such as lead, nickel, zinc, cop - per, chromium, antimony, and barium (from additives to the plastics), to protect cat cracking or hydrocracking catalysts. Reactor plugging problems (we observed a commercial demo plant shut down in 30 days due to plugging). Pyrolysis oil rich in aromatics or olefins is low in cetane number and unsuitable for diesel fuel (but for lower-grade fuel oils). The magnetically induced Universal Filter (developed and commercially demonstrated by Shin-Chuang Technology in Taiwan) may remove heavy metals and solid particles (down to nanometer sizes) in the feed stream to protect the reactor catalysts. (Refer to US patent 9,352,331). Alternatively, instead of converting waste plastics into pyrolysis oil, Shin-Chuang Technology has commercially incorporated waste tyre rubber and waste plastics into the huge worldwide specialty cement and concrete mar- kets with very low processing costs (no chemical reactor,
no heating, no pressurising, no cooling, and no CO2 or gas emissions). Plastics, including PE, PP, PS, as well as butyl rubber (tyres) are hydrophobic, so mixing them with hydrophilic cementitious materials forms a loose mixture with very weak strength. The strength of the cement matrix required as the construction material is from the hydrates produced through hydration of cement and water. However, typical cementitious material cannot stop water from damaging its internal structures. Over the years, people have tried all kinds of methods to incorporate polar plastics such as PVA or non-polar plastics such as PP fibre into the cement- matrix composite (CMC) to improve the hydrophobic capa - bility of cement and concrete without satisfactory results. The novel method disclosed in US patent 10,882,785B1 issued to Shin-Chuang Technology is to disperse the hydrophobic waste plastic or rubber particles as carriers of the hydrophobic agent uniformly throughout the cement matrix by improving the surface property of the particles. Hydration occurs in the cement matrix without disturbance. After hydration, the CMC becomes hydrophobic with mini - mal strength loss. For example, after hydration, the ‘hydro - phobic’ cement mortar containing 4 wt% waste tyre rubber exhibits higher than 95% compression strength compared to that of ‘hydrophilic’ mortar containing no rubber. An SEM image of the hydrate of the CMC showed tight and uniform C-S-H bonding to confirm the high compression strength. Also, gaps in the CMC are hydrophobic, and the water contact angle in the gaps is too large to allow film flow of the water, so water cannot pass through. However, mois - ture can get through freely, making this CMC a hydro - phobic but breathable construction material. The product is successfully commercialised with references available. Furthermore, the CMC provides a much-improved sound (noise) barrier and heat insulation than regular cement or concrete. A Joris Mertens, Principal Consultant, KBC (A Yokogawa Company), joris.mertens@kbcglobal Yes, we see a growing interest in waste plastic pyrolysis and, consequently, in processing technology for the waste plastic pyrolysis oil (WPPO) product. Refiners are better prepared to handle WPPO in that they are familiar with hydrotreating technology, which is central to WPPO clean - ing technology. Besides knowing how to start, run, and shut down these units, refiners are familiar with handling catalysts and have the necessary hydrogen to run them. On the other hand, treating WPPO requires consideration of other factors. First is unit size. Both the treating technology and pyroly - sis represent emerging technologies. The first industrial units coming online are tiny by refinery standards, with feed rates lower than 10 m3/h (below 1.5 kBPD). Sizes of the treating units are set primarily by availability of the WPPO feed rather than by technical constraints. Therefore, hydrogen availability is unlikely to be a major constraint despite the high specific hydrogen consumption. Although a simplified block flow diagram will look similar to that of a hydrocracker, KBC expects most of these units will be
PTQ Q1 2023
END-TO-END SOLUTIONS FOR MAXIMIZING THE PRODUCTION OF PETROCHEMICALS FROM CRUDE OIL
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grassroots projects rather than revamps of existing units because of their size difference. For the same reason, the possibility of repurposing existing facilities to construct a WPPO cleaning/conversion facility will be limited. Despite the small size of the contaminant/treatment unit, the variability and (un)availability of the WPPO feedstock could pose a significant operational concern. The waste plastic source will strongly influence unit performance, with some generating olefinic paraffins and others pro - ducing aromatic products, which may be less suitable for certain applications (such as ethylene cracking). Therefore, the refiner should be well aware of both the quality of the WPPO and the risk of disruptions in supply. Q Is it possible that refiners could be overlooking some practical solutions to increasing FCC olefins yields, such as in the gas plant/recovery section? A Michael Allegro, Technical Services Specialist, BASF, Michael.firstname.lastname@example.org For C 3 s, propylene splitters are well-established solutions that most units concerned with C 3 = recovery have likely investigated. For C 4s, most units interested in olefin recov - ery have at least conducted a paper study to determine if a separations solution would be economical. An opportunity for optimisation could be for customers to pay closer atten- tion to ‘lost’ olefins. A potential opportunity for further recovery efforts could be that of ethylene. Many feel that FCCs do not produce enough C 2 = for it to be worth recovering. A future shift in product economics could lead to more attention being paid to fuel gas olefinicity. A Bani Cipriano, Segment Marketing Manager, Light Olefins email@example.com and Stephen Amalraj, Principal Technologist, firstname.lastname@example.org, W. R. Grace The yield of light olefins from the FCC can be increased by optimising different FCC process variables, including riser operating temperature (ROT), injection of ZSM-5 addi - tives, hydrocarbon partial pressure, and the recycle of light naphtha, C 4 or oligomer streams into the FCC. Increasing the yield of light olefins increases the load on the wet gas compressor (WGC) and the gas plant. The FCC unit can realise maximum value within unit con - straints by optimising the appropriate variables, and it is important not to overlook catalytic solutions to these con- straints. For example, by increasing the yield of light olefins via ZSM-5 additives versus ROT increase, it is possible to make more light olefins per unit of dry gas production and, The yield of light olefins from the FCC can be increased by optimising different FCC process variables
therefore, for a given unit limitation on the WGC and the gas plant. Furthermore, in high metals applications, using an appropriate coke-selective catalyst with metals trapping functionality can result in lower H 2 make, which further offloads the WGC and gas plant. In both cases, an increase in recovery of light olefins is enabled. As the cost of pro - pylene production from the FCC is lower than other pro- pylene production routes, the use of catalytic solutions or minor revamps to overcome the gas plant handling capac- ity are effective ways of realising the maximum value from the FCC. A Mel Larson, Manager, Strategic Business, Becht, mlar - email@example.com This is a compound question of FCC yield and recovery. On the yield front, most units are bounded by the wet gas compressor and subsequent recovery capacity. The value and recovery of olefins are regionally specific. In the US, the difference depends on economical access to chemi- cal infrastructure for propylene vs alkylation. The US Gulf Coast has been maximising recovery within existing hard- ware and cooling limits for decades. It is the opposite in the EU market, as LNG prices have been driving plants to fuel more LPG, be it saturates or olefins. One major in the EU stated it had reduced LNG demand by 40% by fuelling LPG components. Thus ultimately, the issue is the value of olefin processing, including petrochemicals, alkylation, and/ or cat poly plant (there are a few left), and it is not a one-size-fits- all solution. Q Under what conditions do you see opportunities with the upgradation of distressed refinery products (such as vacuum resid) to higher value outlets? Are these oppor - tunities primarily outside the fuels market? A Fu-Ming Lee, Maw-Tien Lee, and Tzong-Bin Lin, all Senior Consultants, Shin-Chuang Technology, and Ricky Hsu, Founder, International Innotech, Inc., ricky_hsu@ msn.com A supercritical solvent extraction process combining an anti-solvent with multicomponent phase equilibria is suc - cessfully used to separate oil and asphaltenes in vacuum resid commercially. The supercritical or near-critical solvent used in the process exhibits key favourable characteristics for separating asphaltenes from residue: Unique solvent behaviour, vapour density, and diffusiv - ity, which enhance asphalt phase separation. Facilitated turbulent mixing of petroleum feedstock and solvent, which enhances mass transfer. ( Refer to: Chung, W., et al, Asphaltene removal technology produces novel cement water- proofing additive, Hydrocarbon Processing , Sep 2021 ). Upon removal of the asphaltene portion, the process produces a high yield of deasphalted, decontaminated, and decarbonised oil suitable for conventional packed-bed hydroprocessing. The novelty of the proprietary process is its unique ability to produce solid, easy-to-handle, virgin, granular asphaltenes, which can be applied to a variety of new uses and allow for the further diversification of the
PTQ Q1 2023
Turn iron into gold? Alchemy? No. It’s chemistry.
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petroleum sector. The utilisation of asphaltenes in non- combustible ways will be critical for the long-term viability of the green petroleum sector and provides an immediate opportunity for achieving a 10-20% carbon emissions reduction from the status quo. A hydrophobic CMC through the incorporation of 0.2 wt% asphaltenes into Taiwan cement Type 1 with stan- dard sand and water (‘asphalted mortar’) was successfully demonstrated. The advantage of the hydrophobic CMC is that the cement, and by extension the concrete, becomes inherently water-resistant. Furthermore, inherently the water-resistant CMC is mould-preventative. Properties of the newly formulated asphalted mortar complied with CNS 3763-2009 requirements, indicating that asphaltenes are appropriate cement waterproofing agents. A Mel Larson, Manager, Strategic Business, Becht, mlar- firstname.lastname@example.org There is not much pure vac residua in the market. It is more likely a blended high-sulphur fuel oil (HSFO), which has die- sel to blend the API. The opportunity is to fill delayed cok - ing capacity with HSFO while optimising other conventional oils. The market differential between very low sulphur fuel oil (VLSFO) and HSFO is between 200 to 300 $/mt or (30 to 40 $/bbl), thus if there is sulphur/hydrogen plant capacity, processing HSFO could be a very attractive opportunity. Q With the ‘CO 2 -to-methanol route’ gaining more inter- est, what emerging technology do you see accelerating this interest? A Joris Mertens, Principal Consultant, KBC (A Yokogawa Company), joris.mertens@kbcglobal For CO 2 -to-methanol, the primary accelerator will not be technical but rather a market pricing strategy based on the carbon intensity of the methanol product. In brief, ‘green’ methanol needs a higher price. The International Maritime Organization (IMO) has set a 50% emission reduction tar- get for shipping that will require the use of low-carbon fuels. In addition to being more technically mature, the e-methanol and bio-methanol paths are easier to apply to existing shipping infrastructure. In their energy transition outlook, DNV predicts e-methanol demand for bunkering will reach 360 and 1800 PJ in 2030 and 2050, respectively, which corresponds with 18 and 90 million tonnes per year. Regulations are crucial, with technical developments important as well. On the one hand, renewable electric- ity and the development of electrolyser technology can reduce hydrogen costs. On the other hand, the well-estab- lished methanol synthesis technology needs to be further E-methanol technology will evolve faster if stable and selective catalysts tailored to CO 2 /H 2 feeds are developed
developed, particularly the methanol synthesis catalyst. Conventional methanol synthesis uses a syngas mixture rich in CO, not CO 2 . E-methanol technology will evolve faster if stable and selective catalysts tailored to CO 2 /H 2 feeds are developed. They will reduce the yield of lower value by-products, as well as the capital cost (for example, reactor size) and operating cost (for example, reduced recy- cling of unconverted product). Reducing operating costs will reduce the carbon intensity of the process, which may further increase the product value. The final parameters in the equation are the price and availability of CO 2 , which will be determined both by regu- lations and cost reductions through further technological developments. CO 2 captured from large point sources is likely to be used over the short and medium terms as it will become more readily available at lower costs. Ultimately, however, CO 2 from direct air capture should be the pre- ferred CO 2 source. A Troels Juel Friis-Christensen, Technology Manager, Topsoe, email@example.com Green methanol produced by biogenic CO 2 and hydrogen from electrolysis powered by renewable energy is one of the possible solutions for decarbonising the maritime sec- tor. Demand for green methanol is therefore predicted to increase significantly in the future. Conversion of CO2 into methanol changes the chemical processing conditions for the methanol catalyst. The concentration of water and CO 2 is much higher than that of a traditional operation. Based on Topsoe’s knowledge of copper-based metha- nol catalysts and years of experience within CO 2 utilisa- tion for the production of methanol, Topsoe has developed MK-317 Sustain, which can achieve a high and stable con- version rate over a long period of time. The dependency on fluctuating renewable energy for the generation of hydrogen requires a robust plant design with the ability to change load fast and frequently, and with extended turn- down requirements. Topsoe’s eMethanol process provides the required flexibility in a simple and efficient solution by combining a methanol catalyst with a reliable and proven process design. A Pattabhi Raman Narayanan, Manager, Strategic Business, Becht, firstname.lastname@example.org Methanol synthesis is a mature technology. The feed- stock is typically a mixture of CO 2 , CO, and hydrogen, and catalysts are mainly based on copper or copper/zinc oxide. Technology development is underway to tune them towards the different requirements of CO 2 conversion driven by global climate change. There are two pathways for converting CO 2 into methanol. One is to reduce CO 2 to carbon monoxide (CO) and then reduce CO with hydrogen to make methanol. The second is the direct hydrogenation of CO 2 with hydrogen over a heterogeneous catalyst. In the first pathway, the reverse water gas shift (RWGS) reaction is receiving increased attention as a method for converting CO 2 into syngas using renewable hydrogen. RWGS is attractive as it allows existing, high technology readiness level (TRL) processes to be run in two steps from
PTQ Q1 2023
CO 2 . The key issues are selectivity to methane, carbon lay-down, and the high temperatures needed to drive the reaction forward, and they are being addressed at present. Also, a range of catalysts is being evaluated. Many of these are based on copper, but iron, nickel, platinum, and molyb- denum carbide catalysts are also under investigation. In light of the challenges to develop a commercialised RWGS process, other methods for activation of CO 2 to CO such as electrochemistry or photo-chemistry are interesting. The George Olah methanol plant in Iceland, commissioned in 2011, follows the second method. The production unit captures CO 2 from flue gas released by an adjacent geo - thermal power plant, which is purified to make it suitable for downstream methanol synthesis. Following adequate compression, synthesis gas containing green hydrogen generated by electrolysis of water and CO 2 is catalytically reacted to form methanol. Direct CO 2 hydrogenation to produce methanol is licensed by several leading companies. Recently, China made great progress in employing copper-based and oxide catalyst systems. Also, a novel technique for converting CO 2 to methanol was recently created at TU Wien (Vienna). Liquid methanol is formed from CO 2 with the aid of a unique cata- lyst material consisting of sulphur and molybdenum. The new technology has already been patented, and now it must be ramped up to industrial size in collaboration with business partners. Increasingly abundant low-cost renewable electricity
enabled electrochemical processes to compete with tra- ditional thermocatalysis methods. The George Olah plant mentioned above couples the hydrogen through electrolysis with thermocatalysis to produce methanol. The availability of electrolysis at the scale needed to supply hydrogen to methanol plants is a key challenge, and significant efforts are being made to scale up electrolysers. Also, the high- temperature electrolysis to produce CO and syngas using solid oxide electrolyser cell (SOEC) systems could be advantageous if coupled with thermochemical processes to reduce heating cycles. However, SOECs cannot reduce CO 2 directly to other hydrocarbons and oxygenates, unlike low-temperature electrolysis. Methanol synthesis from CO 2 over heterogeneous cata- lysts suffers from several shortcomings, such as harsh operating conditions like high pressure and temperature. Also, CO 2 thermocatalytic hydrogenation is limited by thermodynamics, and continuous separation of methanol from CO 2 and by-products is necessary for the recirculating process. Several alternatives for CO 2 reduction to methanol have emerged in recent years involving homogeneous, enzymatic catalysis, photocatalysis, and electrocatalysis. Advantages of these emerging processes include tem- perature lower than in heterogeneous catalysis, alternative sources of energy (light or electricity) use, and potentially higher methanol selectivity. In some alternatives, water is used for CO 2 reduction instead of costly green hydrogen.
PTQ Q1 2023
Achieving Fit for 55 emission reduction targets by 2030
Options available to oil refineries in reducing CO 2 emissions while providing a clearer vision on possible roadmaps
Fred Baars and Samiya Parvez Fluor B.V.
Emissions reduction protocols Numerous governments and companies around the world have committed to reducing their CO₂ footprint to ultimately achieve net-zero emissions. The European Commission (EC) has set a target to reduce CO₂ emissions by 55% by 2030 (relative to 1990) with a 2050 ‘net-zero’ target. CO₂ emissions are generally classified as Scope 1, 2 or 3. The Green House Gas protocol 1 refers to Scope 1-3 emis - sions for greenhouse gases in general. For the purposes of this discussion, only CO2 emissions are considered. As far as oil refineries are concerned, Scope 1 emissions relate to the amount of CO₂ that a refinery emits to produce saleable products. Scope 2 are the emissions related to the imported utilities that the refinery consumes, while Scope 3 emis - sions result from all the goods/services that the refinery purchases, sells, or disposes of. Oil refinery Scope 1 CO₂ emissions result from the burn - ing of refinery fuel (fuel gas and or natural gas) or from cer - tain processes such as hydrogen manufacturing via steam methane reforming (SMR). CO₂ emissions can be reduced by improving the energy efficiency of various process units, by replacing refinery fuels (natural gas, electricity), by CO₂
neutral sources such as green electricity or green hydro - gen (fuel substitution), by replacing crude oil feedstock, for example with vegetable oil or mixed plastic waste (MPW, feedstock substitution), or by capturing CO₂ from process streams and/or stacks and utilising or storing the CO₂. Fuel substitution also includes 'electrification' such as switching gas/steam turbines to electric motors and using e-boilers/ furnaces. Some measures may only affect the Scope 1 emissions, while others may impact Scope 1, 2 and 3 emis - sions shown in Table 1 . Feedstock substitution and most CO₂ utilisation mea - sures make the greatest contribution to Scope 3 emission reduction. Feedstock substitution may increase Scope 1 and 2 emissions depending on the source of the supple - mental utilities required, if any. The individual measures can be combined in various ways to arrive at a refinery decarbonisation programme. Such a programme includes: A set of CO₂ abatement curves showing cumulative CO₂ removal against the cost of the individual measures, considering synergies or improvement opportunities when combining measures. A roadmap which will picture how decarbonisation could develop with time, considering the duration of the imple - mentation of the various solutions (taking into account per - mitting, turnaround sequence, and construction time) and/ or expected time for technologies to have matured to an acceptable technical readiness level. Full economic analyses of the roadmap, also including CO₂ credits/taxes. In addition to presenting various options available to oil refineries in the reduction of CO₂ emissions, elaboration on what a potential roadmap would look like is forthcom - ing. Assessing the full impact and potential of the options being considered is a complex exercise. The true poten - tial of various decarbonisation programmes will require a full life cycle (ensuring a seamless evaluation of the con - secutive steps in the process without gaps or overlaps) and economic analysis, which is outside the scope of this article. Our reference case is a typical European refinery process - ing 10 MTA of crude oil, producing motor fuels and having a delayed coker and hydrocracker as its main conversion units. The refinery will continue to produce motor fuels in the
Impact of decarbonisation measures on Scope 1, 2 and 3 emissions
Scope 1 Scope 2
Energy efficiency Fuel substitution
CO₂ capture & use
10 MTA oil refinery, Scope 1, 2 and 3 emissions
Scope 1 Scope 2 1 Scope 3 2
KTA (93%) 1. Based on natural gas being used for power generation with an overall thermal efficiency of 50% 2. Based on combusting the refinery net production of LPG, naphtha, kerosene, diesel, fuel-oil, and coke, having an average carbon content of 85% (1%)
PTQ Q1 2023
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immediate future. The breakdown of Scope 1, 2 and 3 emissions is shown in Table 2 . Scope 2 emissions relate to electricity import. Scope 3 emissions represent emis- sions related to the combustion of motor fuels only, ignoring other contributors. Scope 3 emissions can be drastically reduced if a greater fraction of the refinery products is worked up to petrochemicals. Improving energy efficiency has a direct impact on Scope 1 and possibly Scope 2 emissions. While it has always been the goal of a refin - ery operator to reduce fuel consumption, the enforcement of a CO₂ tax gives further impe - tus to this. Techniques previously regarded as uneconomical may now prove to be attractive. Energy efficiency can be improved by operational and technical means. Operational means include operating distillation columns at their lowest possible pressure, minimising furnace excess air, avoiding reprocessing of CO₂ abatement measures Improved energy efficiency
CO₂ reduction and associated cost for selected measures, 2019 Western European pricing
€/t CO₂ avoided
€/t CO₂ avoided
(30% higher utility prices)
Energy efficiency Furnace revamp/replacement Fuel substitution Steam drivers to e-motors on green electricity 1
Green electricity 2 Blue hydrogen firing Green hydrogen firing5
271 273 370 370
Electric heating 6
1. It is assumed the refinery has 10 steam turbines in the 40-2000 kW range 2. The refinery has a power import of 82 MW. ‘Green’ electricity implies that this power is now coming from renewable sources. 3. Two furnaces of 100 MW each, new blue hydrogen plant 4. Excluding cost of CO2 disposal 5. Electrolyser stack cost of 650 €/kW, Two furnaces of 100 MW each 6. Two heaters of 100 MW each
streams, avoiding cooling and subsequent reheating of streams, minimising tank heating, use of more efficient catalysts that allow operating temperature or pressure to be reduced, preventive maintenance/cleaning, and so on. Technical means include installing additional or more effi - cient heat exchangers, implementing variable speed drives on pumps, applying heat pumps, swapping steam-driven ejectors for liquid-driven ejectors, and/or additional instru- mentation to monitor key variables and maintain them at optimum values. 2, 3 Operational and technical measures often go together, such as installing instrumentation to measure furnace flue gas O₂ content and ensuring this information is used to adjust the air rate to the burners. Energy efficiency improve - ment projects reduce CO₂ emissions, have a positive pay - back, and a negative CO₂ avoidance cost. A comprehensive review was carried out to determine the cost/benefits of revamping/replacing several stand- alone furnaces/boilers to achieve a 90% thermal efficiency. In preparing a hypothetical case, the refinery has a few fur - naces with efficiencies as low as 60%, which will need to be replaced. A number of other, higher-duty furnaces with efficiencies of around 80% will be revamped (for example, by installing air preheaters). For the hypothetical case, the total investment amounts to 97 M€. The 44 MW reduction in natural gas firing duty reduces Scope 1 CO₂ emissions by 74 KTA (4% of the original Scope 1 emissions). Without CO₂ tax, this project would, assuming 10% disbursement per year and a natural gas price of 375 €/t, have a payback time of close to 10 years and would not qualify for project sanctioning. The cost per ton of CO₂ avoided is -4 €/t, dropping to -44 €/t at a 30% higher natural gas price. The cost per ton of CO 2 avoided takes into account investment disbursement and changes in operating cost between the as-is situation and
the future situation also considering any changes in Scope 3 emissions where relevant. Fuel substitution Another way to reduce Scope 1 and 2 emissions is to con- vert steam drivers to electric motors and swap all electric consumers to green power. As a supplemental step in fuel substitution, furnaces could be converted to hydrogen fir - ing using green hydrogen produced via water electroly- sis or blue hydrogen from a new auto thermal reforming (ATR)-type hydrogen plant equipped with pre-combustion CO₂ capture. Some heating services (such as steam boil - ers) may be replaced by electric heat exchangers using green electricity. The estimated cost of these modifications, their impact on CO₂ emissions, and the cost per ton of CO₂ avoided (based on typical 2019 Western European pricing) are reported in Table 3 . The CO₂ avoidance costs are heavily dependent on the utility prices used. The last column in Table 3 shows the CO₂ avoidance cost at 30% higher utility prices. For all measures except furnace efficiency improvement, the cost of CO₂ removal goes up with higher utility prices. Replacing steam turbines with electric motors is not attractive as natural gas is still fairly inexpensive (in our cost basis) compared to electric power. This does not reflect current circumstances. ‘Green electricity’ implies all users have changed to elec- tricity from renewable sources at a higher cost than grey electricity. Electric and hydrogen (especially green hydrogen) firing have a high CO₂ avoidance cost. Feedstock substitution Replacing crude oil with renewable feedstocks such as vegetable oil (processed in an hydrotreated vegetable oil
PTQ Q1 2023
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