REFINING GAS PROCESSING PETROCHEMICALS PETROLEUM TECHNOLOGY QUARTERLY ptq Q2 2022
INDIAN GASOLI N E MARKET
DIRECT CO 2 REDUCTION OPERATIONAL TUNING OF FIRED HEATERS
DIGITAL TWIN FCC OPERATIONS
REVAMP TO THRIVE IN THE NEW REALITY
The global economic challenges impact product demand and skew product slates. As you continue to deal with the challenges in the present, its critical to think about long-term solutions. Shell Catalysts & Technologies, has solutions to enable you to make smart investments while preserving cash through revamping, reconfiguring, or optimising 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
Q2 (Apr, May, Jun) 2022 www.digitalrefining.com ptq PETROLEUM TECHNOLOGY QUARTERLY
7 Emerging opportunities Rene Gonzalez
15 Meeting future Indian gasoline market demands Edward Griffiths KBR 23 Achieving 95% direct CO 2 reduction for hydrogen plants Ken Chlapik, Dominic Winch and Diane Dierking Johnson Matthey 27 Digital twin optimises FCC operations for real separator behaviour Rodolfo Tellez-Schmill KBC (A Yokogawa Company) Tom Ralston and Wim Moyson MySep
33 Revamp of a methanol wash column Ang Chew Peng and Tan Hian Min Sulzer Singapore Mariyana Chalakova and Ludwig Bauer Linde Germany Carlos Arguelles Sulzer Chemtech Switzerland
41 Importance of testing for vacuum ejectors in refinery service Edward Hartman and Tony Barletta Process Consulting Services, Inc. Laurent Solliec and Peter Trefzer GEA Wiegand GmbH 49 Rejuvenated catalysts optimise refinery margins in high severity ULSD applications
Ioan-Teodor Trotus and Jean-Claude Adelbrecht hte Michael Martinez and Guillaume Vincent Evonik
57 Continuous operational tuning of refinery fired heaters Euler Jiménez G Independent Advisor and Instructor on Fired Heaters 63 Using future rows capacity to debottleneck fired heaters Akhil Gobind, Ankur Saini, Rupam Mukherjee and Shilpa Singh Engineers India Limited 69 Artificial intelligence for sustainable development Gregory Shahnovsky, Ariel Kigel and Gadi Briskman Modcon Systems 73 Energy management and sustainability of the downstream industry Marcio Wagner Da Silva Petrobras
79 Technology in Action
Cover SPEC Energy DMCC’s grassroots refinery in Pakistan targeted upgrading VGO and VR to high-octane gasoline blendstock Photo: Honeywell UOP
©2022. 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.
In the lead up to the event, we’re asking leading experts to provide us with first insights into the discussions we can expect on 18-19 May in London. Watch the previews
Click the images to watch
Watch Miguel A. Calderón , Carbon Cycle Director Division – ESG, Cepsa and Joachim von Schéele , Director Global Commercialization, Linde discuss the path of energy transition and the impact of recent events on setting a realistic roadmap.
Watch André Faaij , Director of Science, TNO Energy Transition provide a glimpse of the multiple opportunities already here for the industry to explore.
Brought to you by: decarbonisationtechnologysummit.com
Joachim von Scheele Linde
Matthew Williamson BP
Lara Young Costain
Jean-Marc Sohier Concawe
Angus Gillespie Global CCS Institute
Maurits van Tol Johnson Matthey
Miguel Ángel García Carreño Repsol
Miguel A. Calderón Cepsa
Guloren Turan Global CCS Institute
André Faaij TNO
Joseph Howe Energy Research Institute
Daniel Carter Wood
Concetto Fischetti IOGP
Girish Nadkarni TotalEnergies Ventures
Lewis Barlow Scottish Government
John Davies Derwent London
Jim Heverin Zaha Hadid Architects
Syrie Crouch Shell
Attend in person or online!
Fred van Beuningen Chrysalix
Sir Dieter Helm CBE University of Oxford
Claude Loréa Global Cement and Concrete Association (GCCA)
Chris Manson Whitton Progressive Energy
There’s a lot more information that we’d be happy to share. If you have a question about the programme or would like to find out about opportunities to make an impact, please get in touch! Our team is here for you Christina Wood, Event Development Director E: firstname.lastname@example.org Paul Mason, Business Development Director E: email@example.com If your organisation is part of an industry association or looking to send a bigger team you may qualify for a special rate. Get in touch to find out more, email: firstname.lastname@example.org Are you looking for a discount?
Expand your renewable feed options with Albemarle ReNewSTAX ™ . ReNewSTAX ™ – Albemarle’s catalyst technology for processing renewable feeds into your valuable hydrotreating unit. Learn how you can power the potential of your refinery at Albemarle.com/Renewables .
ptq PETROLEUM TECHNOLOGY QUARTERLY
Emerging opportunities M y first duty on returning to PTQ as editor is to thank Chris Cunningham for his excellent work over the past 13 years. We hope he enjoys a well- deserved retirement. As I take the reins, I see many emerging opportunities for integrated refinery/petrochemical facilities and certain standalone fuels refineries. But for the most part, we are under no illusion that refining capacity and investments are levelling off or declining in mature markets. C ompared to the previous decade, awider array of topics require a deeper dive from a technology perspective. In the quest for net-zero emissions (NZEs), enterprise-wide metrics like sustainability and ESG weigh into every refinery processing discussion, such as crude-to-chemicals (CTC) and waste plastics recycling. With the expansion of the circular economy influencing the refining and petrochemical sector, expect to see downstream industry topics on renewable fuels coprocessing through upgraded FCCandhydrotreating units and speciality chemicals. As the industry evolvesmore rapidly than expected, data analytics,AI, andmachine learning can enhance thermodynamic, catalytic, and mass transfer capabilities Against this backdrop, we are developing content with a view to how refiners can be the solution instead of the problem towards sustainability based objectives. U ncovering process opportunities, including hydrocracker upgrades to increase naphtha feedstock production for world-scale steam crackers, requires a multi- faceted approach. For this task, refinery uplift from petrochemical production and the ability to make money varies for different regions due to complexity and efficiency advantages, which is why the CTC transition warrants more scrutiny. LNG deserves more elaboration, considering it serves as the primary transition energy product on the road to 2050 deep decarbonisation targets. And even though fossil fuel products are projected to peak in the late 2020s before steadily declining, editorial coverage will not end there. Niche opportunities continue to emerge in the supply of clean fossil fuels for the Latin American market and elsewhere. Speaking of opportunities, the newest refinery projects are petrochemically integrated, such as the Saudi Aramco JV with China announced recently. This is another clear indication that fossil feedstocks for petrochemical demand are set to increase through the early 2040s. In fact, 309 Mtpy of oil was converted into petrochemicals in 1990, while the IEA projects a 905 Mtpy demand growth by 2035. The Gas 2022 special report, included with the Q2 issue of PTQ , discusses a range of topics, ranging from midstream gas processing, LNG process optimisation, and H 2 production to fuel olefins plants while reducing site-wide CO 2 emissions. In the second half of 2022, the Q3 and Q4 issues will focus on the transition towards speciality chemicals and the interconnection of aromatics and olefins processes. One area hardly discussed in the previous decade involves the integration of refineries and other heavy industries for energy and CO 2 recovery. This development alludes to the possibility of surprises and advantages for dwindling fuels refineries. It includes opportunities for cogeneration and co-development of distributed energy resources (DERs) with other heavy industries like steel. As mentioned at the start, I am under no illusion that all these metrics will come to fruition. Still, we are already seeing developments that will benefit refiners in distress, such as biomass processing to SAF and pyrolysis of polyethylene post-consumer plastic packaging waste. Some of these include opportunities for relatively small fuels refiners to take the lead in establishing microgrids to supply electricity for midstream oil and gas operations, mega data centres, or even mining operations. There is a lot to cover. In any event, I am glad to be back.
Vol 27 No 3 Q2 (Apr, May, Jun) 2022
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PTQ Q 2 2022 7
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 lowmass 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 email@example.com www.revamps.com
More answers to these questions can be found at www.digitalrefining.com/qanda
Q What are themain issues you have experienced in revamps to add in CO 2 capture? A Ken Chlapik, Market Manager - Low Carbon Solutions, JohnsonMatthey, firstname.lastname@example.org The main issues we have seen in CO 2 capture based revamps on existing syngas plants are: 1) Carbon pricing: CO 2 capture comes at a cost; whether the region has an incentive or a tax, is it enough to drive the investment? 2) Carbon storage: some states and countries do not have sequestering sites, and transport costs to other regions can be prohibitive. 3) Capital cost: during the pandemic, many companies have reduced capital budgets by 20% and have priori- tised upstream methane emissions and renewable fuels in their strategic plans. 4) Plot space required: many facilities are in metropoli- tan areas with limited space for development, with some CO 2 capture solutions requiring more space than the plant producing the emissions. Johnson Matthey’s Low Carbon Solutions portfo - lio utilises Advanced Reforming technology to provide enhanced carbon capture, resulting in up to 95% CO 2 capture with 40% lower plot space requirement and 30% less capital than post-combustion solutions. Q Howhastheintegrationofalternativefeedstocks impacted your overall energy efficiency (any pluses and minuses)? A Nicolas Bouvier, Renewable Hydroprocessing Technologist, Axens, nicolas.BOUVIER@axens.net; Benoît Durupt, Hydrotreatment Global Market Manager, Axens, benoit.DURUPT@axens.net The main incentive for using alternative feedstock is to reduce the overall CO 2 footprint of the refinery, which is a key objective for any operator today. This integration comes with some consequences, especially on hydro- treating units, where those impacts are as diverse as the feedstock types on the overall energy efficiency of the refinery. For renewable lipids, the oxygenated compounds in those feeds make this type of feed more hydrogen intensive and exothermic than fossil feedstocks. With adequate heat management and high-efficiency heat exchangers like ZPJE spiral tube heat exchangers, those feedstocks can generate sufficient heat to reduce or avoid the use of fired heaters in hydroprocessing. At the same time, it could also generate steam for the refinery net - work, which is a plus. In addition, propane is a valu- able by-product of glycerides hydroprocessing. It can be either valorised as a bio-LPG product or used to replace advantageously natural gas as a steam reforming feed- stock or refinery fuel gas, thus decreasing the overall car - bon intensity.
On the other hand, alternative feedstocks also have variable content and impurities that can negatively impact the overall energy efficiency. For example, waste based feedstocks such as plastic pyrolysis oil can have very high levels of metals or chloride due to their various origins and initial treatments, which will have a negative impact on global heat integration. Metals will require increased reactor temperature due to catalyst poison- ing and reduced cycle length, while chloride will make heat integration more complex due to corrosion issues. In addition, other contaminants can be sources of pressure drop build-up and subsequent operational issues. In this context, even low incorporation rates of those pyrolysis oils can negatively impact the overall energy efficiency. However, a combination of equipment, specialty grad- ing, specific catalysts, and unique process expertise can mitigate these negative effects. Axens’ EquiFlow Hy-Clean filtering trays, ACT series specialty bed, the latest HR 700’s series, air preheater (APH) technologies, revamp studies are among Axens’ proven solutions to overcome the challenges of any alter- native feedstocks co-processing. They maximise their rate of incorporation in existing assets with an overall positive impact on energy efficiency. A Tom Chupick, Principal Consultant – Carbon and Energy Management, Petrogenium, email@example.com It depends. The blending of bio-components directly into the refinery gasoline pool tends to reduce reformer throughput, which requires higher severity to sustain hydrogen production. This is usually an energy inten- sity index penalty (depending on reformer optimisation and constraints). Coprocessing bio-components in HDS feeds increases reaction heat and hydrogen consump- tion, which may appear to lower HDS reaction furnace duty, but may not translate into a site-wide energy ben- efit when hydrogen supply is considered. Note that most refineries make incremental hydrogen from 75% efficient steam methane reformers. Importing green/blue hydro- gen reduces the site’s own energy use and CO 2 emissions but has an even lower efficiency when off-site energy use is considered (albeit offset by lower Scope 2 CO 2 emis- sions). Dedicated biorefinery units or massive hydrogen imports can lead to fuel/steam system imbalances with more inefficiencies. To summarise, alternative feeds usu - ally have a favourable (accounting) impact on local pro- cess unit energy efficiency, which can be misleading when the energy (and resource) efficiency across a wider boundary is considered. Any experiences you can share regarding the imple- mentation of carbon management/digital data tools? A Marie Duverne, Technical Support Digital Transformation Leader, Axens, Marie.DUVERNE@axens.net; Pierre-Yves Le Goff, Global Market Manager, Reforming & Isomerization,
PTQ Q2 2022 9
Process Book) used for operations, process control, and reliability. In addition to the ubiquitous lagging indi - cators, such as unit/site energy indices, effective EnMS use leading KPIs that are operating handle/degradation focused and prioritised on energy or $ gap to poten - tial. These leading KPIs include reflux ratios, key tem - peratures, pressures, fouling/degradation impact on exchanger heat recovery/compressor efficiency. They were originally developed in a standardised (Excel) variable table with regression based SMART targets that track key constraints like product quality. Effective EnMS accountability requires a mix of central and units roles, usually with a central coordinator, site-wide tools, and functions for utility systems, furnaces, compres - sors and responsibilities for each process area. Daily, weekly, monthly, quarterly meetings and reports include a significant $/day total energy gap and the top notable contributors at the unit/equipment area levels to drive operations and maintenance or project initiation needed to close the gaps, which should be tracked by the normal refinery initiative management processes. Q Have completed energy efficiency projects delivered expected energy and CO 2 savings? A Romain Roux, Decarbonization & Consulting Director, Axens, firstname.lastname@example.org In the frame of energy efficiency studies performed by Axens Horizon, we have frequent feedback on the results of implemented energy efficiency solutions, especially for quick wins and budget-friendly solutions. Results are as expected within a margin of accuracy that depends on the accuracy of the basic data. Some solutions we would like to highlight include: ● Low Capex projects for optimisation of complex heat exchange networks by re-routing of streams ● Optimisation of distillation column operating conditions ● Upgrade of heaters fuel/air control system ● Implementation of air preheaters in furnaces Among the solutions creating a higher return on investment, we got several opportunities to switch two heat exchangers within a heat exchange network (CDU, coker, visbreaker). The two heat exchangers were iden - tified thanks to Pinch analysis developed explicitly for revamping applications. A Ken Chlapik, Market Manager - Low Carbon Solutions, JohnsonMatthey, email@example.com For decades Johnson Matthey has been involved in energy efficiency projects with its customers to help reduce the level of energy used per unit production of syngas. For example, in the refinery hydrogen market, we have worked with industrial gas companies over the last 20 years to set new levels of efficiency that are 20-30% lower than on-purpose refinery hydrogen plants. This has been done utilising unit technologies and cat - alyst developments to not only improve year one per - formance but also extend that efficient performance for long lifecycles beyond the typical refinery major turn - around cycle.
Axens, Pierre-Yves.LE-GOFF@axens.net; PhilippeMège, Head of Digital Service Factory, Axens, Philippe.MEGE@axens.net Digital transformation of the refining and chemical industry is now playing a crucial role in energy effi - ciency improvement and associated GHG emission reduction. Digitalisation in view of remote performance monitoring is a major aspect of today’s unit operation management and optimisation. The main advantages of digital tools are first to reduce the delay between the client’s request for unit monitoring or troubleshooting and the technology provider’s answers, and to open up access to customised unit optimisation tools. Implementing Software as a Service, accessible to our customers 24/365 and fed by process and lab data through an automatic and near real-time transfer, has been the first step of our digital transformation and paved the way for a new paradigm for technical services. For such fast-track implementation, supported by licensor and catalyst experts, operator involvement to automate data transfer while addressing all potential concerns related to cybersecurity, data ownership, and lifecycle is minimum. For operators, access to appropriate alerts, data anal - yses, and optimisation tools are success factors in fast decision-making in increasing overall unit profitability. Typical examples of client expectations that can be addressed through remote performance monitoring are: unit performance prediction while changing operating conditions; comparing actual performances with nor - malised ones; catalyst end-of-cycle prediction to antic - ipate turnaround or get the most from the catalyst; or even proposing continuously the best set of operating conditions for a given set of performance targets, such as yields optimisation, utilities reduction, and cycle length extension. Reliability of the projections is ensured through advanced data analysis algorithms with a preliminary data reconciliation step using, for instance, principal component analysis (PCA) and robust regression meth - odologies such as partial least squares (PLS) or Theil- Sen estimator. Other available tools are very accurate and continu - ously update shift vector generation, which can become a major help for the planning department. The generation of synthetic data thanks to machine learning is another example of either densifying lab - oratory data or generating new models to foresee a product’s properties based on existing process data and unit performances and acting as an on-line analy - ser. Improving operation survey quality at no extra cost becomes a key adoption factor. A Tom Chupick, Principal Consultant – Carbon and Energy Management, Petrogenium, firstname.lastname@example.org After developing/supporting/auditing a few dozen energy management systems (EnMS) globally, the main learnings relative to integration and accountabilities help drive sustainability. The foundation is consistent with Iso-50001, but improved sharing and replication of best practices and tools is required. Sites with effective inte - gration have built EnMS into the same user interface (PI
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Carbon dioxide is formed both on the process side of syngas flowsheets and the steam methane reformer (SMR) furnace firing side of syngas production. Energy efficiency projects can impact these CO 2 emissions, but that has only recently been the focus of energy efficiency projects. Johnson Matthey’s Low Carbon Solutions busi - ness has been established to help our customers in the chemical and refinery markets decarbonise their exist - ing syngas production and facilities. JM’s Advanced Reforming technologies, combined with the applica - tion of decades of experience in syngas production, have resulted in a portfolio of solutions that can impact the CO 2 emissions of existing syngas production, not only to enable enhanced carbon capture of up to 95% but also to reduce the overall CO 2 emissions being produced within the flowsheet by 20-30% through improved carbon inten - sity of the syngas production. A Tom Chupick, Principal Consultant – Carbon and Energy Management, Petrogenium, email@example.com A wide range of (refinery) energy efficiency projects have led to varying degrees of success. The optimisation and maintenance projects demonstrate close to the expected benefits in the short term, but benefits often degrade over time without adequate systems and accountabilities. Major successes include heat exchanger cleaning-cycle optimisation, distillation optimisation (with a $ gap com - plementing both base layer and APC systems) and cata - lyst/reaction ratio optimisation, particularly on reformer H 2 :Oil, SMR S/C ratios, and some hydroprocessing units with flexibility. Capital projects include heat recov - ery (such as modifying the exchanger to reduce fouling, re-piping, adding a new area, modifying pumparounds to make more heat available at higher temperatures on CDU/HVU systems). Steam systems operations and maintenance usually give sustained benefits, aided by a number of platforms available for steam models plus a focus on leaks, traps, losses, and turbine vs let-down optimisation, plus heat recovery/optimisation to reduce site steam use. Major utility projects like GT based cogen systems to replace boilers are increasingly diffi - cult to justify due to cheaper/lower CO 2 footprint renew - able power and major steam demand reductions due to optimisation/downsizing. Q How is the downstream industry progressing in the application of data analytics to support plant operations? A Keith Tilley, CEO, Intoware Ltd, firstname.lastname@example.org Our research found that over three-quarters, 80% of oil and gas companies post-pandemic, are relying on legacy systems and spreadsheets to get tasks done, believing this inflexible, often out-of-date, disconnected data is suf - ficient to support corporate decision making. This independent survey showed that the vast major - ity of those working in oil and gas, 92% claimed to be data-informed and 76% said that they trust data enough to complete tasks, this is despite most of them still rely - ing on disparate legacy systems.* Most of those surveyed believe they are data-driven, when in reality they could be relying on old, out-of-date
data. This disconnected data acts like a ball and chain, tying down staff as they spend a huge amount of time trying to unlock data trapped in spreadsheets and legacy systems to meet the demands of businesses, customers and regulators. Our research shows that over three-quarters, 80% of decision makers have access to data and the large major - ity 84%, believe that data is an asset, which is very good news. However, just under half of those surveyed, 47% use data only occasionally to help get the job done - as the reality is that their data is siloed. While nearly two-thirds 72% are interested in using digital software ‘tools’ to support their role, it seems that a significant minority simply don’t have the skills to use the new data these systems provide, with 21% feeling overwhelmed and another 24% feel only slightly con - fident when using data to back decision-making, that is almost half, 45% of those surveyed. Despite this, when it comes to passing on critical skills and expertise from ageing workers to help plug the skills ‘gap’ for the next generation, 76% see digital ‘tools’ as playing a valuable part in sharing knowledge. So, it’s no surprise that most companies (80%) intend to invest in data skills, training and development in 2022 to help meet this challenge. It seems that a culture of un-informed decision-mak - ing still persists for many, with just under a half (40%) having made decisions based on ‘gut-feel’ during their careers, with 32% doing this on a monthly basis and a worrying 8% each week. This was particularly prevalent in the oil and gas industry, where un-informed decisions are relied on by 40% of those surveyed. This culture goes right to the very top of businesses, with just under a third, 28% of senior decision makers and 27% of managers relying on ‘gut-feel’ all the time. This can have serious implications, such as when man - agers need to introduce engineering changes without assessing the impact on current works or raw materials for example – which are all factors that are detrimental to business performance. A reliance on siloed data severely hinders business operations with accountability and visibility issues, as each department has their own interpretation of data, which is a problem for businesses that are increasingly under pressure to evolve how they manage resources and communicate data insights. If you digitise paper-processes with work-instruction ‘tools’ that integrate with connected smart devices and third-party systems, this information can be more easily shared, providing staff with access to quality data, and a ‘single source of truth’ right across the business, for more proactive and rapid, ‘real-time’ insights to improve pro - ductivity and satisfy compliance. As oil and gas operators persist in the belief that they are data-driven by relying on spreadsheets, legacy sys - tems and ‘gut-feel’, it will negatively impact on their efforts to be more competitive as staff spend time gather - ing and cleaning data just to respond to requests, which means they risk not focusing on the insights that will really add value and future growth. *This research survey was conducted by Surveygoo with 1,030 industrial businesses, between the 28th February and the 3rd March 2022.
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Meeting future Indian gasoline market demands
The role Indian oil refiners can take inmeeting gasoline demandwith production of clean burning components
Edward Griffiths KBR
T he Indian transportation fuels market has traditionally been dominated by diesel, but recent changes to legislation and consumer preference are produc- ing a shift away from diesel and towards gasoline consumption. Since vehicle electrification is still in its infancy, gasoline demand seems set to rise considerably through the 2020s and beyond. While gasoline remains a key transportation fuel, its growth must be balanced with environmental considerations such as air quality and decarbonisation which will be supported by changes to gasoline specifications. This arti - cle addresses the role Indian oil refiners can take in meeting gasoline demand with production of clean burning components. Indian transportation fuels demand The Indian transportation fuels mar - ket has traditionally been dominated by diesel, accounting for some 74% of transportation fuels consumed in 2019 (see Figure 1 ). Consequently, Indian refineries have been config - ured and operated for maximum diesel production. However, legis- lative changes and environmental standards have driven consumer behaviour towards owning and operating gasoline vehicles. In the period from 2012 to 2014, the Government of India (GOI) gradually increased the price of diesel, until subsidies were fully removed in October 2014. 2 The removal of the diesel subsidy nar- rowed the price differential between diesel and gasoline fuels, bringing the retail price of diesel to 80% of the gasoline price, up from 63% in 2011/12 (see Figure 2 ). This change
Period of subsidy removal
% share gasoline
Figure 1 Indian transportation fuels consumption
Source: Petroleum Planning & Analysis Cell 1
in pricing policy corresponds to the beginning of a sustained uptick of gasoline consumption from 2012, as a percentage of transportation fuels, illustrated in Figure 1 . A second factor in the pivot towards gasoline is the transition to Bharat Stage 6 (BSVI) emis- sions standards, implemented in April 2020. The transition to BSVI emissions standards required the introduction of new diesel engine technologies, including diesel par- ticulate filters and selective catalytic reduction. The addition of these sys - tems and their associated electron- ics added significantly to the cost of diesel vehicles, making them less attractive to consumers. The impact of this change is greatest in smaller vehicles, where the relative cost of additional components is largest, and small gasoline vehicles offer a cost-effective alternative. Indeed, India’s leading car marker, Maruti
Suzuki, has exited the diesel car market altogether. 3 The cumulative impact of these changes has led to a drop in the share of diesel car sales from nearly 50% in 2012/13 to only 19% in 2018/19. 4 In the same period, total passenger vehicle sales increased by 27%, from 2.7 million to 3.4 mil- lion 5,6 , implying that annual gaso- line vehicle sales grew by more than 100% in the same period. The effect of vehicle electrification is yet to be seen in the fuels market, with electric vehicles (EVs) account- ing less than 1% of new light vehicle sales in 2020 and predicted to reach only 8% penetration by 2030. 7 With the cost of lithium carbonate, used in car batteries, increasing eight-fold since the start of 2021 8 , the price of EVs is likely to remain prohibitive to mass adoption in the short to medium term, so the impact on gas- oline consumption will be muted.
PTQQ 2 2022 15
vehicles for E20 compatibility is prohibitive. With the registration limit of gasoline vehicles at 15 years, most vehicles will not be E20 com- patible in 2025, and the role of the E10 protection grade will be signif- icant for a decade or more. Whether or not E20 is fully adopted in 2025, the projected gasoline demand in Figure 3 shows contin- uing growth, with volumes rising 70% through this decade. Even with full E20 utilisation, the volume of conventional gasoline is predicted to rise by 43% in the same period. CAFE norms Phase II The second phase of CAFE norms will further reduce the benchmark emissions for diesel and gasoline vehicles. As other regions have experienced, this change requires a shift to more modern engine tech- nologies such as turbochargers and gasoline direct injection. Due to the higher compression ratio used in these engines, it is likely that the new norms will require large-scale rollout of 95 RON (research octane number) gasoline, a four-point increase from the current stand- ard. This development would bring Indian gasoline specifications in line with EN228, the European standard that aligns gasoline specifications with Euro emissions standards. There is a certain synergy from introducing a 95 RON standard and rolling out E20 in the same period. Adding 20% ethanol to a 91 RON gasoline stock provides a boost of around four octane num- bers, bridging the gap to the new grade. However, around 40% of this benefit is already realised through the current ethanol blending level. There is also a question of where the credit for ethanol octane is taken. If refinery storage and pipeline sys - tems are not compatible with E20, due to the hygroscopic nature of ethanol, can refiners take credit for ethanol blended downstream, with a risk of shortfall in ethanol sup- ply? To ensure a smooth rollout of 95 RON standard, it would be pru- dent to plan for supply of additional octane enhancers. It is also worth noting that an increase in ethanol blending raises the Reid vapour pressure (RVP) of
30% 20% 10% 40%
Period of subsidy removal
Diesel as % of gasoline
Figure 2 Indian transportation fuels prices
Source: Petroleum Planning & Analysis Cell 1
Future gasoline market The GOI recognises that vehicle emissions reduction is required to mitigate the effects of an increas - ing transportation fuels consump- tion as mobility increases. It is widely reported that two signifi - cant changes in gasoline quality and emissions specifications are being implemented to ensure sustainabil- ity and security of fuel supply: • In 2021, the GOI announced a roadmap to achieve 20% ethanol in gasoline (E20) by 2025. 9 • The first phase of Corporate Average Fuel Economy (CAFE) norms requires car makers to cut carbon emissions from new cars to below 130 grams per kilometre by April 2022. In Phase II, imple- mented by 2024, emissions are to be cut to less than 113 grams per kilo- metre. 10
E20 roadmap In the period 2020-21, average eth- anol blending in gasoline hit its highest total of 8.1% 11 albeit against lower overall gasoline demand than the previous two years, due to the pandemic. The target of 20% etha- nol blending, against rising demand for gasoline as shown in Figure 3 , is an ambitious target. The target is unlikely to be met in its entirety due to a range of supply, distri- bution, and demand factors. One primary reason is that the current fleet of vehicles is not compatible with gasoline containing more than 10% ethanol. Under the roadmap, E20 compat- ible cars will not become available until April 2023, and they will be tuned for highest efficiency with E10 fuels. 9 The GOI has also con- cluded that the cost of retrofitting
Hydrocarbon, Cr. litres
Ethanol, Cr. litres
2021 2020 0
Figure 3 Indian gasoline demand projection by component
Source: Government of India 9
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the blend, typically by around 1 psi (7 kPa) for both E10 and E20 blends. This impact will place a greater rel- ative premium on low RVP compo- nents in the gasoline pool. Petrochemicals integration A further factor influencing the Indian gasoline market is the pro- gression towards greater integra- tion of refining and petrochemicals, where optimal molecule manage- ment is key to maximising value. In an integrated scheme, a portion of naphtha is cracked in a steam cracker or high severity catalytic cracker to maximise olefins yield, and aromatics from reformate and FCC light naphtha are recovered for petrochemicals use. 12 Removing aromatic compounds from the gas- oline pool in this way will have a negative impact on volume, octane, and RVP of the pool, while cracking naphtha to produce light olefins fur - ther decreases the volume of blend stock available. Meeting demand and specifications With tightening emissions standards and increasing gasoline consump- tion, the demand for high octane, clean burning gasoline blend stocks will require focused investments in the near term. As reformate and naphtha are increasingly redirected to petrochemicals production, Indian refiners should look for alternative routes to produce high octane, low RVP components. One such oppor- tunity lies within the butane-buty- lene fraction (BBF) product from the FCC unit. The olefinic content of this stream can be readily utilised to produce ethers and alkylate, both of which are ideal premium gasoline blend stocks: • Alkylate is produced via the alkyl- ation of isobutane with light olefins, most commonly butylene, gener- ating a high octane, clean burning, and low RVP product. • Common ethers include methyl tert-butyl ether (MTBE) and ethyl tert-butyl ether (ETBE), with clear RON of 117 and 118, produced from etherification of isobutylene with methanol and ethanol, respectively. While only two MTBE units and two alkylation units are listed in published data for India, there are
Stream or product name
Figure 4 Potential utilisation of FCC butane-butylene fraction
around 20 FCC units in the coun- try, representing an opportunity to increase production of octane enhancers. By contrast, there are around 50 FCC units in Europe, of which over 80% have associ- ated etherification and/or alky - lation capacity to meet EN228 specifications. Figure 4 illustrates the potential gasoline products to be produced from a typical 20 MT/h FCC BBF stream via dimerisation of isobu- tylene, etherification with metha - nol, or alkylation with isobutane. MTBE and ETBE exhibit high blending RON, typically 119 and 120, respectively, depending on the gasoline matrix. Isooctene, the product of isobutylene dimerisa-
tion, has a high blending RON of 124, based on a 10% blending vol- ume. Alkylate, with a RON rating of around 97, can be produced in larger volumes because it utilises all C 4 olefins and isobutane, mak - ing it a good component to add high octane volume to the gaso- line pool. Make-up isobutane for alkylate production is typically sourced from the saturated gas plant, with additional volumes pro- duced through C 4 isomerisation, if required. Etherification and alkylation tech - nologies can be used in series to provide the largest octane contribu- tion. Figure 5 illustrates the potential products from sequential production of MTBE and alkylate, with the alky-
n-butane i-butane 1-butene trans-2-butene cis-2-butene i-butene
MTBE & Alkylate
Stream or product name
Figure 5 Maximise octane contribution from FCC butane-butylene fraction
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produce MTBE or ETBE in the short term, while ethanol supply is scarce, and switch to isooctene or isooc- tane when enough ethanol is avail- able to satisfy E20 requirements, or when gasoline oxygen content limi- tations prevent blending of ethanol and ethers. Alkylation technologies In the US, where use of fuel ethers is banned due to concerns about contamination of water, alkylate forms around 13% of the gasoline pool, with ethanol content at 10%. Alkylate exhibits all of the ideal properties of premium gasoline, being free from sulphur, olefins, and aromatics, having a high octane number, and low vapour pressure. In US refining circles, it has earned the moniker ‘liquid gold’ due to its utility in correcting gasoline blend properties and composition. Alkylate has found limited use in the Indian gasoline pool to date. Blending to the standard 91 RON gasoline grade does not require alky- late, and traditional alkylation tech- nologies bring their own challenges. Both types of legacy alkylation tech- nology use strong liquid acid cata- lysts: hydrogen fluoride (HF) and sulphuric acid. HF alkylation was more popular in earlier years due to lower installed cost than the sulphu- ric acid process, with around half of alkylation units in the US using HF. However, concerns about the poten - tial risks from HF acid release and aerosol formation have swung the balance in favour of sulphuric acid alkylation in recent decades. Sulphuric acid is inherently less efficient as an alkylation catalyst, so large volumes of catalyst are required. Regeneration of the cat- alyst is carried out in a separate spent acid recovery unit, which generates flue gas with high SOx, NOx, and volatile organic com- pound (VOC) content. The spent acid regeneration unit, acid storage and handling facilities, and waste- water treatment add significantly to outside battery limit (OSBL) scope, making capital costs another barrier to alkylation adoption in India. Ionic liquid alkylation technol- ogy has recently been marketed as a cleaner, safer alternative to sulphuric
Mixed C feed
Make-up water methanol
Figure 6 A flexible process for ethers and Isooctene production
late product achieving higher quality in the absence of iso-butylene. KBR’s solid acid alkylation technology (K-SAAT) produces alkylate with 99 RON in this configuration. ETBE vs MTBE The choice between MTBE and ETBE production has generally been a question of economics and local policy. In markets without incentives for bio-components, the lower cost of methanol versus eth- anol favours MTBE. Renewable fuels policies in Europe have lat- terly favoured conversion to ETBE production, utilising bioethanol, and Japan began widespread use of ETBE in 2010 to meet its obligations under the Kyoto Protocol. ETBE can play a useful role in the Indian market by extending the octane contribution of bioethanol in ex-refinery gasoline. While the blending RON of ETBE (120) is lower than ethanol (~130), each litre of eth - anol can be converted to 2.4 litres of ETBE, providing a larger octane con- tribution to the gasoline pool. Water solubility of ETBE is lower than both MTBE and ethanol, improving its
storage properties to enable blending at the refinery and reducing reliance on ethanol blending downstream. In addition to these benefits, the blending RVP of ETBE is only four psi (28 kPa) versus a blending RVP of around 20 psi (138 kPa) for etha - nol. ETBE is, therefore, an excellent component to help meet future gas- oline standards and allow blend- ing of low-value naphtha streams into gasoline. A flexible solution Given the dynamics of the Indian gasoline market, refiners may prefer to hedge their bets by constructing a unit with product flexibility. KBR partners with Neste Engineering Solutions Oy to license NexEthers technology for combined ethers pro- duction and NexOctane for isooc- tene or isooctane production, while offering the flexibility to design for swing production of ethers and isooctene. Figure 6 illustrates the flexible process, which offers very high conversion, high availability, and easy operability. In the Indian market, a refiner may opt to install a flexible unit to
Figure 7 Alkylation technology catalysts
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