ptq Q1 2024 REFINING GAS PROCESSING PETROCHEMICALS DIGITAL TWINS REFINERY WASTEWATER CHALLENGES CDU OPTIMISATION PREFLASH DRUMS & TOWERS CONTROLLING BIOFILM FORMATION TO MAKE SURE YOU CONTINUE RECEIVING A REGULAR ISSUE OF PTQ UPDATE YOUR SUBSCRIPTION REGISTER FOR A PRINT OR DIGITAL ISSUE ANY QUESTIONS? CLICK HERE REGISTER CONTACT US © 2023 Honeywell Inc. All rights reserved uop.indd 1 13/12/2023 17:46:07 ptq PETROLEUM TECHNOLOGY QUARTERLY Q1 (Jan, Feb, Mar) 2024 www.digitalrefining.com 3 Challenges to chemical recycling of plastic waste Rene Gonzalez 5 ptq&a 15 Adding CHP to refinery power infrastructures Rene Gonzalez PTQ 19 Filtration and separation for industrial carbon capture, transport, and storage Lara Heberle and Julien Plumail Pall Corporation 25 Overcoming wastewater challenges of opportunity crude processing Shane Lund Veolia Water Technologies & Solutions 31 Biofilm: A hidden threat Brian Martin Marathon Petroleum Corporation Tim Duncan and Gordon Johnson Solenis LLC 39 Simulating FCC upset operations Tek Sutikno Fluor Enterprises 45 Refractory detection system and floating roof protection Bob Poteet and Andrea Biava WIKA Haytham Al-Barrak and Mahendran Sella Saudi Aramco 51 Crude to chemicals: Part 2 Kandasamy M Sundaram, Ujjal K Mukherjee, Pedro M Santos and Ronald M Venner Lummus Technology 59 Revolutionising refining with digital twins Michelle Wicmandy, Jagadesh Donepudi and Rodolfo Tellez-Schmill KBC (A Yokogawa Company) 65 Optimising nitrogen utilisation in refinery operations Rajib Talukder and Prabhas K Mandal Aramco 75 Simulating VGO, WLO, and WCO co-hydroprocessing: Part 2 Mohamed S El-Sawy, Fatma H Ashour and Ahmed Refaat Cairo University Tarek M Aboul-Fotouh Al-Azhar University S A Hanafi Egyptian Petroleum Research Institute 81 Considerations for crude unit preflash drums and preflash towers Henry Z Kister and Walter J Stupin (dec.) Fluor Maureen Price Maureen Price Consulting LLC 93 Technology in Action Cover Large volumes of utility steam and cooling water are key to sustainable refinery and petrochemical operations, such as the unit shown on the front cover. Photo courtesy of Kurita Water Industries Ltd ©2024. The entire content of this publication is protected by copyright. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means – electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner. The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included in Petroleum Technology Quarterly and its supplements the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies. www.digitalrefining.com www.decarbonisationtechnology.com q1 ed com.indd 1 12/12/2023 12:34:25 Revamp to thrive in the new reality Ever-changing market conditions, global economic challenges, and the shared journey of the energy transition all mean it is crucial to evaluate easy-to-implement and costeffective improvement opportunities. At Shell Catalysts & Technologies, our solutions open new possibilities for smarter investments while preserving cash through revamping, reconfiguring, or optimising your existing assets. Our experts co-create tailored solutions 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. shell.indd 1 shell_revamp_PDQ.indd 1 08/12/2023 11/14/2312:55:23 2:59 PM ptq Challenges to chemical recycling of plastic waste PETROLEUM TECHNOLOGY QUARTERLY Vol 29 No 1 Q1 (Jan, Feb, Mar) 2024 Editor Rene Gonzalez [email protected] tel: +1 713 449 5817 Managing Editor Rachel Storry [email protected] Editorial Assistant Lisa Harrison [email protected] Graphics Peter Harper Business Development Director Paul Mason [email protected] tel: +44 7841 699431 Managing Director Richard Watts [email protected] Circulation Fran Havard circulation@petroleumtechnology. com EMAP, 10th Floor, Southern House, Wellesley Grove, Croydon CR0 1XG tel +44 208 253 8695 Register to receive your regular copy of PTQ at https://bit.ly/370Tg1e PTQ (Petroleum Technology Quarterly) (ISSN No: 1632-363X, USPS No: 014-781) is published quarterly plus annual Catalysis edition by EMAP and is distributed in the US by SP/Asendia, 17B South Middlesex Avenue, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. Postmaster: send address changes to PTQ (Petroleum Technology Quarterly), 17B South Middlesex Avenue, Monroe NJ 08831. Back numbers available from the Publisherat $30 per copy inc postage. T he end products obtained through the chemical recycling of plastic wastes can be used as fuels, lubricants, or feedstocks for chemicals production, contributing to a more sustainable and circular economy. However, the efficiency and economic viability of chemical recycling processes can vary depending on the specific feedstock and the desired end products. The chemical recycling of pyrolysis oil (from plastic waste) typically involves refining or upgrading the oil to improve its properties or convert it into specific chemicals. This can be done through processes such as hydrotreating, hydrocracking, and other chemical reactions. The goal is to produce higher-quality products that can be used as fuels, chemicals, or feedstocks for various industrial applications. However, some sceptics in Europe, the US, and elsewhere say the technical challenges run much deeper than previously expected, including contaminants poisoning of hydroprocessing catalysts, energy consumption, and emissions. The landscape of waste management and recycling initiatives can change rapidly, though, and new developments in one small pilot plant or research project could resolve these hurdles. Steady progress is expected in 2024 to fund scale-up to commercial production of chemical recycling of plastic waste-derived pyrolysis oil to its basic monomer. Although there are already proven technologies for producing propylene, polypropylene, and other plastics precursors, these are single-use, non-circular routes. Public campaigns to arrive at an international treaty limiting single-use plastics production coincide with calls for the implementation of Extended Producer Responsibility policies. This would make plastics manufacturers responsible for the entire life cycle of plastic products, and may incentivise resolutions of the many challenges associated with expanding chemical recycling of plastic wastes. Despite the 2022 Inflation Reduction Act that could provide up to $1 trillion for ‘green’ investments (possibly including biomass or plastics chemical recycling to valuable products like PVC), billions of dollars continue to pour into the conventional fossil fuel industry, including refinery and petrochemical projects in the Middle East, Saudi Arabia, and China. Regardless of the increased use of EVs, solar, and other ‘green’ energy alternatives, global oil demand in 2024 is set to grow year on year by an impressive 2.2 million bpd, supported by steadily rising road mobility in major consuming countries, such as China, India, and the US. The IEA estimated growth in demand for petrochemical products means that petrochemicals are set to account for nearly half of growth in oil demand to 2050, ahead of diesel, SAF, and maritime fuel. It is no secret that refiners can sell fuels for $550/ton or else convert fossil-based feedstocks to petrochemicals and earn around $1,400/ton, such as with the integrated refinery and petrochemical facilities in India. Against this backdrop, it is projected that global production of thermoplastics will amount to 445.25 million metric tons per year (mmtpy) in 2025. Annual production volumes are expected to continue rising in the following decades to approximately 590 mmtpy by 2050. While the percentage from chemical recycling of plastic waste contributing to that 590 mmtpy seems insignificant, the fossil fuel industry seems confident that steady technical improvements will allow the upgrading of higher volumes of plastics waste-derived pyrolysis oil through refinery hydroprocessing units. The profitable link between plastics and fossil fuels may have provided a lifeline for Big Oil, including the refining industry. This begs the question: why invest in chemical recycling of plastic waste? With the prospect of a global treaty that limits noncircular, single-use plastics production, it could be a big winner. Rene Gonzalez, Editor, PTQ PTQ Q1 2024 q1 ed com.indd 3 3 11/12/2023 11:38:41 es ot N Process Vacuum tower cutpoint delivers profits Cutpoint Concerns Crude unit vacuum tower performance is often critical to a refiner’s bottom line. The vacuum tower bottoms stream is valued far below the gas oil cuts, so most refineries look to minimize it. Many vacuum columns are also designed or revamped to produce a diesel cut, recovering diesel slipped from the atmospheric column that would otherwise be downgraded to VGO product. Good vacuum column performance can maximize the profitability of downstream units by removing distillate hydrotreater feed (diesel) from FCCU or hydrocracker feed (VGO) and removing VGO from coker feed (resid). One important measure of vacuum column performance is VGO/resid cutpoint. The cutpoint is the temperature on the crude TBP curve that corresponds to the vacuum tower resid yield. Vacuum column cutpoint depends on three variables: 1. Flash zone temperature 2. Flash zone pressure 3. Stripping section performance (if present) Flash zone temperature is driven by vacuum heater coil outlet temperature (COT). Increasing COT increases cutpoint. Vacuum heater outlet temperature is typically maximized against firing or coking limits. When processing relatively stable crudes, vacuum heaters with better designs and optimized coil steam can avoid coking even at very high COT (800°F+, 425°C), but poorly designed heaters may experience coking with COT below 700°F (370°C). Flash zone pressure is set by vacuum system performance and column pressure drop. Lower flash zone pressure increases cutpoint until the tower shell C-factor limit is reached, at which point the packed beds begin to flood. Vacuum producing systems are mysterious to many in the industry, so a large number of refiners unnecessarily accept poor vacuum system performance. With technical understanding and a good field survey, the root causes of high tower operating pressure can be identified and remedied. In columns with stripping trays, stripping steam rate and tray performance are important. Stripping steam rate is limited by vacuum column diameter (C-factor) and vacuum system capacity. Any steam injected into the bottom of the tower will act as load to the vacuum system, so vacuum system size, tower operating pressure, and stripping steam rate must be optimized together. Depending on the design, a stripping section with 6 stripping trays can provide between zero and two theoretical stages of fractionation, which can drive a big improvement in VGO yield. Although the variables for maximizing vacuum tower cutpoint are simple, manipulating them to maximize cutpoint without sacrificing unit reliability is not. Contact Process Consulting Services, Inc. to learn how to maximize the performance of your vacuum unit. 3400 Bissonnet St. Suite 130 Houston, TX 77005, USA pcs cutpoint.indd 1 +1 (713) 665-7046 [email protected] www.revamps.com 16/09/2020 12:05 ptq&a Q With the chemical value of hydrogen (H₂) increasing, what are the best options for extracting H₂ from fuel gas? A Neeraj Tiwari, Principal Process Engineer, Honeywell UOP, [email protected] High-yield byproducts generated by the refinery process for motor fuel, diesel or aromatics production can be highvalue secondary revenue. The typical composition of fuel gas contains H2 as ~30-50 mol%, and other major components are LPG range material. To monetise the benefit of these high-value byproducts and increase the overall profitability, a novel concept involving a dual sponge absorber can be applied to the off-gas stream (routed to fuel gas header) to recover the majority of LPG range material along with light naphtha, if any. The application of a novel dual sponge absorber will improve the hydrogen composition in off-gases to a high level (such as 70-85 mol%). This high-purity gas can then be routed to PSA to recover hydrogen efficiently having a purity of 99.9 mol%. In catalytic reforming, secondary byproducts generated include H₂, LPG, and fuel gas. Of these byproducts, the lowest value byproduct is generally fuel gas. UOP’s proprietary RecoveryMax system allows 95% recovery of hydrogen, >85% LPG recovery, and nearly 100% reformate recovery by purifying more of these byproducts and not diverting them to fuel gas. Alternative options are being explored based on where hydrogen is being used as one of the raw materials. One option is to contact the feed stream or any hydrocarbon stream with hydrogen-rich fuel gas that will absorb the hydrogen; then, the absorbed hydrogen can be used during the reaction process. Concern with this option is that it can also absorb impurities from fuel gas (such as C1, C2), which may not be desirable in the process. A Cristian Spica, Application Engineer, OLI Systems Hydrogen is an integral part of the modern energy industry and plays a crucial role in the path to net zero. Despite the strong momentum behind ‘green’ hydrogen, to stay on track for achieving net zero emissions by 2050, we will need more than a doubling of the announced investments by 2030. These investments must mature and be put into action. Therefore, considering their significant economic advantages and as part of the short- to mid-term strategy to support the development of a clean hydrogen economy, we should make use of ‘grey’, ‘turquoise’, and especially ‘blue’ hydrogen production methods. Industrial technologies currently employed for grey hydrogen production include: • Catalytic steam methane reforming (SMR) • Dry reforming (DR) • Catalytic partial oxidation (CPO) www.digitalrefining.com Q1 q&a.indd 5 More answers to these questions can be found at www.digitalrefining.com/qanda • Autothermal reforming (ATR) • Tri-reforming (TR) • Coal/petroleum coke gasification/pyrolysis. Blue hydrogen also relies on hydrocarbons but is combined with carbon capture, utilisation, and storage (CCUS) technology, which helps mitigate its environmental impact but may require additional investments. Turquoise hydrogen is produced through methane thermal pyrolysis. Each of these technologies has its own set of advantages and disadvantages based on the unique characteristics of the process. While SMR is one of the most established and widely used technologies for grey hydrogen production, it is also one of the most energy and capital-intensive processes. This is because the endothermic reaction in SMR requires heat, and the catalyst can suffer from deactivation if the fuel gas is not properly desulphurised. Additionally, in an SMR plant, there are two sources of CO₂ emissions: one from the oxidation of carbon atoms in the feedstock during reforming and shift reactions and the other from combustion in the reformer furnace. To capture all the CO₂, a post-combustion plant is required, as precombustion capture can only capture the CO₂ in the syngas. Despite these challenges, SMR is still considered one of the most efficient methods for producing grey hydrogen, especially when heat integration is part of the process design. The same efficiency advantage applies to DR, but it also faces the drawback of coke deposition on the catalyst surface. In the case of CPO, the partial oxidation of CH₄ and other hydrocarbons in the fuel gas is a slightly exothermic reaction, making it less capital-intensive than SMR. However, it initially produces less hydrogen and CO₂ per unit of input fuel compared to SMR. To produce high-purity H2, pure oxygen or an air separation unit (ASU) is needed. ATR generates syngas by partially oxidising a hydrocarbon feedstock with oxygen and steam, along with subsequent catalytic reforming. Unlike SMR, the heat for the reaction is provided within the reaction vessel, eliminating the need for an external furnace. This method allows up to 99% of carbon removal directly from the syngas, resulting in lower carbon capture costs. ATR, when combined with CO-shift and carbon capture technology, is one of the most cost-effective solutions for large-scale low-carbon hydrogen production. TRM is a combination of SMR, CO₂ reforming, and PCO in a single reactor for efficient syngas production. The inclusion of oxygen in the reaction generates in-situ heat, which can enhance energy efficiency. However, it may present challenges in terms of heat transfer and temperature uniformity in the catalyst bed. The choice of the best production process depends on several factors affecting both capital and operational expenditures, including hydrogen yield, purity, energy efficiency, flexibility, plant complexity, and raw material availability. PTQ Q1 2024 5 08/12/2023 13:54:17 ATR combines the advantages of both SMR and partial oxidation, offering a high hydrogen yield, rapid reaction kinetics, and reduced reactor number and size. OLI Systems provides unique tools for designing and safely operating grey and blue hydrogen facilities. These tools encompass a wide range of capabilities, including modelling for various production processes (SMR, ATR, TRM, CPO) for hydrogen storage, transportation, and CCUS. These tools offer rigorous mass balance, corrosion, and scaling risk assessment, considering the reactivity and phase equilibria of impurities and their potential negative impacts on plant safety and reliability. Hydrogen as well as CO₂ dense phase, especially when containing impurities, can promote corrosion in materials such as steel, pipelines, and storage tanks. Impurities like water vapour, oxygen, sulphur compounds, nitrogen compounds, and carbon monoxide can react with hydrogen to form corrosive substances, making the selection of corrosion-resistant materials essential for hydrogen transportation infrastructure. Q What contaminants removal capabilities are available to expand the SAF feedstock base? A Yvon Bernard, Business Development Manager, Renewable Product Line, Yvon.BERNARD@axens. net, Yoeugourthen Hamlaoui, Global Market Manager, [email protected], Alexandre Javidi, Alcohol to Jet Business & Technology Manager, Alexandre. [email protected], Axens u For SAF production from low-carbon ethanol through Axens’ proprietary Jetanol solution, one of the key Axens features (Atol) is an innovative and profitable technology due to its flexibility in handling a wide range of feedstocks. During the technology development, Axens, along with its partners IFPEN and TotalEnergies, developed customised analytical methods for mastering the ethanol impurities that are critical for this application. Extensive testing in pilot plants was also performed to confirm the technical ability to process virtually all kinds of ethanol: bioethanol (1G) or advanced ethanol (2G) and waste-based ethanol (from blast furnace flue gas and municipal solid waste) at various levels of dilution. Furthermore, Atol relies on its superior catalyst, which has proven to have a high tolerance to feedstock impurities and is fully regenerable. Atol catalyst provides even more flexibility by allowing the handling of feedstock quality fluctuations. In terms of ethanol, impurities are well-known and can be handled with pretreatment solutions. v For SAF production from lignocellulosic biomass via gasification route (BioTfueL), impurities are dealt with in three steps. The first is the pretreatment step, which ensures the removal of foreign contaminants such as glass, rocks, plastics, and moisture. Additionally, the pretreatment homogenises the biomass through drying and torrefaction: this step is key to enabling the utilisation of a wide array of lignocellulosic biomass, from agricultural residues to energy crops and forestry residues. In the second step, biomass gasification technology removes the inorganic (mineral, metals) and chlorine from the biomass. 6 Q1 q&a.indd 6 PTQ Q1 2024 The remaining S- or N-based impurities are removed in the syngas phase through well-known separation technologies. Its smart and flexible contaminant removal scheme allows BioTfueL to operate with any kind of biomass. This feature means more resilience for the project and gives significant flexibility in operation to the customers. Some additional feedstock, like municipal solid wastes, brings other opportunities but requires additional pretreatment and purification steps to deal with the heterogeneity of the feedstock and impurities. w For SAF production from CO₂ and H₂, purity requirements are often regulated by the downstream unit, mainly the Fischer-Tropsch reaction section for the e-fuel production. Axens dispatches its wide portfolio to cope with the common impurities found in CO₂ feedstock, including adsorbents for impurities trapping as well as washing sections, to bring the feed to the desired specifications. The final scheme of purification will depend on CO₂ project quality and is typically adapted on a case-by-case approach. Typical contaminants for FT catalyst are (sulphur, organic nitrogen, metal, NOx). Axens’ integrated scheme takes advantage of its expertise and know-how to optimise the sizing and positioning of such purification requirements. x For SAF production from vegetable oils with Vegan technology, pretreatment is also needed. Phospholipids and metals (Fe, Mg, K, Ca, Na) were the main contaminants present in the first-generation vegetable oil (soybean oil, palm oil, rapeseed oil) and could be abated with wellestablished edible oil refining technologies. The processing of second-generation waste oil (used cooking oil, animal fats) brings a wide variety of contaminants, including the same contaminants as vegetable oil, but at higher content. Pretreatment technologies are adapting to remove contaminants to acceptable levels. Higher nitrogen, sulphur and chlorine are also observed in these new feeds: nitrogen/sulphur are partially removed by pretreatment and then converted by the hydrotreatment, inorganic chloride is completely removed by pretreatment, whereas organic chloride slips to the hydroprocessing unit, which has an impact on the unit design and metallurgy selection. Polyethylene found mostly in animal fats should be removed in a dedicated section of the lipid feed pretreatment. A Andres Coy, Business Development Manager SAF, Syngas and Fuels, [email protected], Rainer Albert Rakoczy, Technology Advisor Fuel and Hydrocarbons, Syngas and Fuels, [email protected], Clariant Catalysts The potential feedstocks and process routes toward SAF are constantly increasing. Any SAF as a final Jet fuel blending component must meet very stringent specifications, as aviation fuels are the most delicate fuel products in terms of quality and stability. In addition, most of these processes need optimum reactant properties to achieve the most efficient SAF yields. Clariant offers a broad variety of catalysts and adsorbents technology to clean most feed and intermediate species in gas or liquid phase for these SAF processing technologies. This technology is primarily based on long-time experience in handling non-benign and demanding feed streams even in industries beyond refinery. www.digitalrefining.com 08/12/2023 13:54:18 Turn iron into gold? Alchemy? No. It’s chemistry. Grace, the global leader in FCC catalysts and additives, introduces MIDAS® Pro catalyst MIDAS® Pro catalyst, for resid cracking in high iron applications. offers the solution for This innovation, built on our workhorse MIDAS catalyst platform, proved resid cracking in high iron its capacity to handle even the worst Fe excursions. In commercial trials environments. Gain feed with multiple in-unit applications, MIDAS Pro catalyst demonstrated flexibility with better sustained bottoms cracking in the face of iron spikes that measured bottoms upgrading. ® ® among the highest in the industry. Diffusivity levels were consistently high, indicating no transport restrictions with concentration of Fe. This improved iron tolerance allows refiners to operate at higher iron levels which increases feed processing flexibility and profitability. Talk with your Grace partner about the advantages of MIDAS® Pro catalyst today. Learn more at grace.com grace.indd 1 08/12/2023 12:52:29 A Kandasamy Sundaram, Distinguished Technologist & Lummus Fellow, [email protected] SAF is addressed from different angles. Plastics pyrolysis, tyre pyrolysis, and vegetable oils are a few examples. They all have different types of contaminants compared with fossil fuels. Some adsorbents are used to remove some contaminants. However, they are not able to reduce the concentration significantly. Hydrotreating is required. Isoterra for vegetable oil uses hydrotreating. Plastic pyoil requires hydrotreating to reduce chlorides and nitrogen. For chemicals production, adsorbents meet the specification in some cases. produce soft sensors generated through surrogate models that will provide insights for adjustments of parameters such as temperature, pressure, and flow rates to maximise efficiency and product quality. w Predictive maintenance: AI can monitor equipment and machinery in real-time, analysing data from sensors to predict when maintenance is needed. This can help prevent unplanned downtime and reduce maintenance costs. x Production scheduling: AI can create optimised production schedules that balance production efficiency with demand fluctuations and resource constraints. A Ezequiel Vicent, Senior Application Engineer and A Ezequiel Vicent, Senior Application Engineer and Consulting Lead, OLI Systems The advent of renewable fuels has brought the necessity to change catalyst to treat the carboxylic groups in the fatty acids that make up vegetable oils (increased CO, CO₂ and H₂O production) as well as an increase in chlorides. In addition to catalyst selection, unit engineers need to focus on the production of the byproducts from these reactions. We have seen an increase in NH₄Cl salt formation out of these feeds that can foul the feed-effluent exchangers at higher temperatures. The increase in water formation (up to five times larger than usual hydrocarbon feed) means the possibility of the salts that deposit in the feed-effluent exchangers getting wet increases dramatically. Engineers need to monitor the exchangers for the NH₄Cl formation temperature as well as the relative humidity increase due to increased water content. The engineer should note that at relative humidity greater than 10%, ammonium chloride salts will start to absorb water from the vapour stream. This can cause underdeposit corrosion and pitting in equipment and piping. The equipment most at risk for this type of corrosion is the feedeffluent heat exchangers and the piping up to the reactor effluent air coolers inlet wash water injection. In this case, operations will need to invest in monitoring tools (both software and hardware) that can help them calculate salt formation temperatures, water relative humidity, and sour water concentrations (especially bisulphide concentration) to maintain static asset reliability. Q What role are AI systems expected to play when optimising plant-wide operations? A Isabelle Conso, Digital Innovation Director, Isabelle. [email protected], and Philippe Mege, Digital Services Factory Manager, [email protected], Axens AI is expected to play a significant role in optimising plantwide operations. Here are some key roles and benefits that AI systems can provide in this context: u Safety and compliance: AI can monitor safety conditions in the plant and detect anomalies or potential hazards. It can also assist in compliance with regulatory requirements by ensuring that processes and products meet the necessary standards. v Process optimisation: AI can continuously analyse vast amounts of data from various sensors to uncover patterns in view of production process optimisation. It can also 8 Q1 q&a.indd 8 PTQ Q1 2024 Consulting Lead, OLI Systems AI will play a major role in the optimisation of plant-wide operations both during steady-state times and during shutdowns and start-ups. There are many examples of how AI is being used today to optimise a plant, but the decision to go from an open system to a closed system is still a few years away< and the technology has not yet caught up. A prime example of AI being used in plant optimisation is in the area of energy and emissions management. There are energy optimisers that use first principles to look at the current energy status of the unit and are able to optimise fuel consumption and steam production while accounting for combustion emissions to minimise the amount of energy needed for the steam demand. They will account for steam Cogen units and heat integration. However, to predict future demand, AI models ‘learn’ where the peaks and valleys come in and are able to predict the input changes before they happen. This helps the energy optimiser capture changes more quickly and have additional energy savings. Another area where AI, or in this case a Machine Learning (ML) model, can make a big impact is in dynamic processes, like the start-up or shutdown of a unit. Consider a unit where a process upset occurs upstream, and a column needs to be quickly shut down with a precise sequence of events. The outcome largely relies on the operators’ experience. In such a case, a ML model can be ‘taught’ that exact sequence under varying process and environmental conditions. Various dynamic simulations can be created to show the different types of upsets that can trigger a shutdown, and the shutdown sequence can be included. The ML model, once tested against multiple simulations, can now be added as a closed-loop system and allowed to ‘operate’ the shutdown or start-up of the column to avoid damage to the unit or unwanted chemical releases. However, for more complex systems, AI still needs to evolve as a technology. Several refiners we have worked with have started on the path of AI implementation but have stopped short of full ‘autonomous plant’ systems. We have heard that the complexity of the processes at the refinery and the constant variation of feedstock and pricing have made it difficult to gain value from full AI implementation. A Lisa Krumpholz, CSO, Navigance GmbH, Lisa. [email protected] The major challenges of optimising plant-wide operations www.digitalrefining.com 08/12/2023 13:54:19 solenis.indd 1 08/12/2023 13:01:07 are the vast amount of data available and the high complexity of interconnected unit operations. Traditional first-principles models and tools for optimisation have disadvantages in coping with these challenges as they usually require high effort and thus cost to develop, maintain, and adapt to changes in the operation. In contrast, AI systems with machine learning-based models at their core can be designed with reasonable effort for complex systems. They offer the opportunity to learn automatically from continuous data streams in the plant and adapt quickly to changing conditions. Thus, AI systems will see rapid adoption in the coming years to replace, complement or enhance existing optimisation approaches. Like the developments in autonomous driving, AI systems are expected first to be adopted as assisting systems to support and enable better human decision-making for plant-wide optimisation. Q Gasoline, diesel, and aviation fuel are still expected to dominate refinery markets to 2030; what reactor and catalyst systems will be the most effective in maximising fuel production? A Pierre-Yves le-Goff, Global Market Manager Reforming and Isomerisation, [email protected], Laurent Watripont, Clean Fuels Technologies Director Expert, [email protected], Christophe Pierre, Reforming Product Line Manager, Gasoline Product Line Technology and Technical Support Business Division, [email protected], Matthew Hutchinson, Senior Technology Manager, Gasoline and Petrochemical Technologies, Technology Dept., Matthew. [email protected], Axens For gasoline production, among the building blocks of the gasoline pool, we can mention isomerate and reformate. For reforming, maximisation of gasoline production is linked to a reduction of cracking while ensuring a stable operation. The addition of modifiers is one of the possibilities to reduce cracking; however, rigorous selection process is needed to ensure that stability and regenerability are not impacted. Axens, formerly Procatalyse, has been involved in such a field of expertise since the mid-1990s. From a process standpoint, reduction of the pressure will improve the fuel production. However, such a reduction needs to be compatible with unit constraints (for example, pressure drop). To mitigate these pressure drops, a possibility is to move from a standard axial flow reactor to a radial flow reactor. Axens has already performed such modifications and has proprietary internals to improve gas distribution. On the isomerisation side, depending on the octane target and feed composition, different schemes can be proposed. For example, if the feed is rich in C6 paraffin, the deisohexaniser (DIH) column can be implemented to maximise octane without selectivity debit. In addition, to reduce cracking, the use of high-activity catalyst is of paramount importance. Therefore, Axens process expertise with ATIS-2L catalyst provides the best combination for isomerisation unit optimisation. 10 Q1 q&a.indd 10 PTQ Q1 2024 A Johanna Fernengel, Product Manager, Syngas and Fuels, [email protected], and Rainer Albert Rakoczy, Technology Advisor Fuel and Hydrocarbons, Syngas and Fuels, [email protected], Clariant Catalysts Besides topping upgrading, the key to maximising fuel production is the right balance of hydrocracking (HC), delayed coking (DC), and catalytic cracking (FCC), as this gives the highest flexibility in utilising nearly any crude source, including renewable sources. In particular, utilisation of the light olefins from the FCC off-gas with alkylation and oligomerisation with alternative concepts can give a higher flexibility, moving from sole gasoline focus towards distillates as potential diesel and jet blending components. A Ioan-Teodor Trotus, Team Leader Refining, Ioan- [email protected], hte GmbH Which reactor system will be the most effective depends on multiple factors, such as the feed or feed mix to be converted, the actual fuel to be produced – diesel, gasoline, or aviation fuel – and, of course, on which reactors are already operating in the refinery. For a refinery that aims to convert mainly crude oil with existing plants – be it hydrotreaters, hydrocrackers or FCC units – pilot plant tests will yield the most reliable results for choosing the right catalyst system. The right catalyst system must show a reasonable level of activity and stability to maximise the duration of an operating cycle. This can be determined in pilot plant testing either as the start-of-run activity or by performing accelerated deactivation studies to estimate the mid-run or end-of-run activity. At the same time, pilot plant testing will give information about the yields and properties of each fuel fraction, allowing one to feed a techno-economic model with actual plant data and make a like-for-like comparison of all the catalyst systems to be compared. For a refinery aiming to co-process or process renewable feedstocks in existing equipment, a pilot plant test is even more important because it also allows the operator to see a new application in action before testing in a production unit. The number of industrial references for the conversion of renewable fuels is still relatively low compared to the number of references for the conversion of crude-derived feeds. Simply relying on models and paper studies is particularly risky in these cases, as such models still have relatively little data on which to build their estimates. In short, the most effective catalyst – be it for hydroprocessing or FCC applications aimed at the production of fuels and the conversion of renewables – will most likely be the one that was determined by a pilot plant test. A Kurt du Mong, CEO, Zeopore Technologies A key value creator in the refinery, specifically to yield fuels, remains the hydrocracker. These units feature multicomponent catalysts involving NiW or NiMo hydrogenation components supported on acidic zeolite/alumina carriers. These types of catalysts have gone through generations of remarkable developments, particularly with respect to the optimisation of the zeolite component. www.digitalrefining.com 08/12/2023 13:54:20 Over the last decade, it has become clear that optimising the zeolite’s mesoporosity and macroporosity enables the control of the degree of cracking, thereby maximising the yield of fuels, which was demonstrated in a selection of refineries. However, thus far, mesoporous zeolite-based hydrocracking catalysts have been associated with inhibitive cost increases and lower conversion levels, limiting their widespread application. Zeopore helps to overcome such limitations via a platform of affordable USY zeolites, yielding selectivity and activity benefits of a wide range of catalyst types and zeolite contents. Zeopore’s mesoporised hydrocracking zeolites have recently been tested in a high throughput facility of a major refiner, generating up to 4 wt% more middle distillates at retained activity levels, generating $15 million more profit per average hydrocracker (see Zeopore press release: www.zeopore.com/post/zeopore-enables-breakthrough-in-hydrocracking-by-leveraging-zeolite-mesopore-quality) Q How is the dual focus on increasing butylene and propylene production being met? A Alvin Chen, Global Technology Application Manager, Hernando Salgado, Technical Service Manager, BASF While butylene pricing is often quite stable (typically either very high or very low), propylene pricing has seen significant volatility over the past few years. One approach that many refiners have adopted, to address the dual focus on butylene and propylene production, is to formulate a base FCC catalyst with moderate overall LPG= selectivity and an emphasis on strong C₄= selectivity. Such a catalyst coupled with judicious usage of ZSM-5 offers excellent C₄= selectivity during times when C₃= value is low. However, it still allows the refiner to capture short-term C₃= opportunities while maintaining a strong C4= yield. One strategy for the optimum base catalyst is to optimise the acid site distribution on the catalyst by increasing total surface area while reducing acid site density, allowing similar catalytic activity with reduced hydrogen transfer. Since it is known that butylenes are more sensitive than propylene to hydrogen transfer effects, a catalyst with this approach will target both products depending on process conditions and externally added ZSM-5. BASF applies this catalyst design approach in the Multiple Frameworks Topologies (MFT) technology, where secondary zeolite frameworks are also used to further improve butylenes to propylene flexibility. Catalysts like Fourte and Fourtune for VGO applications and Fortitude for resid applications are examples of the MFT catalyst technology for FCC units. It should not be forgotten that operating conditions, such as catalyst-to-oil ratio and reactor outlet temperature, also have an impact on butylenes to propylene distribution, with butylenes favoured at mild severity conditions, while propylene is favoured at high severity conditions. A Stefan Jäger, Applied Catalyst Technology Engineer, [email protected], www.digitalrefining.com Q1 q&a.indd 11 Rainer Albert Rakoczy, Technology Advisor Fuel and Hydrocarbons, Syngas and Fuels, [email protected], Clariant Catalysts In traditional refining, the catalytic cracker (FCC) is the source for light olefins such as propylene and butylenes. In many countries, demand for gasoline is shrinking as individual transportation is the most influenced section during the energy transition, moving to lean consumption engines, plug-in hybrids or fully electric-driven solutions. Thus, the product slate behind FCC calls for more distillates and light olefins and less gasoline. Cracking technology providers can offer revamp solutions to follow these requirements (second riser and modified catalyst solution). Clariant can offer adsorbents and catalysts to clean these streams, delivering highpurity light olefins over the fence or utilising these olefins in the refinery grid toward fuels or even chemicals. A Cai Zeng, Head of PDH Strategic Marketing and Product Management, Propylene Catalysts, Cai.Zeng@ clariant.com, Clariant Catalysts Petrochemicals customers are now looking for unique and extremely reliable technology for co-processing butane and propane to meet both increasing butylene production and propylene demand. Catalysts such as Clariant’s highly selective Catofin catalyst and the company’s patented metal-oxide HGM allow for thermodynamically advantaged reactor pressure and temperature to achieve a high conversion rate and maximised yield. One example is the Hengli Group’s world’s largest mixed-feed dehydrogenation plant in China using the Catofin technology. The plant is designed to process 500 KTA of propane and 800 KTA of iso-butane feeds to produce propylene and iso-butylene. A Kandasamy Sundaram, Distinguished Technologist & Lummus Fellow, [email protected] On-purpose propylene routes are satisfying the demand to some extent. FCC and olefin conversion technology satisfy some additional capacity in addition to thermal cracking. Butene-1, Butene-2, and isobutene have different markets. Due to the decline in the MTBE market, isobutene is not requested by our clients. The dimerisation of ethylene is meeting some demand. A Victor Batarseh and Bani Cipriano, W. R. Grace & Co. The FCC unit is a key source of both propylene and butylene. While the primary drivers for propylene and butylene demand are different, there is some overlap in the factors that influence their production in the FCC. Propylene demand stems mostly from the demand for polypropylene and other chemicals such as acrylonitrile and cumene. Meanwhile, butylene demand primarily stems from the production of high-octane alkylate used as a blending stock for gasoline. The FCC can produce high amounts of propylene and butylene, and to increase their production, refiners have process knobs available such as feedstock selection, implementation of FCC product recycles, adjustment of cat-to-oil ratio, and hydrocarbon partial pressure (among others). At times, the knobs previously listed are not sufficient to bring refiners to a truly optimised yield slate with respect to PTQ Q1 2024 11 08/12/2023 13:54:20 C3= Yield vs. Conversion 8.0 8.0 7.5 7.5 Total C3= Yield (vol%) Total C4= Yield (vol%) C4= Yield vs. Conversion 7.0 6.5 6.0 5.5 Base Base w/GBA 5.0 60 62 64 66 68 70 72 7.0 6.5 6.0 5.5 Base Base w/GBA 5.0 74 Conversion 60 62 64 66 68 70 72 74 Conversion Figure 1 Yield shifts from an FCC implementing GBA, where the FCC observed increased butylene and propylene yields of approximately 1 vol% at equivalent conversion levels propylene and butylene production. In this case, collaboration with the FCC catalyst partner is required to evaluate catalytic solutions that bring another degree of freedom to solving this challenge. To target increased LPG olefin production, it is important to ensure the FCC base catalyst drives appropriate levels of gasoline yield and olefinicity. The resulting gasoline olefins are then cracked into smaller LPG olefins via the incorporation of a pentasil zeolite technology. While this overall approach holds for both propylene and butylene, the choice of catalyst and pentasil technology can influence whether butylene or propylene selectivity is maximised, as will be explained in more detail. Butylene Grace’s approach to increasing butylene yields is twofold. Starting with a base catalyst that supplies sufficient conversion and gasoline olefinicity is key. Building on that foundation, Grace supports customers with both additivebased and catalyst-oriented solutions. For refiners who 2.0 require flexibility to quickly manipulate butylene yields with the backdrop of shifting constraints or feedstock availability, an additive solution is recommended. GBA can be implemented to quickly increase butylene without as much propylene increase as a traditional ZSM-5 additive. Figure 1 shows yield shifts from an FCC implementing GBA, where the FCC observed increased butylene and propylene yields of approximately 1 vol% at equivalent conversion levels. When refiners consistently require higher butylene yields, Grace considers adjustments to base catalyst formulation to incorporate both Y and pentasil zeolites with its proprietary Achieve 400 platform of catalyst, which delivers impressive butylene yields and selectivity. Incorporating the pentasil zeolite functionality directly into the base catalyst with optimised active-matrix surface area, zeolite-to-matrix surface area ratio, pore distribution, and Y-zeolite stabilisation maximise butylene yield and selectivity while also improving gasoline octane and LPG olefinicity. Achieve 400 Prime is the latest development on the butylene selective catalyst platform and delivers the highest butylene yields, selectivity, and LPG olefinicity. Figure 2 demonstrates the step-out butylene yield and selectivity performance of Achieve 400 Prime relative to competitor butylene selective catalyst. Total C4= /wt. % 1.5 1.0 0.5 0.0 -0.5 Competitor Grace -1.0 -5 -4 -3 -2 -1 0 1 Conversion / wt. % Figure 2 Butylene yield and selectivity performance of Achieve 400 Prime relative to competitor butylene selective catalyst 12 Q1 q&a.indd 12 PTQ Q1 2024 Propylene As in the case of butylene maximisation catalyst systems, when selecting a catalyst for maximising propylene, the need for conversion is balanced against minimising hydrogen transfer reactions to preserve gasoline-range olefins. Traditionally, to minimise hydrogen transfer, max propylene catalysts are designed with low unit cell size and a cokeselective matrix. Max propylene catalyst systems include a ZSM-5 technology that cracks gasoline olefins into LPG olefins while shifting the selectivity towards propylene. FCCs with a high propylene yield of 11 wt% or higher are not uncommon. In these cases, a high addition rate of ZSM-5 is used. Relative to a lower activity ZSM-5 additive, using the www.digitalrefining.com 12/12/2023 15:45:36 highest activity ZSM-5 results in reduced additive consumption for a similar or higher propylene yield. Since ZSM-5 can only crack gasoline-range molecules, using a large amount of ZSM-5 additive results in a dilution of the base catalyst activity and lower conversion of feedstock into gasoline olefin precursors. The main benefit then of using a high-activity additive is to minimise the dilution of the base catalyst activity vs the use of a loweractivity ZSM-5 additive. To maximise propylene, Grace recommends using high-activity ZSM-5 additives from its OlefinsUltra family of additives or its newest innovation in ZSM-5 technology, Zavanti additives. In summary, refiners are adopting a variety of strategies to increase butylene and propylene from the FCC, depending on their specific hardware constraints, downstream handling limits, and regional economics. FCC catalysts and additives are key elements of the strategy as well, given the flexibility they offer and the dynamic nature of the FCC unit operation. A Ezequiel Vicent, Senior Application Engineer and Consulting Lead, OLI Systems The dual focus on increasing butylene production and propylene production is being met with ZSM-5 technology and a propane/propylene (PP) splitter (50-300 MMUSD). Refiners on the US West Coast and the Gulf of Mexico are best positioned to take advantage of an increase in the production of butylene and propylene. However, market www.digitalrefining.com Q1 q&a.indd 13 drivers and asset characteristics will dictate the extent of the benefit realised. Increasing the production of propane, propylene, and butylene can be achieved by introducing additives to the FCC catalyst, the zeolite ZSM-5. This ZSM-5 will help in the cracking and production of butylene and propylene. The butylene will be used at the alkylation (sulphuric or HF acid) unit to produce alkylate, a gasoline-range material almost void of contaminants and aromatic components and makes an excellent blending component in the gasoline pool. Whenever there is insufficient butylene or a market need for increased alkylate, propylene can also be added to the alkylation unit. However, the propylene can be cleaned at a PP splitter and further refined to either chemical-grade propylene (92-95 mass% propylene) or polymer-grade propylene (99.5 mass% and greater). If a refinery does not have a PP splitter as an asset, the butylene/propylene or propane/propylene mix can be sent to the gas plant and recovered as ‘refinery gas’, which can be later used as fuel to the various furnaces in the refinery. The investment to design and install a PP splitter at a refinery is not small. Pre-COVID estimates put the total cost of the project at around 300 million US dollars (2019) on the West Coast (California) and around 50 to 100 million US dollars (2019) in the Gulf. The three-to-one ratio difference is due to labour and materials costs on the West Coast. PTQ Q1 2024 13 08/12/2023 13:54:24 We have more seats on codes and standards committees than all the majors combined. LEADERSHIP POSITIONS ACTIVE MEMBERSHIPS AMPP API ASCE ASME GPA MTI AMPP API ASCE ASME ASTM AWS CSA DOE GPA MTI PVP US TAG LEADERSHIP POSITIONS (Former) API ASME ASTM OTHER VALUE EXPERTISE More than just general knowledge as to what the standards specify; we provide expert insight as to why. RISK REDUCTION A deeper understanding of code requirements yields improved solutions that reduce risk. COMPLIANCE Compliance is ensured with an advanced insight to the depth and breadth of industry requirements. COST SAVINGS Gain deep industry knowledge without the time and cost to attend hundreds of industry code committee meetings each year. ADVOCACY We promote code development and improvements based on client feedback and industry needs. BECHT.COM/CONTACT /COMPANY/BECHT becht.indd 1 08/12/2023 12:49:36 Adding CHP to refinery power infrastructures CI scores and delivered economic impact at downstream facilities improve when adding CHP units to increase electrical and thermal efficiency Rene Gonzalez Editor, PTQ I mplementing combined heat and power (CHP) plants fuelled by natural gas (NG), renewable natural gas (RNG), or hydrogen can reduce refinery operating costs during normal run lengths or extended downtime for a unit revamp. The end game is a huge reduction in the process gas emissions footprint. Financially, this means that with proper equipment selection and layout design, the return on investment (ROI) of the CHP cogeneration power plant in the refining and petrochemical industry could be less than a year. Cogeneration facilities have been a mainstay in commercial and industrial facilities worldwide, with capacities approaching 100 MW in various applications. In addition, CHP cogeneration units under 20 MW are used throughout the oil and gas industry, including the refining and petrochemical sectors, particularly during a major revamp or turnaround, as well as during normal operations. Although the demand for CHP units has remained relatively flat until recently, that market is projected to expand as these portable systems are part of the broader effort towards transitioning to more sustainable energy sources, reducing GHG emissions, and promoting circular economy practices by reusing waste materials, such as in the production of RNG. For example, combining CHP units powered by fuels such as RNG or hydrogen benefits project carbon intensity (CI) scores in the long term. Energy efficiency Downstream processing facilities have significant energy requirements, both for electricity (compressors, pumps) and thermal energy (heat and steam), making CHP systems an efficient and cost-effective solution for the following applications: Steam and power generation: Refineries use steam for various processes, including distillation, desalting, and heating. CHP systems can simultaneously generate electricity and steam, optimising energy use and reducing overall energy costs. Waste heat recovery: Refineries produce a substantial amount of waste heat as a byproduct of their operations. CHP systems can capture and use this waste heat to generate electricity or provide supplementary process heating, improving energy efficiency. Process heating: High-temperature heat is often required www.digitalrefining.com RENE.indd 15 for specific processes. CHP systems can provide this heat, reducing the need for separate heating systems and improving overall energy efficiency. Energy cost reduction: By generating electricity on-site, refineries can reduce their reliance on external power sources, potentially leading to cost savings, particularly when energy prices are high. Environmental benefits: CHP systems can help reduce greenhouse gas emissions (GHG) and other pollutants, as they are more energy efficient compared to traditional power generation methods. Energy security and reliability: CHP systems enhance the reliability of power supply in refineries, offering a back-up power source during grid outages or other disruptions. Specific configurations of CHP systems in a refinery or petrochemical unit will depend on the plant’s energy needs, available energy sources, and operational processes. The choice of technology, such as gas turbines, steam turbines, reciprocating engines, will also be based on the refinery’s specific requirements, such as the volatile process of upgrading refinery-grade propylene to higher margins polypropylene via thermocompression benefits from an integrated CHP and chiller design to balance cooling water requirements. In some cases, refineries and chemical plants with CHP systems can contribute excess electricity back to the grid, potentially earning revenue through power sales. CHP technology can be deployed quickly, cost-effectively, and with few geographic limitations. Natural gas-powered CHP has quietly provided highly efficient electricity and process heat to some facilities. Improve CI scores To date, NG-powered CHP operations provide the leverage to decouple from grid electricity affected by high GHG emissions and unreliable grid connectivity. In the future, combining RNG and NG, or pure RNG, improves a facility’s CI scores, but other factors also influence whether a refinery or chemical plant benefits from CHP. For example: • Would there be substantial business, safety, or health impacts if the electricity supply were interrupted, such as during a major turnaround or weather-related outage? • Is there interest in reducing a facility’s impact on the environment? PTQ Q1 2024 15 08/12/2023 14:59:50 Conventional generation Power station fuel (US average fossil fuel) 155 units fuel Combined heat and power (CHP) Power plant Electricity 52% efficient Electricity Annual consumption Boiler Heat Boiler fuel (Gas) 36 units Electricity 44 units Heat Combined heat and power (CHP) 1 MW Natural gas reciprocating engine CHP fuel (Gas) 100 units fuel Heat TOTAL FUEL EFFICIENCY 80% efficient Figure 1 EPA-sourced diagram comparing conventional generation vs CHP • Are there concerns about the impact of current or future energy costs on the business? • Does the facility operate at high utilisation rates? • Are there plans to replace, upgrade, or retrofit central plant equipment (such as generators, boilers, and chillers) within the next three to five years? Overall, integrating CHP into a facility demonstrates a commitment to sustainable practices and environmental stewardship, enhancing the facility’s reputation and appeal to environmentally conscious consumers and stakeholders. CHP systems are one of the most direct pathways towards reducing carbon intensity and increasing RNG’s value. Opportunities For these bespoke circumstances, CHP has proven its ability to offer a variety of benefits, including avoided capital costs, revenue stream protection while reducing exposure to electricity rate increases from the grid. Against this backdrop, NG or RNG-powered CHP will positively impact carbon scores vs the grid’s supply mix. By using waste heat recovery technology to capture wasted heat associated with electricity production, CHP systems can typically achieve total system efficiencies of 60-80%, compared to 50% for conventional technologies (such as purchased utility electricity and an on-site boiler). In fact, the Waste Heat & Carbon Emissions Reduction Act encourages the development of small CHP projects of less than 20 MW. This includes CHP/NG/RNG/microgrid applications at facilities without temporary or permanent grid access. Basically, they need less fuel, including tail gas, for a given unit of energy output. Operating costs are further reduced because the CHP output reduces electricity purchases. Through on-site generation and improved reliability, CHP can allow facilities to continue operating in the event of a disaster or grid interruption, thus protecting revenue streams from the increasing drop in grid reliability, such as the hurricane-prone US Gulf Coast refining region. Unfortunately, the drop in grid reliability is co-occurring with electricity rate increases. Because less electricity is purchased from the grid using CHP, facilities have less exposure to rate increases. CHP units can be configured to operate on a variety of fuel types, such as NG, RNG, biogas, hydrogen, or a combination thereof. Therefore, a facility could build in fuel-switching capabilities to hedge against high fuel prices. With the passage of the US Inflation Reduction Act (IRA) and its full implementation 16 RENE.indd 16 PTQ Q1 2024 in 2024, flat demand for CHP seen over the past decade will increase linearly for RNG-powered CHP units. Paybacks To further generate credits, The IRA reduced ‘direct pay’ timelines, increasing paybacks from CHP projects with built-in efficiencies, resiliency, and sustainability. All signs suggest that RNG projects fuelling CHP units will grow significantly in 2024. RNG economics increase with CHP utilisation, exhibiting a linear relationship between improved CI score and improved RNG market value. The Wall Street Journal recently predicted that RNG may make up nearly 30% of the total natural gas supply by 2040 compared to less than 1% today. Against this backdrop, tax and regulatory-driven incentives (renewable identification numbers [RINs], Low Carbon Fuel Standard [LCFS]) can facilitate the pace and permitting pathways to RNG and CHP integration, such as identifying the necessary permits and approvals required for RNG and CHP components of the project. Notwithstanding, every effort should be made to maximise LCFS and Investment Tax Credits (ITC) in addition to RINs under the Renewable Fuel Standard (RFS) programme. This is the reason why CHP projects are seen in other industries. CHP market growth in the refining and petrochemical industry may soon follow. However, according to some experts, CHP downstream applications in Europe, The Middle East, and other major refining regions outside North America seem minimal to nothing, perhaps because IRA, US Environmental Protection Agency (EPA), and other similar types of government incentives are not available in other regions. For more near-term prospects, biogas (biomethane) and RNG-powered CHP projects can be implemented now. RNG, meanwhile, can be generated from the direct gasification or pyrolysis of biomass. “The high methane content of RNG allows for full compatibility within pipeline systems. CHP fleets that run on natural gas require minimal upgrades to be fuelled by RNG and would produce immediate emission reductions by transitioning,” the CHP Alliance noted. EPA support On the market front, evolving opportunities include the outgrowth of Power Purchase Agreement (PPA)-style contracts, which can be designed for heat and power purchases. The EPA’s CHP Partnership programme aims to promote www.digitalrefining.com 08/12/2023 14:59:51 BLEED TRIM LEED RIM Meet th people behind solutio Only ActiPhase® active filtration technology comes with years of proven performance. Plus, technical experts who don’t play around when it comes to optimizing filtration. Get yours today! Vika Field Repres Discovery is wh developing new scoping out the knows that cre adaptability are optimizing perf where a job tak MANTRA PHILOSOPHY Optimize INTERESTS crystaphase.com crystaphase digital.indd 1 19/12/2023 11:42:17 We fight the scum of the earth. And we do it equipped with super-powered products and technologies we developed, tested, perfected and proved in hundreds of applications throughout the world. Optimize crystaphase.com crystaphase digital.indd 2 19/12/2023 11:42:29 the adoption of CHP systems across different industries and sectors. The programme provides technical assistance, tools, and resources to help organisations and businesses assess the feasibility of CHP projects and facilitate their implementation and certification. This programme includes all types of CHP applications. While not directly administered by the EPA, various federal and state-level renewable energy incentives may apply to certain facilities that utilise CHP. These incentives could include tax credits, grants, or other financial benefits aimed at promoting clean and renewable energy sources. The EPA occasionally offers grant programmes supporting clean energy projects and initiatives, including those involving CHP and RNG. EPA grant opportunities are typically designed to reduce GHG emissions and promote sustainable energy practices. The EPA’s Combined programme aims to highlight the benefits of CHP in improving energy efficiency, resiliency, and reliability for critical infrastructure and facilities, which could be relevant for chemical processing facilities looking to enhance their energy systems with CHP (see Figure 1). IRA and RIN credits Along with these bespoke opportunities, state-driven efforts to boost distributed generation are opening new pathways for non-traditional CHP entrants. The IRA will allow production tax credit (PTC) and investment tax credit (ITC) recipients to monetise credits through the previously mentioned ‘direct pay’ option or by selling all or a portion of the credits. With these incentives covering as much as 30% of project cost, the payback timeline decreases. CHP projects are more attractive with their built-in efficiency, resiliency, and sustainability. Going forward, the onus on achieving circa 20% LCFS reduction by 2030, and even more so by 2040, predicates the development of RNG-powered CHP units demonstrating highly negative CI scores. RNG-based CI score ranges benefit from combined value delivered LCFS and D3 RINs, as well as D5 RINs (RINs is the RFS programme’s ‘currency’). When considering value ranges to produce RNG, such as the -100 to -400 CI scale, adding value from LCFS compounds the attractiveness of RNG-powered CHP projects. Using a more specific demonstration, the value of dairy RNG = (D3 + LCFS) or RNG = ($37 [for D3 RIN @ $3.15/RIN]) + (LCFS = $65 [with a CI of -225]) is what is driving RNG/CHP. If a refinery, such as one in California, uses a certain amount of RNG for cogeneration originating from agricultural or dairy waste, it can demonstrate sustainable performance in a circular economy. Note that the $37 is from the Federal RFS RINs programme, the $65 is from the California LCFS programme, and the commodity value of the gas is just $2. Although CI scores are typically discussed without units, it is actually measured in grams of CO2 equivalent per megajoule. Because of the combined value delivered by RFS RINs and California LCFS, interesting programmes are also developing for RNG/CHP projects in other industries, such as the plastics industry. Under the RFS programme, every feedstock and fuel type has a specific ‘D’ code of RINs. With RNG, there are pathways for qualification as a D3 RIN or D5 RIN. For example, D3 ($3.15/RIN) is generated from a www.digitalrefining.com RENE.indd 17 cellulosic-based feedstock (landfill gas, wastewater treatment plant, or any other feedstock with a 75% or greater adjusted cellulosic content). If a D3 RIN cannot be generated, then a D5 ($1.87/RIN) can be generated as long as it is renewable biomass. However, that gap (or spread) has been wider in the past at about 4x or 5x difference. So, many planners, including a few refiners, are targeting those cellulosic feedstocks to capitalise on the higher value D3 RIN. Existing pathways In this early stage of incentives implementation, it is likely to be seven to 10 months from commercial operation before LCFS credits are awarded. This expected revenue needs to be planned for, understanding that incentive payments may not be realised for at least seven months before obtaining a registered certification pathway under an LCFS. The credit must then be generated and sold. A common business practice among corporate planners involves banking and planning for about 10 months of limited LCFS cash flow. The RIN usually falls within that period because the RNG is being stored during that time. The important aspect to understand is that earned value is not lost during those 10 months. Certain accounting exercises allow for the virtual storing of the RNG. The bottom line is that patience is necessary to fully monetise value from the RIN and LCFS pathway during that 10-month delay. The LCFS also has a process where a temporary pathway can be used to generate credits upon submitting an application. That temporary pathway can be as much as -150 CI for cellulosic feeds, so a lot of revenue could be left on the table using that temporary pathway because the project is expected to provide CIs in the -200 to -400 range. It boils down to an economic exercise as to what works for a given project. Otherwise, carefully budgeting and planning for those seven to 10 months is good practice. So, it is more of a timing delay until you receive that LCFS credit. Alignment We are seeing the coalescing of regulations, business practices, and technical advancements favouring RNG-powered CHP systems. They are well suited for applications with very negative CI scores associated with lucrative LCFS values. In the US, the Fuel LCA model is used to measure the same (low CI ~ high $ value). Organisations like the Combined Heat & Power Alliance provide monetisation support to the CHP industry, particularly through CHP Technical Assistant Programs (TAPs). Such alliances help deploy CHP more effectively, which is why the CHP market is projected to be worth $35.2 billion by 2026. Adding CHP to a facility not only increases CI scores but also has a positive economic impact on the project. The IRA extends the ITC of 30% and PTC of $0.0275/ kWh (2023 value) until at least 2025. However, projects over 1 MW AC must meet prevailing wage and apprenticeship requirements. Overall, CHP is a valuable technology that can offer many benefits to facilities. By integrating CHP, processing facilities can demonstrate their efforts at reducing their environmental impact, saving money on energy costs, and improving their operational resilience. PTQ Q1 2024 17 08/12/2023 14:59:52 ITW Innovative Technologies Worldwide IMPROVE SUSTAINABILITY: OUR MISSION SUSTAINABLE DEVELOPMENT GOALS ACHIEVED AT NO ADDITIONAL COSTS ITW proprietary technologies enable improved sustainability in that, among the others, they: Reduce CO2 and greenhouse gas emissions Reduce VOCs Reduce waste generation and disposal Reduce energy consumption Improve energy efficiency Improve Operational Excellence Promote safe working environments ITW Online Cleaning clean an entire Unit in as little as 24 hours on a feed-out/feed-in basis. ITW Onstream Cleaning clean an entire Unit during the run. Our proprietary chemistries dissolve and stabilize any asphaltenic/paraffinic/polymeric deposits, by transforming the same into a fully reusable/reprocessable liquid. When applied to tank cleaning, our technologies effectively, safely and quickly recover oil from sludge, thereby eliminating waste generation and disposal. Pro-active application of our cleaning technologies reduces CO2 , VOCs and greenhouse gas emissions, while reducing energy consumption thereby getting additional value by improved Operational Excellence. ITW proprietary technologies promote safe working, as they eliminate/reduce mechanical cleaning operations as well as working in confined spaces. Our Improved Degassing/Decontamination technology has unrivalled performance all in terms of contaminants elimination, quick safe entry achievement, waste disposal elimination and environmental compliance. Our patented chemistry does not create any emulsion and fluids can be easily handled by Waste Water Treatment Plant. Other proprietary technologies also include: Amine Unit Optimization, Sulphur Dissolution, Ethylene Furnace Run Length Increase, Cleaning of Texas Towers/Packinox, Coke on catalyst Formation Reduction, Diesel/Fuel Oil Particulate and NOx Emission Reduction. ITW technologies can be applied to all the Oil & Gas Industry, including the Transportation and Energy Production industries. Sustainability improvement can be achieved by process optimization, without any major investment. CONTACT ITW TO LEARN HOW IMPROVED SUSTAINABILITY CAN BE ACHIEVED NOW AT ADDITIONAL VALUE For more information contact: ITW S.r.l.- C.da S.Cusumano - 96011 Augusta - Italy Tel. +39 (0931) 766011 E-mail: [email protected] www.itwtechnologies.com Hiring Professionals Worldwide Join ITW Team worldwide and send your Curriculum Vitae to : [email protected] itw.indd 1 09/09/2022 11:49:53 Filtration and separation for industrial carbon capture, transport, and storage Novel filtration and separation products and a deep understanding of material science and fluid contamination characteristics are needed to reduce the Opex of carbon capture Lara Heberle and Julien Plumail Pall Corporation I n addition to electrification, hydrogen, and other clean energy technologies, large-scale carbon capture, utilisation, and storage (CCUS) is critical to achieving netzero 2050 goals. These goals were set forward by the International Energy Agency (IEA) in 2021 as a challenging path to restrict global temperature rise to 1.5°C. One of the key aspects of the plan is to limit emissions from point-source industrial emitters that produce elevated levels of CO₂, which are often hard to abate. These industries include cement, lime, steel, and aluminum production, bioenergy, refineries, chemicals, natural gas and coal power plants, pulp and paper, and waste-to-energy.1 Looking at the carbon capture value chain, there are a range of technologies at widely varying technical readiness levels (TRL). The most mature carbon capture technology, which is currently used in most industrial carbon capture installations, is chemical absorption, where a solvent selectively binds with the CO₂ in one column called the absorber and regenerates in a secondary regenerator column where the CO₂ is released. Solvent-based absorption technology is well known and has been used extensively in natural gas treating plants such as in amine sweetening processes. Other carbon capture technologies at lower TRLs include physical absorption, adsorbents, oxyfuel combustion, cryogenics, calcium or chemical looping, and membranes. Once CO₂ is captured, it is typically dehydrated, compressed into a dense or supercritical phase for easier transport, then transported via pipeline or ship. It can be utilised in material production, enhanced oil recovery, or other processes or stored in depleted reservoirs or saline formations. Treated gas CO2 to compression Condenser 3 Water wash loop Carbon bed Reflux drum Cooler 5 Feed gas 1 4 Stripper 4 2 Heat exchanger Cooler Absorber Reboiler Rich solvent Lean solvent Figure 1 Pretreatment and solvent-based capture filtration and separation needs Filtration and separation recommendations for select process locations in Figure 1 # Need Driver 1 Particulate removal from dry gas feeds Protect equipment, prevent solvent loss 2 Remove contaminants on inlet gas Protect equipment, prevent solvent loss 3 Prevent amine carry-over on absorber outlet Meet environmental specs, prevent solvent loss 4 Remove solid contaminants from solvent loop Prevent fouling of critical equipment 5 Prevent activated carbon fine carry-over in solvent loop Prevent fouling of critical equipment Separation solution Low ΔP flue gas filter Low ΔP aerosol removal Low ΔP aerosol removal Absolute-rated particulate filter Absolute-rated particulate filter Table 1 www.digitalrefining.com PALL.indd 19 PTQ Q1 2024 19 08/12/2023 15:02:19 Compressor stages (high-P) 5 Dehydration stages Compressor stages (low-P) CO2 gas Cooler Regenerator 2 8–9 3 4 1 2 3 Glycol contactor Heat exchanger Rich glycol Reboiler Lean glycol Displaced H2O Reservoir 7 6 Reservoir Dense phase (supercritical) CO2 CO2 transport, pipeline Dense phase (supercritical) CO2 CO2 storage Figure 2 Downstream compression, dehydration, and storage filtration and separation needs Which capture technologies are favourable highly depends on process economics, often cited in units of $/ton CO₂. Because CO₂ does not have an intrinsic value, installations are driven by credits and regulations. This drives the industry to seek the lowest expense-proven solution and actively pursue technologies that offer cost reduction and increased equipment lifetime. Solving the contaminant challenge In the critical-to-decarbonise industrial sectors, CO₂ is typically captured after a combustion process. Therefore, flue gas feed streams entering CO₂ capture processes can contain an elevated level of combustion byproduct contaminants. These feed contaminants can increase process operating expenses by (1) increasing the need for water replacement in wash systems and direct contact coolers, (2) increasing the frequency of solvent, membrane, or adsorbent replacement, (3) for solvent-based processes, causing amine emissions in the flue gas outlet from the absorber, and (4) fouling critical process equipment such as heat exchangers, reboilers, compressors, and absorber internals, thereby reducing process efficiency, increasing energy requirements, and requiring more frequent maintenance. Additionally, contaminants can be generated during the carbon capture process. For instance, corrosion byproducts, solvent degradation compounds, and heat-stable salts can build up over time in solvent loops. Similarly, in downstream process steps, lube oil and solid contaminants can be introduced into the concentrated CO₂ stream. These contaminants also increase operating expenses by contaminating successive stages of equipment, leading to off-specification pipeline contents, and can plug reservoirs. For each of these problems related to contaminants, reliable filtration and separation steps are critical to maintaining low operating expenses. Filtration and separation products for solvent clean-up are well known due to decades of experience with gas treatment. However, other applications, such as feed treatment before CO₂ capture processes, solvent emission prevention, and downstream, including dense-phase CO₂ purification are less known, emerging applications in this sector. Pall applications in solvent clean-up, feed treatment, and solvent emission prevention are shown in Figure 1, with detail in Table 1. Applications downstream and in dense-phase CO₂ purification are shown in Figure 2, with details in Table 2. Filtration and separation recommendations for select process locations in Figure 2 # 1 2 Need Driver Remove solids and liquids on inlet Compressor protection Remove solid contaminants from lube oil Keep lube oil clean, reduce compressor component wear 3 Compressor vent Prevent compressor cavitation (depends on compressor) 4 Prevent lube oil carry-over to TEG Keep TEG/dehydration loop process dehydration loop efficiency high 5 Remove solvent carry-over Protect downstream compressor 6 Remove contaminants from supercritical CO₂ Prevent reservoir fouling 7 Remove contaminants from displaced water Prevent reservoir fouling 8-9 See applications 4-5 in solvent carbon capture, Figure 1. Separation solution Liquid-gas coalescer Particulate filter or vacuum purifier Vent filter, also called a ‘breather’ Liquid-gas coalescer Liquid-gas coalescer Absolute-rated particulate filter Absolute-rated particulate filter Table 2 20 PALL.indd 20 PTQ Q1 2024 www.digitalrefining.com 08/12/2023 15:02:20 Solvent purification With a solvent-based CO₂ capture process, the process efficiency and operating expenses of the entire unit hinge on the cleanliness of the solvent and equipment. On a positive note, recommended filtration and separation steps are well-studied due to the longevity of these processes in gas processing plants. Solid feed contaminants such as fine fly ash particulates (as small as <1 µm diameter) that can bypass feed pretreatment steps due to their small size can build up and foul the lean/rich heat exchanger, the reboiler, the absorber internals and require more frequent solvent change-out over time. Contaminants can also alter the surface tension of the solvent, causing an increased tendency to foam and increased foam stability, requiring the use of anti-foam. Finally, fine particulates can form aerosol nuclei, which contribute to solvent emissions, resulting in solvent losses out of the absorber vent, as found from tests at the post-combustion carbon capture plant at Niederaussem.² Corrosion products from stainless steel and similar equipment can also precipitate in the rich side of the solvent loop into solid particulates such as iron compounds, causing similar issues. To remove these solids, particulate filtration of the solvent is recommended at a minimum of 10% slipstream. The target level for solids after filtration is 1-5 ppmw. Five or 10 µm-rated absolute particle filters are recommended, based on the diameter of the solid particulates. It is important to understand the differences between how particulate filters are rated. Nominal ratings are arbitrarily assigned by the filter manufacturer, and there is no regulation for the value of the nominal ratings to indicate the performance of removing certain particle sizes. In contrast, absolute particle filter ratings must meet rigorous ‘ISO or ASTM’ standards. The absolute rating of a particle filter directly corresponds to the largest diameter of particle that the filter will allow through – all larger particulates will be captured. An example of the difference between solvent cleanliness after using no filter, a nominally rated filter, and an absolute-rated filter is shown in Figure 3. Rich side filtration is commonly recommended to remove precipitated corrosion like iron sulphide and to protect the lean/rich heat exchanger. Significant improvements in the removal of solvent contaminants have been demonstrated using Pall absolute-rated filters, with extensive data proving the removal of precipitated corrosion products and process equipment protection from the gas treating industry.³ Lean filters can also be added to the process scheme to prevent fine particulates from entering the absorber. Lean filtration is particularly recommended for polishing and removing adsorbent fines if there is a carbon bed on the lean solvent side. Carbon beds are often installed to remove solvent degradation products and have been found to remove some metal ions. Degradation products such as organic acids, formed by the solvent degrading through oxidative and thermal mechanisms, can be corrosive, cause foaming, solvent losses, and reduced absorber capacity. Metals are common from internal metallurgy and can catalyse amine degradation. Not all activated carbon targets the same www.digitalrefining.com PALL.indd 21 contaminants, so the product must be selected carefully to ensure that it does not prematurely plug. Other concerns in the solvent loop include heat-stable salts, which are produced when amines react with acidic components such as O₂, CO, and SO₂. Concerns with heatstable salts are that they render the amine inactive and can make the solution corrosive if allowed to reach a level above 3%. Ion exchange techniques are commonly recommended for treating heat-stable salts. Finally, there is increasing concern about nitramines and nitrosamines in the carbon capture industry due to their nature as a potential carcinogen. These compounds are produced from NOx in the flue gas reacting with amines. Water wash prevents nitramines and nitrosamines from venting out of the absorber, but they must still be removed from the water wash before disposal to avoid environmental contamination. Processes to remove nitrosamines and nitramines, such as selective catalytic reduction (SCR) for NOx removal and use of activated carbon, are ongoing areas of study to ensure that these compounds remain below desired levels.⁴ Flue gas pretreatment The top three contaminants commonly present in post-combustion flue gas are NOx, SOx, and particulates such as fly ash. All three of these contaminants should be removed prior to CO₂ capture, regardless of the capture technology used. NOx levels are reduced in the pretreatment step before the absorber with a selective catalytic reduction process (SCR); SOx levels are also reduced during pretreatment with a wet or dry scrubbing process. Particle filtration is commonly employed in pretreatment steps with cyclones, electrostatic precipitators, and bag filters. Cyclones use rotation to separate solids but have difficulty removing small particulates. Electrostatic precipitators (ESPs) remove fine particulates by applying an electric charge but can be expensive and associated with an increased safety risk. Furthermore, wet ESPs have been found to break up large contaminants, increasing the total number of contaminants in some cases. Finally, bag filters can be temperature-limited due to the use of polymeric material. They can have a shorter lifetime and lower particulate removal efficiency when compared to absolute-rated filters with inorganic (metallic or ceramic) filter media. One key requirement of filtration pretreatment is that it operates at a low pressure drop due both to the excessive Figure 3 Amine cleanliness after no filtration, nominal filtration, and absolute filtration PTQ Q1 2024 21 08/12/2023 15:02:21 Clean gas pipe Blowback valves Module Clean gas chamber Filter module Dust hopper Figure 4 Fine fly ash present in flue gas feed to Figure 5 Low pressure drop filtration testing. Left: test stand setup. Right: filter inlet a carbon capture process following tests. Fine particulate contaminants are visible on the face plate costs of compressing large gas flows and near-atmospheric process conditions of flue gas feed to CO₂ capture processes. Low pressure drop filtration systems are often large, making their integration into existing plants a potential challenge in terms of space constraints. They also do not always capture fine (<1 µm) particulates present in industrial flue gases, such as those shown in Figure 4. Pall has recently developed a new low pressure drop particulate filter to address this application. The system and overall operation are based on decades of experience with Blowback filter technology, where particle contaminants build up on the feed side of a filter. After a period, caked contaminants are ejected off the filter for collection or disposal at automated intervals via a short gas pulse in the reverse direction. Filters regenerate at separate times, such that most of the filters in the system provide continuous operation and filtration. Through regeneration, filters maintain a long on-stream service life, and the pressure drop after solids are blown off reaches an equilibrium point. Blowback filter cartridges were conventionally cylindrically shaped and made from inorganic materials such as metals or ceramics to withstand harsh process conditions and offer fine filtration ratings with good reliability. However, to achieve an extremely low pressure drop with an order of magnitude in the 10s of millibar, as requested by the CCUS industry, conventional blowback technology would need to be oversized and thus would not have been an economical solution and would have been challenging to fit into brownfield industrial plants. This new product development leverages recent advances in additive manufacturing (AM) to produce a remarkably high surface area filter element with minimal manual manufacturing, enabling bulk production of filters at a given time. The high surface area ensures a small filter system footprint to handle a given flow rate and pressure drop (down to <20% the size compared to the conventional product and similar alternatives), which directly translates to reduced infrastructure needs and production costs. The new filter design was optimised through iterations of advanced computational fluid dynamics (CFD) modelling, coupled with rapid 3D printing prototypes that were tested at a lab scale with representative test dust and varied blowback cycle time to regenerate the filter. Larger bench-scale tests depicted in Figure 5 with multiple elements were performed internally at Pall and offer impressive results. The pressure drop across the filters for the duration of 22 PALL.indd 22 PTQ Q1 2024 the tests is kept between 20-30 mbar, with an estimated pressure drop below 60 mbar for full-scale installations, which include piping and valves. Solid loading in the gas feed varied above 1 g/Nm³, with exceptionally low downstream solid loading after filtration – well below 1 mg/Nm³. Removal efficiency is above 99%, even for sub-micron particulates down to a 0.5 µm diameter and below. The next steps are to continue to prove performance at increasing scales. Emission prevention Aerosol emission management has been another major focus of carbon capture technology providers. In solvent-based carbon capture technology, SOx and fine (<1 µm) flue gas feed particulates are responsible for most of the solvent losses out of the vent, which have been found to reach more than 1,000 mg/Nm³. In contrast, desired levels are typically as low as possible to minimise solvent losses and environmental impacts, well below 10 mg/Nm³. A water wash mounted on the top of the absorber unit limits gas-phase solvent emissions, but particulates and SOx, which form H₂SO₄ aerosols, serve as sub-micron diameter droplet nuclei. Droplet nuclei can then grow to larger micron-sized droplets as they travel through the water wash section. In this application, like flue gas pretreatment requirements, there is an extremely low pressure drop (<20 mbar, as an example) available due to pressure conditions near atmospheric. Again, Pall is developing a product to uniquely meet the low-pressure requirements, while removing fine aerosols with an exceedingly high-efficiency (>99% aerosol removal) separator, producing well below 1 ppmw downstream and also providing a minimal footprint. The unique ability of this separator to meet high-efficiency removal requirements and a low desired pressure drop is a result of the material science used in its fabrication and in-house technical expertise. The product design allows liquid to drain off quickly and easily, similar to the industry-proven high-efficiency liquid-gas coalescers shown in Figure 6. Downstream purification and dense phase CO₂ After CO₂ has been captured, it is dehydrated and compressed to a high pressure for transport and storage. After dehydration and compression, CO₂ reaches a high-pressure ‘supercritical’ or ‘dense phase’ state, with a high density nearing that of a liquid and a viscosity nearing that of www.digitalrefining.com 08/12/2023 15:02:22 a gas. Converting CO₂ to a dense phase enables the use of smaller pipelines and increases the amount of CO₂ that can be stored in reservoirs. In downstream applications, lube oil can become contaminated through compressor wear, requiring filtration. It can also be carried over after the compressors, which can cause the CO₂ to become off-specification. Similarly, dehydration processes such as adsorbent-based dryers or glycol loops can require filtration and liquid/gas coalescence to prevent fouling of dryers and absorption loops, and to prevent carry- over of fines or glycol contaminants. After compression and dehydration stages, undesired contaminants such as water, lube oil, oxygen, and H₂S can be present in the CO₂, which pose a threat to the integrity of the pipelines. Hydrogen sulphide and oxygen are corrosive, damaging the pipelines and, in the worst case, causing cracks. Trace water can react with CO₂, forming corrosive byproducts, and can also form hydrates, which produce pipeline blockages. As pipelines deteriorate, solid corrosion products and pipe scale formed through these reactions can be carried downstream, plugging critical equipment needed for carbon capture storage, such as control valves, metering stations, and high-pressure injection pumps. This increases maintenance costs and can require equipment replacement or unscheduled downtime. Solid contaminants can also plug permeable storage reservoir pore structures, requiring increased energy for CO₂ injection and even limiting the amount of available and accessible reservoir storage capacity. In selecting filters and separators for dense phase CO₂ applications, substantial care must be taken on which materials are used, how filter sizing is performed, and what the filtration rating is. To fully protect reservoirs, the filter rating must be selected based on the reservoir permeability and approximate pore diameter. Regarding material choice, safe operation favours corrosion-resistant metallic materials or CO₂-stable plastics. Plastics must be carefully selected, as some materials may swell under contact with supercritical CO₂. Additionally, some polymers can mechanically fail by explosive decompression if there is a rapid pressure drop during upset conditions or routine maintenance after CO₂ has adsorbed and diffused into the polymer due to highpressure operation. Conclusions Filtration and separation applications in solvent-based absorptive carbon capture are well-known from decades of gas processing technology with amine solvents. However, there are emerging requirements specific to carbon capture, such as low available pressure drops in pretreatment and high pressures in downstream CO₂ transport and storage. These requirements mean that new filters and separators tailored to the applications outlined in this article, as well as expert knowledge in material and product selection, are needed. By choosing the right purification product with the right material compatible with the application, both capital and operating expenses can be minimised by protecting critical equipment, meeting environmental specifications on contaminant levels, and keeping process efficiency high. www.digitalrefining.com PALL.indd 23 Gas out Gas in Water in Figure 6 Pall high-efficiency liquid-gas coalescer Acknowledgements Special thanks to Olivier Trifilieff, Ali Arshad, Joe Youberg, and Keith Webb for their contributions and review of this article. References 1 IEA, Transforming Industry through CCUS, 2019, www.iea.org/ reports/transforming-industry-through-ccus. 2 Moser et al, Solid particles as nuclei for aerosol formation and cause of emissions – Results from the post-combustion capture pilot plant at Niederaussem, 13th International Conference on Greenhouse Gas Control Technologies, Lausanne, Switzerland, 2016. 3 Raymond A, Levesque F, Lakhani H, Separations technologies to improve amine system reliability: A case study. Pall Corporation Scientific & Technical Report FCASRCSENa, 2008. 4 Mazari et al, Formation and Elimination of nitrosamines and nitramines in freshwaters involved in post-combustion carbon capture process. Journal of Environmental Chemical Engineering, Vol 7, Issue 3, 2019. Lara Heberle is the Global Technology Development Manager for Carbon Capture, Utilization, and Storage at Pall Corporation. She holds a BSc in engineering physics and mechanical engineering from the University of British Columbia, and a Doctorate in mechanical engineering, with a focus on fluid dynamics and a minor in thermal sciences from Cornell University. Email: [email protected] Julien Plumail is the Global Vertical Marketing Manager for Carbon Capture, Utilization, and Storage at Pall Corporation. He holds an MSc in engineering from the French Petroleum Institute, and an MBA from IESEG. Email: julien_plumail@ pall.com PTQ Q1 2024 23 08/12/2023 15:02:24 Cut your CO2 emissions in half with ET Black™ Carbon Black Technology ET Black™ is a state-ofthe-art technology that complies with the most stringent environmental regulations now and in the future. q1 eurotecnica.indd 1 Plus, the flexibility to produce all ASTM grades, and specialty grades, in a single plant. ET Black™, the technology of reference for producing carbon black obtained by thermal decomposition of highly aromatic oils. Find out more at: www.igoforETBlack.com 12/12/2022 14:23:23 Overcoming wastewater challenges of opportunity crude processing Refinery wastewater facilities need new practices and solutions for efficient and sustainable operation with heavy opportunity crudes Shane Lund Veolia Water Technologies & Solutions T he challenges associated with processing opportunity crudes have been well-documented over recent years. Their high content of small, suspended solids, tramp amines, asphaltenes, naphthenic acids, and many other problematic substances combined with high variability can make these crudes difficult to treat from beginning to end in a refinery. Increased difficulty desalting these crudes can lead to brine effluent heavily contaminated with hydrocarbons sent to the wastewater treatment plant. Even when the desalting operation is working well, the increased loading can overwhelm some wastewater plants, forcing production to be curtailed. When faced with this higher loading, many wastewater assets can become overburdened and more likely to push past the breaking point into upset conditions. Symptoms of these upset conditions can include foaming, poor sludge settling and compaction, internal or external toxicity, reduced nitrification rates, and reduced chemical oxygen demand (COD) removal. Identification and treatment of the symptoms and root causes are important to maintain compliance with increasingly tight water discharge limits. This article discusses common wastewater management problems associated with processing opportunity crudes, holistic monitoring strategies to identify potential upsets early, and operation strategies and treatment techniques used to maintain effluent discharge compliance while processing opportunity crudes reliably. Opportunity crude contaminants The blending of tight oils and heavy ‘opportunity’ crude oils is now a common practice for many industry players. This practice certainly benefits operators by sourcing crudes based on availability and price. However, it does present a risk to the performance and reliability of the various process units within the refinery. The resulting blend sent to the crude unit can exhibit less-than-ideal properties that vary daily, even hourly, making it very hard to maintain the unit’s production quality. Increased use of ‘opportunity’ crudes has been shown to create challenging conditions in wastewater treatment as the crude unit struggles to separate water and oil efficiently. Working upstream by optimising crude blending strategies and desalter operations should certainly be part of a holistic www.digitalrefining.com VEOLIA.indd 25 plan to manage heavy crudes. However, conditions should also be in place downstream to address potential desalter upsets. If a comprehensive plan to prevent and address wastewater systems’ contaminations and upsets is not put into place, there is a real risk that production may need to be curtailed as contaminants in the effluent discharge get too close to allowable limits. Much has been written about the connection between opportunity crudes and wastewater difficulties, such as foaming, poor sludge settling and compaction, internal or external toxicity, reduced nitrification rates, and reduced COD removal. Problematic features associated with the opportunity crudes that have been blamed for the wastewater difficulties include increased quantity of solids that are smaller in size, increased amine loading, more naphthenic acids, and high variability in the crudes. The use of opportunity crudes in a refinery’s crude diet is expected to lead to a higher potential for desalter upsets due to variability, emulsions, pH, viscosity, stability, and asphaltene precipitation. These contaminations and fluctuations would provoke more frequent primary wastewater treatment problems as the desalter effluent brine undercarries process compounds such as asphaltenes, small, suspended solids and oil, all in variable quantities. In the secondary wastewater system, we expect to see potential problems due to elevated biochemical oxygen demand (BOD) and COD, elevated levels of both long- and short-chain organic acids, more tramp amines, higher surfactant loads, and inhibitory substances. While it is true that any one of these properties can detrimentally impact wastewater treatment, a single bad actor is not usually identified, as multiple parameters typically act together during an upset event. These combined properties push refinery wastewater treatment assets ever closer to the edge, and contingency plans cannot contain these conditions indefinitely. Each refinery wastewater treatment plant has its own unique set of potential constraints based on its system’s design and level of contingencies. However, the lack of a plan to predict and address upsets takes the system ever closer to the breaking point. Once the breaking point is hit, several things can occur, including foaming of aeration basins and clarifiers, floating solids on clarifiers, poor sludge settling and PTQ Q1 2024 25 08/12/2023 15:15:35 compaction, internal and external toxicity, reduced nitrification rates, and reduced COD removal rates. Holistic monitoring Predicting and addressing stressed conditions on a complex and dynamic system such as a refinery’s wastewater plant requires the implementation of a holistic monitoring strategy. The strategy should prioritise areas found to be most vulnerable for a given system, which should not be assumed to be the same as another wastewater system. For example, a wastewater system with limited secondary system capacity may need to focus on ensuring fast COD oxidation and rapid settling sludge, which may need to be enhanced with bioaugmentation and chemical aids. Closely monitoring the bioaugmentation and chemical systems will be important in this case. A system with adequate secondary system capacity but limited primary system capacity may be better served by honing in on monitoring for source control, primary chemical treatment programmes, and optimisation of the primary system. Once vulnerabilities are understood, set up a programme to monitor each wastewater asset. Some typical monitored parameters are found in Table 1. Monitoring of primary treatment operations should include, at minimum, oil and grease (O&G), total suspended solids (TSS), COD, and turbidity. In addition to the influent and effluent of the primary treatment assets, other streams that should be monitored are specific influent streams (desalter brine), equalisation systems, API systems, floatation, and clarifier systems. Secondary biological treatment is the heart of most complex wastewater treatment plants, so a holistic monitoring programme becomes ever more important as to the sensitivity and criticality of the process. Standard chemical tests combined with dissolved oxygen uptake (DOUR), microscopy, and advanced tools such as Veolia’s BioHealth Adenosine Triphosphate (ATP) can provide unique insights to better understand the condition of the secondary system’s biology ahead of performance showing decline. BioHealth DNA genomics testing can also help detect shifts in the microbiome due to changes in food source or other stressors, enabling better long-term process decisions. Because BioHealth ATP testing considers multiple intrant factors to simulate the impact on the secondary treatment biomass, it can provide earlier detection of potential upset conditions than other monitoring tools. Key output information includes Biological Stress Index (BSI), Active Biomass Ratio (ABR), Active Volatile Suspended Solids (AVSS), and True Food to Mass ratio (True F:M). BSI provides the ratio of ATP released from deteriorating cell membranes compared to the total quantity of ATP in a sample, which is a good indicator that inhibitory conditions are present. This allows operators to make smart decisions when considering discretionary loads and can help direct efforts in searching upstream for problematic flows and detrimental environmental conditions such as elevated temperature. ABR informs us how much of the system mass is actively doing the job of reducing contaminants. This information can help optimise plant operation and reduce excess energy consumption as it can be used to reduce the quantity of inert solids safely. AVSS gives the concentration of living biomass in the system. Each system has a specific range of AVSS that provides optimal performance, so once this optimal range is understood, deviation from the optimum should drive process control adjustments. AVSS can also be used to calculate food to mass (F:M) ratio. Traditional F:M includes comparing the mass of BOD to the mass of Mixed Liquor Suspended Solids (MLVSS), but replacing the MLVSS with AVSS provides more accurate information based on the amount of biomass that consumes nutrients. Monitoring the final stage of solids separation following the primary and secondary treatments is also needed to ensure a consistent operation that does not suffer poor effluent quality. Clarifiers, which are most commonly used for removing remaining suspended solids, require a minimum daily record of settling rates, bed depths, solids concentrations, and overflow quality in order to adjust and optimise effluent quality. Operation strategy Data collected from the monitoring programme at the various stages of the wastewater treatment process is key to making process control decisions. However, the basics should not be neglected, which apply no matter what the crude diet. The basics include: Understanding your plant’s specific vulnerabilities Understanding problematic substances from each process stream and avoid shock loads to these streams Communicating frequently with process units Some typical monitored parameters when setting up a Maintaining all equipment (maintenance freprogramme to monitor each wastewater asset quency needs to increase with extra loading) Primary effluent Bio-reactor Clarifier Optimising all primary treatment assets to Flow MLSS, MLVSS, AVSS Bed depth remove as much insoluble matter as possible to pH BioHealth ABR & BSI SSV₅, SSV₃₀, SVI protect downstream biomass TOC, COD, BOD DO RAS flow Optimising secondary treatment by giving the TN, NH₃ DOUR, SOUR RAS TSS biomass a healthy living environment free from TSS F:M ratio WAS flow fast changes Oil & grease pH WAS TSS Optimising clarification/solids separation. Metals Temperature Visual – scum, overflow Primary treatment systems’ data should lead Known toxins Microscopy Turbidity to operational decisions to prevent the process Alkalinity Biohealth DNA Regulated parameters from becoming overloaded with excess solids and Table 1 hydrocarbons associated with varying crudes’ 26 VEOLIA.indd 26 PTQ Q1 2024 www.digitalrefining.com 08/12/2023 15:15:35 diets. These may include adjust- and primary treatment optimisation are DIBconveyor performance ments to skimming rates, keycomparison to reducing shock loads. speeds, solids loading rates, and gasWhen controlling the secondary Operating ratios. parameter Pre-optimisation to-solids With higher loads system, choose aPost-optimisation method, such as conFeed point #21 tray #9 tray that may include more emulsion, and stant sludge age, constant MLSS, or Feed rate, b/d Base + ∆ 15% more smaller solids (more net surface constant F:M and stick with it. However, Feed temperature, ºF Base Base area and more net negative charge), new conditions may warrant a new Reflux temperature, ºF Base - ∆ 1.3ºF chemical treatment programmes may Base approach. For example, Reflux ratio, volume basis - ∆ 5%if a 25-day require adjustment. sludge historically provided optimum Side reboiler unit steam consumption, lb steam/bbl + ∆ 9%and associNot only the dosage feed but also the Base results, new crude slates choice coagulants and flocculants ated contaminant loading may warrant Bottomof reboiler unit steam consumption, steam/bbl so feedthe chem- Base ∆ 7% even notice may require lb changes, a 30-day sludge age.-Some ical systems a ‘seasonal’ sludge- ∆age approach is RVPinjection of the bottom product,and psia controls Base 1.2 psi should allow for easy adjustments and needed based on ‘crude seasons’. replacement. In some cases, online The goal of secondary treatment is Table 2 monitoring of parameters such as to remove all contaminants via bacturbidity,traffic TSS, would or totalbeorganic teria that them, form floc column fulfilledcarto duties are metabolise also stabilised at the target bon (TOC) the DIB clearfeed advantage of performances. and then settle out in clarifiers or are achieve thehas target rate and allowing for real-time automation of removed through filtration methods. RVP value. the chemical programme at the pri- Summary This should leave clear, contamimary treatment. This can significantly nant-freeimpacts water distillation dischargedunit in perthe Case study 2: Post-optimisation Fouling reduce the variability of this stage’s overflow. Increased organic loading performance formance/run length adversely. It is effluent andtohelp stabiliseresults, secondary associateddifficult with opportunity According evaluation the extremely to resolve thecrudes foultreatment operation. could push clarifier solids loading outDIB feed point was relocated from tray ing problem without unit outages. Astoopportunity side of theiridentifying operating limits. #21 tray #9. The crudes’ number challenging of stripping However, non-optimum naturewas oftenincreased leads to by more par- parameters If clarifiers and become a pinch point, trays 11.fine Bottom building pertinent ticles and higher levels of emulsions the chemical programme should be reboiler duty was maintained at the optimisation strategies can enhance in the process wastewater streams, optimised to encourage faster setmaximum duty available, and the side distillation unit performances and source control andincreased source treatment tling. Routine bioaugmentation, which reboiler duty was to meet avoid unit outages. of these various streams can facilconsists of the addition of specialty the required total reboiler duty and taritate overall wastewater operation bacteria populations to the secondary get DIB bottom temperature. A major Acknowledgements and prevent more general upsets. For treatment’s biomass, helpofimprove version a presbenefit of the optimisation is that these The article is an updatedcan example, were desalter brine accomplished streams may entation organicsgiven removal and optimise solids at AIChE Spring Meeting, changes simply be treated separately they are Kister settling characteristics. Coagulants Distillation Symposium, March 13-16, while the unit remainedwhen in service. affected contaminants and flocculants may also be required, in Houston TX. Anotherbytest run after theassociated optimisa- 2023, with heavy crudes, and further treateven if not necessary when operating tion was arranged to verify the perment of specific components of the on a more traditional and stable crude formance enhancement. The pre- and References brine stream may make sense in some diet, to consistently meet desired T, California post-optimisation test run data are 1 Kister H, Hanson D, Morrisonthe circumstances. effluent quality. summarised and compared in Table 2. Refiner Identify Crude Tower Instability Using To target improve effluent quality, The DIB feed treatment rate and RVP of Root Cause Analysis, AIChE Spring Meeting, In case of2001. upset, listen to the data ensure all assets arewere properly cleaned April 22-26, the bottom product met. Column keeping critical wasteand maintained, as more means 2Even Kisterwhile H, Distillation Design, McGraw-Hill fractionation was evensolids enhanced Company, 1992. water assets in top condition, commore chance of settling and fouling, despite a lower reflux ratio. These 3 Lee S H, Balanced distillation equipment municating frequently with process resulting in reduced volumes and performance enhancements were Q1 2017.from head to tail, units, PTQ, monitoring reduced efficiency. Byoutages. reducing avail- design, acquired without unit 4 Hanson D, Leeoperating S H, Reducing FCC main and adjusting strategies to able tank volume, solids accumulation As the optimisation moves were fractionator operating wastewater risks, PTQ, Q1 2021. the ‘new normal’, upsets reduces equalisation capacity, and implemented with fouled column con5 D, Piping Result cirin doHanson still happen due Circuits to extreme reaction further time for fouling the treatment ditions, could chemerode Distillation Column Underperformance, cumstances. Even the best-run plants istry, so a regular cleaning programme these performance enhancements. To Fractionation Research Institute have experienced upsets due to Annual unexcan present a significant benefit. ensure performance improvements on Meeting Experts Panel, May 4, 2022. pected crude incompatibility, extreme Secondary treatment systems do a long-term basis, post-optimisation not suffer as much presence weather, power outages, or other performances havefrom beenthemonitored Soun Ho Lee is the Subject Matter Expert of contaminants as the speed at which uncontrollable circumstances. for more than two years. Operating for fractionation and separation with Valero The stress of upset conditions can these new andan adverse conditions trends show enhanced DIB presfeed Energy Corporation in San Antonio, Texas. lead decision-making by ent themselves. The biological wasterate and the RVP of the bottom prod- He istoinemotional the Strategic Technology and operation, and the loudest voice in the water system is amazingly resilient if uct are well maintained. There has Development group, overseeing large proroom often gets the most attention; be shocksno aresign avoided and the microbes been of downgraded per- jects and advanced optimisation and troublesure theinloudest voice is your monitorhave adequate timethan to two acclimate. formance for more years shooting fractionation. ing data. Source control, adequate equalisation, of operation. Rebalanced reboiler Email: [email protected] www.digitalrefining.com www.digitalrefining.com VEOLIA.indd 27 VALERO.indd 95 All from one Source! Fast Delivery Worldwide Duranit® Catalyst Support Material Support Plates / Grids Droplet Separators / Demisters Feed Devices: Gas / Liquids Liquid distributors / Collectors Random Packings - Ceramic - Metall - Plastic Software and Consulting Get in touch: [email protected] www.vff.com Check out: Image Movie VFF Vereinigte Füllkörper-Farbriken GmbH & Co.KG P. O. Box 552, 56225 Ransbach-Baumbach, Germany, +49 26 23 / 895 - 0, [email protected] PTQ Q4 Q1 2023 2024 PTQ 27 95 08/12/2023 15:15:35 13/09/2023 10:00:14 7.0 6.0 25 Decreasing ABR 5.0 20 4.0 15 3.0 Increasing stress 2.0 10 5 1.0 0.0 BSI & ABR (%) Ammonia (mg/L) 30 Bioaugmentation programme started 0 Ammonia 10 20 Biomass Stress Index (BSI) 30 Active Biomass Ratio (ABR) 50 40 60 70 80 0 Days Figure 1 Refinery secondary wastewater treatment monitoring during upset Step back. Review the data. Understand your specific constraints and targets. Accept that more than one parameter may be responsible for the upset. Identify and correct the root cause, along with secondary causes. Adjust based on these insights and operating guidelines, and then be patient while the system recovers. Considering that biological systems recover slowly, often taking two to three sludge ages for full recovery, implementing contingency measures to maintain acceptable discharge water quality may be required. These measures may include supplemental coagulants, flocculants, antifoams, bioaugmentation, flow reductions, and other measures. Overcommunicate with production units during upset conditions; failure in communication can lead to extended recovery times if difficult wastewater loads are released from production units when the wastewater plant is vulnerable. Finally, never waste an upset: document more than you think necessary to ensure all lessons are learned, leading to new operating practices and optimised contingency plans. Case study: Downtime averted for refinery wastewater treatment under severe stress In this case example, a refinery wastewater influent was characterised by high levels of organics and ammonia, with frequent variations. While nitrifying bacteria are essential in the secondary treatment to remove ammonia, high-stress events saw their population being depleted. This caused ammonia levels in the effluent to shoot up, and the refinery had to curtail production to prevent potential environmental impacts and discharge permit exceedances. The on-site Veolia team had been using the BioHealth monitoring technology to assess the health of the biological wastewater operation. When combined with the other data collected by the site’s operators, this enabled the plant to make optimal decisions regarding wastewater treatment and process unit adjustments. As shown in Figure 1, the BioHealth tests indicated the BSI gradually increasing, with the ABR decreasing as the challenging conditions worsened. The nitrification process became unstable and completely inhibited as the bacteria population degraded. The production rate was reduced to ensure the plant’s effluent did not exceed regulations, so the wastewater system needed to return to normal rapidly. 28 VEOLIA.indd 28 PTQ Q1 2024 With frequent communications of results between Veolia and the operations team and continued monitoring, it was decided to initiate a bioaugmentation programme. The BioHealth technology was used to identify the proper contingency treatment and dosage for fast and efficient recuperation of the system. While the typical response to a nitrification upset could have taken one month or longer to recover, the data provided by BioHealth to detect the problem and help identify the bioaugmentation solution allowed the plant to return to normal operation within just six days. Throughout the event, the operation team enacted the detailed monitoring programme well, so the discharge quality always remained in compliance. Conclusion Increased processing of opportunity crudes will likely continue as there are clear financial incentives for refiners to include them in their crude diet. Even when trying to optimise crude blends and desalter operation, it is not always practical or economical to prevent all contaminations in the desalter brine effluent, and the wastewater treatment plant should be equipped to handle these while respecting discharge quality limits. For the refinery’s wastewater facility to operate efficiently and sustainably when faced with the challenges attached to these heavy crudes, new practices and solutions must be implemented. Enhanced monitoring, data-driven decisions, and a good understanding of the treatment basics combined with openness to apply these basic rules to new conditions will reduce the frequency of wastewater upsets and increase speed of recovery when they do occur. This will enable the plant to maintain operation while consistently respecting discharge limits and regulations. Shane Lund is a Senior Application Engineer at Veolia Water Technologies & Solutions based in Minnesota. With more than 24 years of water treatment experience, he provides technical and sales support. He has also co-authored several papers on biological wastewater treatment systems in refineries and regularly makes presentations and provides training on the topic. He has a BSc in biology from St. Cloud State University and an Associate of Science in water technologies from St. Cloud College. www.digitalrefining.com 08/12/2023 15:15:37 valmet.indd 1 13/12/2022 14:34:33 BORN, WHERE VALUES ARE VALUED. THE 6X® Technology is only as good as the people who make it. That’s why the new VEGAPULS 6X is the result – made by over 2,000 valuable employees, 60 years of valued measurement experience and every value that is intrinsic to VEGA. VEGA. HOME OF VALUES. www.vega.com/radar PTQ Q4 vega.indd 1 11/09/2023 14:20:05 Biofilm: A hidden threat A new approach to the costly problem of biofilm formation in refinery and petrochemical operations Brian Martin Marathon Petroleum Corporation Tim Duncan and Gordon Johnson Solenis LLC R efineries and petrochemical operations rely on water-cooled heat exchangers in many areas of their facilities. These heat exchangers provide the heat removal from refining processes required for the production of various products and intermediates. The efficient transfer of heat in these exchangers often determines production rates. Fouling of the heat exchanger surfaces or flow restriction resulting from biofilm, scale, or debris may limit production and result in downtime for cleaning. Additionally, corrosion of the heat exchangers because of microbiological deposits may result in failures that require downtime, maintenance, and capital expenses. Expenses can run into millions of dollars, particularly if they include unscheduled downtime and heat exchanger replacement. Proper management of heat exchanger performance includes analysis of heat transfer data and understanding failure mechanisms. Data management tools can assist in the development of preventative maintenance guidelines and in the optimisation of chemical treatment programmes that minimise these expenses. Many refineries and petrochemical plants struggle with heat exchanger bundle failures and efficiency losses between turnarounds. Inspections of failed bundles often reveal under deposit corrosion (UDC) with biofilm as the culprit. Traditional monitoring and control techniques Warm cooling tower water containing microorganisms and nutrients fosters ideal conditions for microbial growth and biofilm formation. Microorganisms and nutrients enter the cooling system through multiple paths. They enter the system in the make-up water – even though it may have been treated for microorganisms, the treatment only renders the water sanitary, not sterile. As the water flows over the tower during the evaporation process, microorganisms and nutrients enter the system through the scrubbing process. Nutrients enter the cooling system from hydrocarbon leaks on the process side of heat exchangers, and they enter in the form of phosphate corrosion inhibitors applied to protect the carbon steel piping and heat exchangers from corrosion. Figure 1 depicts various stages of biofilm formation on a surface as microorganisms and nutrients continually inoculate the cooling water system. In the first stage, the cooling water transports these microorganisms to the surface. In the second stage, the microorganisms begin to attach themselves to the surface and within 20-30 minutes of system inoculation begin colonisation. In the third stage, because microorganisms reproduce through cell division at a geometric rate, within one to two days significant growth can occur. Part of this growth involves the production of extracellular polymeric substances (EPS). The composition of the EPS includes polysaccharides, proteins, extracellular DNA (eDNA), and lipids. The EPS from various microorganisms interact with each other and form a slime matrix that encompasses and protects the microorganisms. In the fourth stage, within three days to three weeks, the thickness of the biofilm matures. In the fifth and final stage, at maturation, detachment occurs because of turbulence or ecological conditions. This detached biofilm can then populate other regions of the cooling water system. Most microbiological control programmes using strong oxidising biocides, such as bleach or chlorine gas, even when used in combination with non-oxidising biocides, can only control biofilm up to a point. The matrix formed by the EPS encapsulates the microorganisms and provides a level of protection from these biocides. The EPS creates a demand for strong oxidisers, which generally cannot be Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Conditioning layer Bacterial attachment Biofilm formation/ EPS production Biofilm maturation Detachment Figure 1 Five stages of biofilm formation www.digitalrefining.com MARATHON SOLENIS.indd 31 PTQ Q1 2024 31 08/12/2023 15:56:44 90% Biofilm Heat transfer resistance 80% CaSO4 70% 60% 50% CaCO3 40% 30% Al2O3 20% 10% 0% 20 2000 200 Fouling thickness (µm) Figure 2 Thermal effect of biofilm and typical mineral scales exceeded at typical dosages. Dosages that can exceed the demand have a negative impact on the corrosion rates of metal surfaces themselves and degrade dispersants that are used to provide protection from inorganic deposition. Non-oxidising biocides similarly have difficulty penetrating the EPS’s protective slime matrix without reacting with the EPS. Economics do not favour traditional approaches to biofilm control. Underappreciated and underestimated aspects of industrial cooling water treatment include the effect of biofilm on heat transfer and the resultant heat exchanger failure from microbiologically induced corrosion (MIC). As shown in Figure 2, thinner biofilms, as compared with mineral scale, exhibit a more severe resistance to heat transfer. Microbiological fouling inhibits heat transfer up to four times that of calcium carbonate fouling. Additionally, once the biofilm exceeds 50 microns, approximately the thickness of adhesive tape, the resulting anaerobic conditions support the growth of acid-producing bacteria. The acidic waste products from anaerobic bacteria often aggressively pit heat exchanger tubes and eventually cause leaks, requiring repair or replacement. Traditional techniques for monitoring microbial growth and biofilm formation cannot measure biofilm. Biofilm forms when planktonic (free-floating) microorganisms begin to adhere on surfaces, such as pipe walls, heat exchangers, and cooling tower fill. Traditional approaches to monitoring microbial activity include measuring halogen residuals, heterotrophic plate counts, and adenosine triphosphate (ATP) levels in the bulk water. Unfortunately, no correlation exists between any of the results of these monitoring techniques and the attached, sessile microorganism levels that cause biofilm. Since traditional approaches to monitoring neither predict nor indicate biofilm, mechanical approaches have been employed to monitor the efficiency of heat exchangers to determine if biofilm fouling is present. However, detecting biofilm by measuring heat exchanger approach temperatures, unfortunately, only indicates the presence of biofilm after the fact. Similarly, flow studies only show restrictions and loss of velocity after biofilm has formed. New approach Solenis’ proprietary ClearPoint biofilm detection and control programme provides a new approach to the costly problem of biofilm fouling. This programme comprises three components: a novel biofilm analyser, proprietary chlorine stabiliser chemistry, and expert service. Employing the biofilm analyser, the programme provides early detection and accurate measurement of biofilm growth in real-time. The chlorine stabiliser chemistry is used to produce a patented, in situ stabilised active chlorine solution. The solution significantly reduces microbiological activity without the adverse side effects associated with strong oxidising biocides. Field service personnel provide the expertise required to maintain clean and efficient heat exchangers. The proprietary OnGuard 3B analyser uses a patented ultrasonic sensor, shown in Figure 3, to accurately measure the thickness of biofilm that accumulates on a heated target assembly, shown in Figure 4. The sensor detects biofilm with a measurement accuracy of approximately 10 μm and at a resolution of ±5 μm. The analyser mimics critical heat exchanger conditions in real-time by duplicating the shear stress on a surface while also simulating the local surface temperature to provide continuous fouling factor measurements that inform the adjustment of chemical feed when Ultrasonic pulse (p) Ultrasonic sensor Heated target assembly Reflection (r) Time (p + r) Biofilm growth Figure 3 Working principle of the ultrasonic sensor 32 PTQ Q1 2024 MARATHON SOLENIS.indd 32 Figure 4 Heated target assembly showing presence of biofilm www.digitalrefining.com 08/12/2023 15:56:46 required. The analyser can also differentiate between soft deposits (organic and microbiological fouling) and hard deposits (scaling). The early detection capability of the analyser allows corrective actions to be taken before biofilm can cause heat transfer loss or equipment damage. The advanced chlorine stabiliser chemistry employed as part of the biofilm detection and control programme is used in combination with sodium hypochlorite to produce a patented, in situ stabilised active chlorine solution. The resulting solution is not consumed when reacting with the EPS’s protective slime matrix, thereby allowing the solution to penetrate the biofilm, where it reacts only with the hydro-sulphur and sulphur-sulphur bonds of the biological proteins on the cell membrane and within the microorganisms. The in situ stabilised active chlorine solution not only controls both planktonic and sessile microorganisms but also removes existing biofilm and inhibits biofilm regrowth. The solution also effectively controls biofilms that harbour legionella. The in situ stabilised active chlorine solution does not increase the corrosion of metal substrate because of its lower oxidation reduction potential (ORP). For the same reasons, the solution does not degrade cooling water inorganic deposit inhibitors or react with other organics potentially present in the water. Thus, adsorbable organic halogen (AOX) and trihalomethane (THM) production does not occur. The lack of these reactions provides desirable environmental and health advantages over strong oxidising biocides. Unlike strong oxidising biocides, ammonia and amine contamination in cooling water does not increase the demand for the in situ stabilised active chlorine solution. Additionally, the patented solution results in lower chloride levels and reduced overall corrosivity of the cooling water. Stainless steel, in particular, has a reduced risk of chlorideinduced stress cracking. As a complement to the biofilm detection and control programme, the Solenis HexEval performance monitoring programme is available. Using advanced monitoring and predictive modelling capabilities, this programme enables decision-makers to identify which heat exchangers pose the greatest threat to reliable operation because of biofouling, scale or both. As a result, plant personnel can develop appropriate action plans. Solenis experts work directly with plant engineers to assign a critical rating score to each exchanger based on its impact on production if taken offline for cleaning or repair. The algorithm, developed from more than five million hours of study time on thousands of heat exchangers, then analyses the flow study data of each exchanger, within the context of its design, to calculate a hydrothermal stress coefficient (HSC) – a discrete value used to assess the reliability of the heat exchanger and identify factors threatening its performance. processing units using 10 cooling towers and more than 400 individual heat exchangers. Heat exchanger reliability and efficiency have a dramatic impact on the profitability of the operation. The facility and its water treatment supplier, Solenis, monitor the conditions of the water chemistry and the individual heat exchangers to ensure smooth operation. Case history: Marathon refinery Marathon and Solenis set about defining the problem and developing a plan to address the root cause. Before changes to the existing treatment programme could be recommended, the hypothesis that biofilm was the root cause of the exchanger problems required additional validation. To do this, Solenis, working with the local Marathon team, Marathon Petroleum Corporation operates the Garyville oil refinery on the banks of the Mississippi River in southeastern Louisiana between Baton Rouge and New Orleans. The facility has a crude oil refining capacity of 596,000 barrels per calendar day. Crude refining takes place in 19 www.digitalrefining.com MARATHON SOLENIS.indd 33 Hidden biofilm cost Despite maintaining corrosion coupon rates of less than two mils per year (mpy) and controlling water treatment parameters within key operating indicators (KOIs) for mineral saturation and corrosion inhibitor residuals, the refinery struggled with heat exchanger bundle failures and efficiency losses between turnarounds. Even with corrosion coupon results well within industry standards, heat exchanger bundle lifespans averaged seven years, lower than predicted. Corrosion coupon data suggested that the exchanger longevity should have been 50-80% longer. Agar dip slides, used to measure aerobic planktonic bacteria growth, routinely yielded results well within the Cooling Technology Institute (CTI) guidelines of 101–102 cfu/ml. Halogen residuals, used to control planktonic microorganisms, conformed to recommended values. The programme used a non-oxidising biocide, selected by laboratory kill studies, fed to the system two to three times per week. Still, summer conditions resulted in constrained refinery capacity, with exchangers being taken offline for cleaning because of water side fouling and requiring Underappreciated and underestimated aspects of industrial cooling water treatment include the effect of biofilm on heat transfer unscheduled shutdowns for cleaning, repair, and replacement. The negative impact on plant production and profitability ran into the millions of dollars annually. Because the heat exchangers were typically removed from service for decontamination, deposit analysis did not show the true cause of the corrosion, which was ultimately determined to be biofilm. The steaming required to decontaminate the process side dehydrated the biofilm. Despite deposit analysis that predicted a different corrosion mechanism, closer inspections of failed bundles revealed UDC and pitting resulting from biofilm. In addition, corrosion coupon visual examination and laboratory testing confirmed that biofilm was the root cause of the problem. A million-dollar problem PTQ Q1 2024 33 08/12/2023 15:56:47 Tube side velocity (ft/s) 6 5 Turnarounds 4 Biofilm detection & control programme 3 2 Measured velocity (ft/s) Design velocity (ft/s) 1 5/ 7/ 2 5/ 003 7/ 2 5/ 004 7/ 2 5/ 005 7/ 2 5/ 006 7/ 2 5/ 007 7/ 2 5/ 008 7/ 2 5/ 009 7/ 2 5/ 010 7/ 2 5/ 011 7/ 2 5/ 012 7/ 2 5/ 013 7/ 2 5/ 014 7/ 2 5/ 015 7/ 2 5/ 016 7/ 2 5/ 017 7/ 2 5/ 018 7/ 20 19 0 Figure 5 Heat exchanger water velocity before and after implementation of the biofilm detection and control programme used the modelling capabilities of the HexEval performance monitoring programme to categorise the heat exchangers at risk of developing biofouling, scale or both. Prior to the implementation of the performance monitoring programme, American Petroleum Institute (API) guidelines were in use. The guidelines identified at-risk exchangers as having a water velocity less than 0.91 m/sec (3 ft/sec), a cooling water outlet temperature greater than 48.9°C (120°F), and a process inlet temperature greater than 60.0°C (140°F). According to these guidelines, 233 of the 400 exchangers in the refinery were at risk of developing deposition. Managing the risk to 233 heat exchangers would have been a daunting task. However, the Marathon engineers used the heat exchanger performance monitoring programme to calculate each exchanger’s HSC value. The HSC assesses the reliability of each heat exchanger and identifies factors threatening their performance. The higher the HSC value, the greater the risk of deposition. An HSC value less than 2.0 identifies a low risk, and a value greater than 2.0 identifies an increasing risk of biofouling or scale. The calculated HSC values reduced the number of at-risk bundles from 233 to 94. After identifying the 94 at-risk exchangers in the plant, the engineers concentrated on improving the mechanical aspects of the cooling system to reduce the overall risk of biofouling and scale formation. Better transient debris mitigation using improved tower screens combined with other mechanical modifications helped to reduce the risk of fouling in the at-risk exchangers and improved the overall performance of the cooling system. These modifications included flow balancing across the exchanger network, using a hot process bypass instead of throttling the cooling water flow, adding supply side jumpers for back wash assistance, introducing metallurgical changes, and making exchanger design changes. The number of at-risk exchangers was reduced to 37. Reducing the number of ‘bad actors’ from 233 exchangers to 37 exchangers brought focus to the problem. Recalculating the HSC values revealed biofouling risk factors for 32 of the 37 problem exchangers. Clearly, these 34 PTQ Q1 2024 MARATHON SOLENIS.indd 34 results warranted a change in the microbiological control programme. To address the biofouling issue, Solenis recommended implementation of its biofilm detection and control programme on one of the refinery’s cooling towers on a trial basis. The recommended chemistry for the trial was the patented, in situ stabilised active chlorine solution. After the six-month trial, the general corrosion rate was cut by a factor of three and the pitting rates were cut by a factor of two. The refinery’s leadership decided to adopt the biofilm detection and control programme for all of its cooling towers. General corrosion rate and corrosion pitting, measured by metal coupon testing, and average weighted wall loss, measured during heat exchanger inspections by non-destructive testing, all showed dramatic improvement. After converting to the in situ stabilised active chlorine solution, corrosion rates of 0.2-0.3 mpy were achieved without pitting. Eddy current testing data collected before and after the implementation of the in situ stabilised active chlorine solution showed a decrease in heat exchanger wall loss of 45%. This loss corresponded to a 50-80% increase in bundle life. Solenis continued to monitor heat exchanger flows and cooling tower efficiency. Monitoring of the heat exchangers revealed that exchangers that historically had lost flow rapidly shortly after a turnaround now maintained their start-up flows. This improvement was validated during annual flow studies, as shown in Figure 5. Furthermore, the biofilm detection and control programme effectively eliminated algae on the cooling water return hot decks. Prior to implementing the programme, even with aggressive doses of conventional biocide, algae covered the hot decks, short-circuited the cooling tower fill, and drove up supply water temperatures, resulting in production rate reductions, until the hot decks were cleaned. After the algae build-up was removed by the new in situ stabilised active chlorine solution, the hot decks remained clean and the supply side approach to wet bulb temperatures immediately improved by -17.2°C to -16.7°C (1-2°F). Towers with high-performance fill experienced the greatest gains. The approach to wet bulb readings were monitored closely for three years. In the first year, the approach to wet bulb temperatures decreased by -16.1°C (3°F) and in the third year by almost -13.9°C (7°F). The colder water flow to the process improved vacuum on overhead exchangers, resulting in production gains with only a negligible increase in operational expense. Additional data analysis would corroborate the evidence of improved performance and profitability. Next, Solenis analysed the data and determined how many heat exchangers required cleaning outside of turnarounds and how many experienced failures before and after the implementation of the biofilm detection and control programme. If biofilm caused the fouling, then the implementation of the programme should result in fewer heat exchanger cleanings during production runs. As shown in Figure 6, the number of heat exchanger cleanings outside of turnaround decreased by 89% with the programme. If biofilm causes corrosion, fewer heat exchanger failures should result from improved biofilm control. The data www.digitalrefining.com 08/12/2023 15:56:48 Spent catalyst recycling made sustainable! In 2024, the Moxba group (Moxba, Metrex and Moxba Metalurgica Do Brasil) celebrates its 50th anniversary. Over the last 49 years we grew from metal scrap trading, via thermal spent catalyst treatment, to a full loop and fully compliant metal recycling company. We recycle over 35.000mt per annum (and expanding) of spent catalysts, as well as many other base metal bearing waste streams from many different industries, like (petro)chemical, EV battery recycling, Hydrogen production, Metal plating etc. Focusing on Mo, Ni, W, Cu, V, Zn and Co. From catalysts to filter cakes, from sludges to grindings, we fully recycle the metals from these waste streams. We produce alloys for the aerospace and stainless-steel industry, allowing them to lower the Carbon footprint in their end-product, making Green Steel/Alloys. 1 2 We hold REACH certifications on all our products, allowing us to market our products all over the globe. 3 We recycle all by-products into fertilizers, refractory materials, road constructionand cement additives. 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Bedrijvenpark Twente 15 7602 KA Almelo The Netherlands moxba.indd 1 Tel. +31 (0)546 577 400 Fax. +31 (0)546 577 600 [email protected] www.moxba.com 12/09/2023 10:21:47 35 29 25 20 18 Biofilm detection & control programme 17 15 15 10 15 11 10 9 9 5 5 3 3 3 2 2 2 2 0 0 20 20 20 20 0 20 0 20 0 20 0 20 0 20 20 20 20 20 20 20 20 20 20 20 20 20 19 19 19 19 19 0 20 0 19 23 22 21 20 19 18 17 16 15 14 13 12 11 10 09 08 07 06 05 04 03 02 01 00 99 98 97 96 95 94 -5 3 20 0 3 2 1 20 Heat exchanger cleanings (#/yr) 30 Figure 6 Heat exchanger cleanings before and after implementation of the biofilm detection and control programme presented in Figure 7 shows fewer heat exchanger failures with the implementation of the biofilm detection and control programme. The number of heat exchanger failures decreased by 85%, and no new failures have been recorded since February of 2016. Implementation of the performance monitoring and biofilm detection and control programmes provided a documented annual net return on investment (ROI) of seven figures. This ROI was based on increased crude charges, increased production through the FCC, overall increased production, reduced propane in the fuel gas, reduced frequency of exchanger cleanings, reduced frequency of cooling tower deck cleanings, and increased heat exchanger life. Overall, the programmes significantly improved the refinery’s profitability. MIC on a large cooling water system, so much so that the expense for sodium hypochlorite and non-oxidising biocide had soared to almost $85,000 per month with its existing treatment programme. The refinery leadership implemented the heat exchanger performance monitoring programme and new biofilm detection and control programme. After the implementation of the programmes, the monthly chemical expenditure decreased to roughly $10,000 per month. The system that once had experienced leaks at least annually, now saw only one leak in the three years after the implementation of the new programmes. Shortly after implementation, that ‘annual’ leak, unrelated to water chemistry, occurred again. Under normal circumstances, that amine-related leak would have resulted in an immediate need to shut down to repair the heat exchanger. Instead, the biofilm detection and control programme maintained microbiological control and corrosion rates in the system for Continued success A sister refinery experienced issues with biofilm and 12 11 11 Heat exchanger failures (#/yr) 10 9 9 8 Biofilm detection & control programme 7 5 6 6 6 5 5 5 5 5 5 4 4 3 3 3 2 2 2 2 3 2 1 1 20 20 20 20 20 23 20 22 0 21 0 20 0 19 0 18 0 17 0 16 0 20 15 20 14 13 12 20 11 20 10 20 09 20 08 20 07 20 06 20 05 20 04 20 03 0 20 0 20 02 20 01 20 00 20 99 20 98 19 97 19 96 19 95 19 94 19 19 -1 0 20 0 0 Figure 7 Heat exchanger failures before and after implementation of the biofilm detection and control programme 36 PTQ Q1 2024 MARATHON SOLENIS.indd 36 www.digitalrefining.com 08/12/2023 15:56:49 six months, enabling the exchanger to be repaired during a scheduled unit turnaround. This system has operated without a leak for more than two years and without the need for an unscheduled cleaning. The refinery intends to implement the biofilm detection and control programme in the coming year on an additional cooling tower and the influent water system. Another Marathon refinery has plans to install the biofilm detection and control programme on its two cooling towers. Marathon’s success has motivated other refineries and petrochemical operations. A petrochemical plant using impound water ran a successful trial using the performance monitoring and biofilm detection and control programmes on part of its pond system, resulting in the expansion of the programmes to two large circulating cooling water systems. Another refinery that implemented the programmes increased the flow through its cooling system by 25% within a month of implementation because of the removal of biofilm. Refinery leadership plans to expand the programmes to several cooling towers. Successful implementation at an ammonia plant allowed continued operation of the plant at a reduced cost, compared with the previous programme, despite a 50 ppm ammonia leak into the cooling water system. Thus far, a shutdown for repair has been avoided for nine months. Actual turnarounds at this facility may be yet another year away. The number of success stories continues to grow at an accelerating rate. These examples show that careful analysis of heat exchanger data to determine the causation of failure and loss of efficiency due to biofouling resulted in the implementation of a biofilm detection and control programme that delivered a large ROI for a wide variety of industrial operations. Thanks to these innovative programmes, biofilm – the hidden threat – can no longer hide. ClearPoint, OnGuard, and HexEval are marks of Solenis LLC. Brian Martin is based out of Canton, Ohio, and is responsible for Marathon’s utility water systems at its 17 plants in the US. He holds bachelor’s degrees in chemistry and biology and has 33 years of water treatment experience, seven of which have been with Marathon. Tim Duncan is based in St. Louis, Missouri, and is responsible for Solenis’ cooling water applications in North America. He holds a bachelor’s degree in chemical engineering and a master’s degree in business administration. During his 35-year career, he has held various water and wastewater management positions in the specialty chemicals industry. For the past seven years he has focused on providing technical expertise in cooling water chemistry and controls. Email: [email protected] Gordon Johnson is based in Baton Rouge, Louisiana, and is responsible for providing technical guidance for Solenis’ petrochemical business in North America. He holds a bachelor’s degree in chemistry and has 27 years of water treatment experience in oil refining and paper manufacturing. 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All Rights Reserved. www.halliburton.com/en/production/specialty-chemicals A4 halliburton.indd 1 20/06/2023 11:01:17 Simulating FCC upset operations Examples are provided of FCC upset event consequences predicted by using FCC performance simulation models Tek Sutikno Fluor Enterprises M ore than half of the world’s petroleum refineries include a fluidised (or fluid) catalytic cracking (FCC) operation generating 30-50% of the gasoline product pool of a refinery. The FCC is typically one of the most productive and profitable processing units among the refining processes. Primarily by utilising the proper catalyst type, product yield distribution can be modified for selectively maximising the yield of the gasoline blending components, light ends high in olefins, high-grade petrochemical feedstocks, or LCO (feedstock for diesel). Light ends from an FCC unit include propylene and olefins that are alkylated to produce high-octane gasoline. Likely due to its role in refinery profitability, an FCC unit often operates at much higher throughput capacities relative to the original design capacity and yields a product distribution significantly different from that of the original yield target. Field implementation of the associated revamp projects is typically completed during the scheduled turnaround period. A hazard and operability (HAZOP) review is normally necessary in each of these revamp projects to examine the design and engineering of the revamp modifications and to assess upset/deviation cases that could cause harm to people, environment or assets. Representatives from operators, unit engineers, engineering contractors, and subject matter experts (SME) are generally required to participate in the HAZOP review meetings and are expected to describe the potential consequences of an upset event where a process parameter deviates from the normal or regulated level. Due to the complexity of the FCC reactor and regenerator involving several essential operating parameters, consequences or operating impacts from a particular upset event may not be obviously known to the operators, the unit engineer, or the SME, especially if they have not observed, experienced, or analysed the same or similar event in the FCC unit. The unit engineer or the SME may likely need time to evaluate the upset consequences using an FCC performance or simulation model. However, the performance or simulation model for the FCC reactor and regenerator in a revamp or new project is commonly developed by the licensor or/and the catalyst vendor and not accessible to the engineering contractor. In these cases, the unit engineer or SME will need to work with the licensor to assess the upset consequences. Based on the severity levels of the consequences, the required protective measures are discussed and specified in the layers of protection analysis (LOPA). www.digitalrefining.com FLUOR.indd 39 Various FCC performance models are reported in the literature. However, these models involving numerous parameters are mathematically complex and likely time-consuming to utilise for a particular FCC system, in addition to the likely absence of a specific deviating parameter in the accessible models. However, recent versions of commercial simulators, such as Hysys Version 12, include FCC performance models with reasonable details of operating parameters. Performance model The Hysys Version 12 FCC performance model discussed herein is a steady-state model with several options applicable to common FCC designs. The default parameter input values in the Hysys model template are used and defined as the base case. By changing one of the input variables in the model, the operating consequences can be checked from the calculation results. The results are the steady-state operation and do not predict any actual or probable time-dependent deviation or response before reaching the steady state. Transient responses from a deviating parameter in an upset event will depend on the control schemes, which To flue gas pressure control valve Reactor effluent to main fractionator PDC TC To flue gas system Reactor LC Regenerator Stripping steam FC Regen. Cat. slide valve Main air blower/ compressor Feed steam Spent Cat. slide valve Lift steam/gas Figure 1 FCC control scheme PTQ Q1 2024 39 08/12/2023 16:07:41 Summary of example upset case consequences Base case Flow rate, BPD lb/hr Temperature to riser, ºF Steam to riser, lb/hr Stripping steam, lb/hr 37,739 508,373 347 10,124 13,879 Case 1 Lower cat. circulation rate 37,739 508,373 347 10,125 13,879 Case 2 Lower combustion air flow 37,739 508,373 347 10,124 13,879 Case 3 Higher stripping steam flow 37,739 508,373 347 10,124 16,656 Case 4 Higher feed steam flow 37,739 508,373 347 20,255 13,879 Case 5 Lower feed temp. 37,739 508,373 327 10,124 13,879 Reactor Plenum temp, °F 1,013 1,003 1,013 1,013 989 1,013 Top pressure, psig 49.3 49.3 49.3 49.3 49.3 49.3 Catalyst circulation rate, lb/hr 4,596,476 4,472,270 4,616,501 4,953,155 4,591,363 4,643,976 Catalyst-to-oil ratio 9.076 8.829 9.113 9.779 9.062 9.169 Coke yield, wt% 6.569 6.499 6.563 6.582 6.381 6.644 Delta coke, wt% 0.716 0.728 0.712 0.666 0.697 0.717 Regenerator Dense bed temp. ºF 1,373.8 1,369.0 1,372.0 1,348.3 1,341.1 1,374.9 Outlet temp. °F 1,381.1 1,376.8 1,374.3 1,356.2 1,349.7 1,381.7 Outlet pressure, psig 53.7 53.7 53.7 53.7 53.7 53.7 Combustion air, lb/hr 461,890 461,890 438,796 461,890 461,890 461,890 Flue gas, O₂, vol% 1.00 1.23 0.11 1.07 1.58 0.77 CO, vol% (dry) 0.08 0.05 0.48 0.11 0.06 0.12 CO₂, vol% (dry) 16.77 16.62 17.24 16.79 16.30 16.93 SOx, vol% (dry) 0.04 0.04 0.05 0.05 0.04 0.04 CO₂, lb/hr 111,484 110,563 108,845 111,797 108,460 112,447 SOx, lb/hr 428.6 413.8 426.4 437.2 385.0 434.6 Yields/conversions Conversion, vol% 76.83 75.26 76.62 77.77 72.18 76.96 Conversion, wt% 75.71 74.15 75.49 76.65 71.08 75.84 Propylene, lb/hr 30,881 29,067 30,725 31,108 26,619 30,874 Cat. naphtha (gasoline), lb/hr 199,372 201,571 199,097 203,101 199,362 199,703 LCO, lb/hr 68,174 71,939 68,600 66,100 77,864 67,874 Table 1 may differ from one FCC unit to another. Applications of the model for predicting the consequences of an upset case need to be consistent with the control schemes of the system being analysed. Figure 1 is an example of an FCC control scheme where the combustion air flows to the regenerator that is on flow control, and the combustion air flow rate to the regenerator will need to be kept constant in the performance model when using the model to assess the impact of different deviating process parameters. The Hysys Version 12 FCC performance model includes physical dimensions of the reactor and regenerator, feed composition and characteristics, operating parameters including common reaction kinetic parameters, catalyst selection, and details of the reaction. Property data of hydrocarbon feeds, typically ranging from the gasoil fraction of the crude oil to heavier feedstocks, including atmospheric resid, vacuum gasoils, and/or vacuum resids, can be input into the model. The calculated results from the Hysys model include fairly comprehensive parameters similar to those normally provided by the licensor. With the proper input data, the results from the model can be useful for analysing the upset conditions or off-design operating performances. For further elaboration, examples are provided of upset events from five different deviating parameters: catalyst circulation rate, combustion air flow rate, stripping steam flow rate, steam feed rate, and feed 40 FLUOR.indd 40 PTQ Q1 2024 temperature to the riser. These five were chosen as illustrative examples, but other upset events can also be modelled. The simulated consequences from the upset events discussed herein are intended to show the resulting operational changes at the steady-state condition and have not been checked against the actual field operating data. Moreover, for extreme or severe upset cases such as loss of flow, the model will not be applicable directly to these cases, which typically result in activating the shutdown system. However, the model can be used to generate reference data likely useful for developing a dynamic model, which is typically needed to determine the process safety time available for system shutdown. Catalyst circulation rate Catalyst circulation rate is an essential parameter or variable determined by the heat balance between the reactor and the regenerator. An FCC reactor involves both exothermic and endothermic reactions, resulting in a net total endothermic reaction. The heat required for increasing the sensible heat of the feed, vaporisation, and the net endothermic reaction is supplied by the temperature drop of the circulating catalysts as they pass through the reactor. The resulting catalyst-to-oil ratio (C/O) affects the cracking reaction yield conversions and reactor temperatures. With increasing C/O, active sites www.digitalrefining.com 08/12/2023 16:07:42 PRECIOUS METALBEARING CATALYST RECYCLING EXPERTISE We recover and refine precious metals from hydrocarbon and petroleum processing catalysts. Also, our proprietary Pyro-Re® process offers the only pyro-metallurgical recovery of rhenium in the industry. With it, we recover total rhenium content from spent semi-regenerative and cyclic fixed-bed hydrocarbon processing catalysts—and get you a full return. With best-in-class techniques and over seven decades of experience, we deliver the highest possible metal returns for our customers. Learn more about our services at sabinmetal.com Q2-Sabin.indd 1 04/04/2022 10:46:33 increase to cause more cracking and higher conversion of gasoil, and the yield of fuel gases and coke increases. Common parameters such as coke yield and delta coke (wt% difference between the spent catalyst and the regenerated catalyst) can be related to C/O. For a given FCC reactor and regenerator system with the same feed rate and characteristics, the catalyst (regenerator) circulation rate increases with changes in process conditions such as higher reactor riser temperature, lower feed preheat, or others demanding additional heat input to the reactor. While the Hysys model includes fairly complete input and output parameters commonly used in FCC performance modelling, only some are displayed in this discussion. As an example of upset cases in the normal catalyst circulation rates in Case 1, Table 1 shows the changes or consequences relative to the base case when the catalyst circulation rate in Case 1 reduces by 2.7% (arbitrary, about 120,000 lb/hr reduction). This reduction decreases the C/O, the reactor temperature (1,013-1,003ºF), and, expectedly, the total conversion. Due to the decreased catalyst circulation, the resulting delta coke in Case 1 increases slightly to satisfy the system heat balance even at the reduced reaction temperature of 1,003ºF, and the resulting coke yield (equal to delta coke x C/O) decreases slightly. For FCC units with control schemes similar to Figure 1, the air flow rate from the main air blower will remain essentially unchanged when a lower set point for reactor temperature reduces the catalyst circulation rate. Compared to the base case, Case 1 in Table 1 shows a reduced yield conversion, mainly with lower propylene and slightly higher yields for cat naphtha and LCO. This yield distribution varies depending on the selectivity and activity of the catalysts selected. The Hysys model contains several options for catalyst types to select. Modern catalysts can accumulate some quantities of coke and still maintain significant activity. Recent revamp options include recycling fractions of the spent catalysts (or carbonised catalyst) from the stripper back to the reactor riser. The Hysys model also includes this recycling option, which offers the flexibility of increasing the C/O in the reactor riser to increase conversion and selectivity without significantly impacting the system heat balance. Combustion air flow Case 2 in Table 1 shows the calculated results for operation when the combustion air flow rate from the main air blower to the regenerator is reduced by 5%, relative to that for the base case. As shown, flue gas oxygen content drops from 1 vol% in the base case to 0.11 vol% in Case 2, and CO content in flue gas increases from 0.08 vol% in the base case to 0.48 vol% in Case 2, which is six times higher due to less excess oxygen. The regenerator will operate in partial burn if combustion air further reduces to below 0% excess oxygen in the flue gas. With reduced inlet air flow in Case 2, CO₂ vol% increases in Case 2 compared to that in the base case. Reduction of O₂ vol% in flue gas to 0.11 vol% in Case 2 decreases flue gas temperature rise in the regenerator dilute phase due to afterburning of CO, as depicted by a lower regenerator flue gas temperature of 1,374ºF in Case 2 vs 1,381ºF in the base case. Additionally, combustion air to the 42 FLUOR.indd 42 PTQ Q1 2024 regenerator in each case of Table 1 does not include any oxygen enrichment, but this option is available in the Hysys FCC model. Reactor feed streams (hydrocarbon and steam) and outlet temperature do not change from the base case to Case 2, and heat transferred from the regenerator to the reactor through the circulating catalyst remains about the same for both the base case and Case 2. The combusted amount of coke on spent catalysts mainly converted to CO₂ (in full burn operation) to supply required heat remains essentially the same for the base case and Case 2, as shown in the essentially unchanged coke yield data (coke combusted in regenerator relative to the feed rate). Stripping steam Case 3 in Table 1 shows the calculated results from the Hysys model for operating with a stripping steam rate 20% higher than the base case. This high stripping steam rate could occur because of operator action or the control valve sticking open. The increased stripping steam rate reduces the amount of heavy hydrocarbons or coke on the spent catalyst, leaving the stripper and recycling back to the regenerator. As the reactor feed rate and outlet temperature in Case 3 remain the same as those in the base case, the reduced combustibles on the spent catalyst to the regenerator increase the required catalyst circulation rate by about 7.7% to generate the unchanging heat demand of the reactor and decrease delta coke by about 7%. As shown in Table 1, the Hysys model results in increasing the conversion from 76.83 vol% in the base case to 77.77 vol% in Case 3, mainly due to the increase in catalyst circulation rate or C/O. Relative to the base case, mass flow yields for propylene and naphtha are respectively 0.7% and 1.9% higher, with a reduced yield of -3.0% for LCO. Steam feed rate The FCC reactor typically includes several steam feed streams, including those for catalyst transfer line aeration, feed atomisation, riser lift and emergency purge, stripping, and others such as instrument purging. When the control valve for one of these steam feed streams malfunctions and becomes wide open, the total steam rate feeding the reactor will increase. Case 4 in Table 1 shows the results when the steam feed rate to the riser increases by 100%. The steam feed rate could potentially increase by higher than 100% of the normal rate if the emergency steam control valve becomes wide open. Steam feeding the reactor is superheated, but the temperature is much lower than the riser operating temperature. The sensible heat required to raise the steam temperature in the riser comes from the regenerated catalysts entering the riser. When the steam flow rate to the riser increases, the riser and reactor temperatures could drop before the regenerated catalyst flow rate increases to a level adequate for reaching and maintaining the reactor normal set temperature. Case 4, with the same catalyst circulation rate as that in the base case, shows the reactor (plenum) temperature drops from 1,013ºF in the base case to 989ºF when the steam feed to the riser increases by 100%. The Hysys www.digitalrefining.com 08/12/2023 16:07:43 model shows the conversion yield reduces from 76.83 vol% in the base case to 72.18 vol% in Case 4. The reduced conversion yield in Case 4 has a 14% reduction in the propylene yield and virtually none in the naphtha yield, based on the selected catalyst type in the model. Moreover, a higher total steam feed rate to the reactor will increase the hydraulic load to the downstream system and could result in a pressure surge in the reactor and the associated systems. Feed temperature to riser Hydrocarbon feed to the FCC reactor typically passes through a preheat system, receiving heat rejected from exchangers in the downstream system. Excessive exchanger fouling or malfunctioning of the exchanger bypass control system could reduce the temperature of the reactor feed. Case 5 in Table 1 shows the Hysys model results for operation with 20ºF less feed temperature to the reactor riser. With the reactor temperature kept the same in the models for both Case 5 and the base case, more heat is needed in Case 5 to compensate for the 20ºF drop in the feed inlet temperature, and the catalyst circulation increases by about 1% in Case 5 relative to that in the base case. The resulting higher C/O from the increase in the catalyst circulation rate in Case 5 also leads to a slightly higher yield conversion. With the combustion air flow rate set the same in the models for Case 5 and the base case, the higher catalysts circulation rate in Case 5 reduces the excess oxygen content of the flue gas from the regenerator, and the vol% of CO and CO2 in the flue gas also increases. Compared to the base case, the Case 5 model calculates a slightly higher delta coke and about 0.8% higher CO2 emission. Conclusion Based on the upset events due to process parameter changes previously discussed, the FCC model in Hysys seems useful for predicting reasonable details of performance consequences resulting from the selected upset events. The model apparently includes reaction kinetics parameters to calculate yield distributions, flue gas compositions, and heat balances at varying operating conditions. Several catalyst type options with varying selectivity performances for specific yield distribution targets are also available in the model, along with the design and operating options, such as combustion air oxygen enrichment and recycling a fraction of spent catalyst to the reactor riser. Utilising the model to simulate these options has not been included in this discussion but may be considered. Moreover, fine-tuning the model input parameters and verifying the calculation results against actual operating data could likely make the model useful for quantitative assessment of consequences from upset events or for process design analysis and optimisation. Tek Sutikno is a Process Engineering Manager with Fluor and a Professional Engineer registered in 11 US states with more than 35 years of experience in the process industries. He holds BSc, MSc, and DEngr degrees in chemical engineering and a MBA degree, all from the University of Kansas. Email: [email protected] Process Engineering ToolS 5.0 Engineering Software for All Disciplines Visit Website for Free Trial ProcessEngineeringToolS.com Process Engineering ToolS (PETS®) 5.0 combines many engineering calc�la�ons in�o one economical easy �o �se so��are �ro��c�. PETS® can be �se� �o si�e a single �iece o� e��i�men� or �esign an en�re �lan�. SRK Flash & Physical Properties Relief Calculations Drum & Droplet Sizing Tank Level Alarm Management ASTM Distillation Conversion Orifice Sizing English & SI Units Pipe System Hydraulics Pump & Compressor Sizing Heat Exchangers & Air Coolers Column Tray Hydraulics Control Valve Sizing Tank Inbreathing/Outbreathing Over 30 ToolS included . . . . Phone: (281)335-7138 | E-mail: [email protected] www.digitalrefining.com FLUOR.indd 43 PTQ Q1 2024 43 08/12/2023 16:07:43 Sulfur extraction expertise maximized. THIOLEX™: Removes mercaptans, H2S, COS and other acids from LPG, NGL and condensate streams Taking full advantage of our non-dispersive FIBER FILM® Contactor, THIOLEX technology delivers high-efficiency sulfur extraction with minimal caustic carryover in liquid and gas streams. Its compact footprint reduces space and CAPEX. With hundreds of licenses and over 75 years of expertise, companies can count on Merichem to keep their operations flowing and on spec. www.merichem.com/thiolex 713-428-5000 The experts in sulfur reduction, removal and spent-caustic reuse. merichem.indd 1 12/12/2022 14:28:51 Refractory detection system and floating roof protection New refractory detection system monitors skin temperatures in Claus or thermal oxidisers as well as SMRs, gasifiers, and emissions from floating roof tanks Bob Poteet and Andrea Biava WIKA Haytham Al-Barrak and Mahendran Sella Saudi Aramco T here are many applications in the process industries where detecting a hotspot on the outside of an operating unit can bring safety and protection of valuable assets, such as the refractory detection system (RDS) under discussion. This technology can be used in a variety of applications, such as in the Claus section of a sulphur recovery unit (SRU). An installation was recently completed at the Aramco gas plant. The results Aramco saw in its investigation after six months of run-time (now 12 months running) will be discussed, in addition to some other applications. The device’s potential applications are only limited by the processor’s imagination (see Figure 1). So, what exactly is this technology? The heart of the system is a special sheath (typically 4.5mm or 3/16in) made of 316SS that only reads out the highest temperature anywhere along the sheath. To install the system on a Claus unit, first divide the unit into zones, which are areas designated for sensing. As illustrated, there can be anywhere from one to six zones in most Claus units, depending on the licensor or operator’s preference. The readout from each zone will resemble a type K thermocouple, but it indicates the hottest area in a zone. You will not know where the hotspot is in the zone, but you will be aware that one exists so that appropriate action can be taken (see Figure 2). This technology has been successfully running on a Claus unit for more than 12 years at a major refinery in Italy. reading. Older transmitters can be used that read below 0°C, but careful consideration would need to be made in the evaluation process • Above 400°C, the readings will lose their reliability again, but they have done their job. No damage will occur to the system until it reaches 900°C. Uncertainties The industry standard has been to attach thermocouples, but nobody knows how many to install. As a result, many installations do not have any thermocouples at all. Thermocouples can indicate the temperature of a specific point, but temperature excursions in other areas will go undetected. If a reactor with thermocouples could be covered, costs increase substantially. The American Petroleum Institute (API) states that an operator should have a system so that an ‘accurate shell temperature measurement system under the shroud should be included in the ETPS design.’ They also request routine thermal imaging of the external shell to spot-check the thermocouples. This can be a maintenance headache if followed as it is intended. Refractory problems in Claus or thermal oxidisers For many operators of SRU plants, detecting refractory problems in the Claus unit can keep them up at night. If the refractory starts to fail, a situation may occur where the hot gasses hit the carbon steel shell and damage or lead to failure of the wall of the reactor. Many ways to detect this have been tried, but they all have limitations. Some have tried thermal imaging, but the problem with rain shields, cowlings, and insulation can be a real barrier. A couple of points should be noted: • This is not a thermocouple. Modern transmitters have self-diagnostics built in, and readings below 120°C are not reliable. While we can prove the system is working at installation, you will have to start the unit without a stable www.digitalrefining.com WIKA.indd 45 Figure 1 Refractory failures at high temperatures are difficult to pinpoint. PTQ Q1 2024 45 08/12/2023 16:11:42 Temperature values sensed by CTLS (WIKA) just two months after installation Time stamp ∆P - kPa TC/PYRO 1 Feb-11, 5:30pm 7.1 kPa IR Survey ºC 1. 203 2. 206 3. 208 4. 203 5. 201 6. 208 CTLSºC Observation 1. Faulty* CTLS is working 2. 213 3. 235 4. 233 5. 248 6. 242 2 Feb 15, 6:30pm 7.6 1074 1. 213 2. 213 3. 218 4. 211 5. 213 6. 217 1. Faulty* 2. 232 3. 244 4. 233 5. 239 6. 221 CTLS is working 3 Feb 16, 6:30pm 7.5 1090 1. 194 2. 196 3. 204 4. 196 5. 204 6. 211 1. Faulty* 2. 213 3. 228 4. 221 5. 235 6. 213 CTLS is working 4 Feb 17, 7:30pm 7.5 1084 1. 178 2. 183 3. 188 4. 183 5. 195 6. 201 1. Faulty* 2. 210 3. 222 4. 217 5. 234 6. 211 CTLS is working 5 Feb 18, 9:30pm 7.5 1083 1. 200 2. 204 3. 212 4. 202 5. 205 6. 211 1. Faulty* CTLS is working 2. 228 3. 240 4. 232 5. 240 6. 221 Table 1 Temperature values sensed by CTLS (WIKA) just two months after installation closely represent the true values as cross-verified by an IR camera survey Throughput vs burner ∆P vs reaction temperature vs outer shell temperature % Acid gas throughput 25 35 45 55 65 75 85 95 100 Burner ∆p, kPa 0.8 1.07 2.13 3.2 4.3 5.3 6.4 7.5 8.8 Hot face (firebrick) Shell outer skin temperature, ºC temperature, ºC ~ 1000 ~ 1033 ~ 1067 ~ 1100 ~ 1133 ~ 1167 ~ 1200 ~ 1233 ~ 1250 210 ± 15 212 ± 15 216 ± 15 218 ± 15 221 ± 15 225 ± 15 229 ± 15 234 ± 15 238 ± 15 Table 2 Aramco findings In an effort to resolve technical challenges, Saudi Aramco (SA) piloted a newly developed RDS to monitor the skin 46 WIKA.indd 46 PTQ Q1 2024 surface temperature of SRU thermal reactors (reaction furnace). Since 90% of SA SRU units are shrouded (weathershielded), measuring the surface temperature online becomes challenging. Without the correct monitoring device in place, catastrophic failures could occur, affecting plant throughput. Deployment of this technology aims to detect repetitive refractory failures early by sensing hot spots on the reactor surface, even with the presence of a shroud. Maintenance and shutdown will be planned and timed accordingly. Collaboration between the technology provider, WIKA, and SA began in March 2022 with the installation of the thermocouple on one of Saudi Aramco’s gas plant SRUs. In October 2022, the CTLS installation was completed and successfully tested. The plant continued monitoring the unit, keeping a close eye on the measured skin temperature to confirm continuous and reliable outputs (see Table 1). Upon testing performance, the new linear thermocouple technology proved to be working well. The CTLS coils’ peak www.digitalrefining.com 08/12/2023 16:11:42 10 100% throughput - 8.8 kPa 95% throughput - 7.5 kPa 67104 85% throughput - 6.4 kPa 75% throughput - 5.3 kPa Delta pressure (kPa) 65% throughput - 4.3 kPa 55% throughput - 3.2 kPa 45% throughput - 2.13 kPa 1 35% throughput - 1.07 kPa 16776 25% throughput - 0.8 kPa Acid gas / MW=37.88 0.1 10000 16776 23486 30197 36907 43617 50328 57038 63749 67104 100000 Capacity (kg/h) Figure 2 Burner capacity curve showing the capacity vs ΔP Figure 3 RDS unit installed outside reactor by a trained crew Figure 4 Close-up view of Nelson studs applied to reactor temperature readings were recorded at 10 different time stamps over the course of eight months of operation since the coils were first put into operation. This is a great tool, but based on our first use, we believe the way forward is if we had the ability and freedom to move the thermocouple CTLS while the unit is running without the need to weld on the reactor casing. We are jointly evaluating the use of magnets to facilitate this feature. Industry feedback Installation The RDS is installed by a trained field crew. Nelson studs are applied to the reactor, and the system is held down by galvanised steel channels attached to the Nelson studs. This system ensures good contact between the RDS and the reactor shell. On a larger Claus, it took a three-man crew five to six days to completely install a six-zone unit (see Figures 3 to 5). www.digitalrefining.com WIKA.indd 47 An Italian refiner who had this bespoke system installed 12 years ago agreed to provide feedback, reporting that he knew of no other system that could provide the required coverage, particularly the need for system reliability. While two of the four zones were lost after contractors cut components, a high level of reliability was still maintained. We enquired if the system had ever alarmed during the 12-year period and he reported that it had only done so twice. In neither case did the hotspot reach the point where he had to shut down. However, during the next routine maintenance, they could see that in the zones where the alarm occurred there were indeed some refractory problems. Other applications Other applications include: • Gasifier applications: Gasifier applications are very similar to the Claus but in a much larger way with more PTQ Q1 2024 47 08/12/2023 16:11:44 Figure 6 Installed scraping and sealing solution for a floating roof tank Figure 5 Multi-zoned RDS unit installation zones. The sensors are run vertically over the full unit and at the top. • Steam methane reformers (SMRs): The outlet header in an SMR is a refractory line piping that requires constant monitoring of the outside temperature by operators. Some use thermocouples, while others just do scanning. A common question related to thermocouples is how many are needed to give complete coverage while the scanning is a real Opex cost. For this solution, we can simply wrap the pipe with the RDS and monitor for any refractory failures. This can be easily installed with a clamping system or even magnets. • Floating roof oil storage: There have always been concerns about the possibility of generating a fire in a floating roof tank (see Figure 6). For their conformation, these tanks have a mobile roof that slides along the vertical axis of a metallic structure fixed cylindrically. To avoid product leaks during the sliding of the roof, a scraping and sealing system (seal) is installed. The seal, made of rubber, undergoes continuous mechanical vertical movement and is exposed to corrosive agents contained in the product, usually hydrocarbons. Over time, it deteriorates and emits vapours released by the stocked product, which is normally maintained in the tank at a variable temperature between 70°C and 90°C. Under certain climatic conditions, this escape of vapours can trigger fires that cause significant damage to plants, the environment, and staff. Protecting these tanks with fire detection systems is therefore essential. However, deterioration of the coating material of the linear heat detection 48 WIKA.indd 48 PTQ Q1 2024 cable (thermowire) can often generate false alarms. This uncertainty is a sign of low sensor reliability and creates a challenge for operators, who must decide when and how to intervene. It is important to decide whether the system should be turned off immediately or, if a false alarm is suspected, the field cause of the alarm should be verified. In the former case, restoration of the area under consideration would result in high costs. Over time, multiple false alarms can cause staff to consider a system unreliable and, therefore, of little use. The third option would mean, in case of ignition, a delay in activating the fire extinguishing system with its related consequences. To avoid these problems, it is therefore necessary to maintain detection systems with technical features that are immune to false alarms and can respond immediately. Moreover, by continuously monitoring the temperature near the seal, valuable information about the wear of the seal can be provided to the operator, allowing for intervention prior to a critical situation arising. Advantages include: • Increased level of security • Increased functional efficiency and durability • Programming of maintenance interventions • Self-recovery sensor after the intervention of the alarm • Reduced cost of insurance premiums, as the provision of prevention systems reduces the level of risk, thus increasing the level of security. Bob Poteet is Director of Business Development for the Global Project Business group at WIKA, Houston, Texas. He graduated from Texas A&M University. He has four patents in temperature sensing areas used in the process industries. Andrea Biava is Business Development Manager for Electrical Temperature and Services at WIKA Italia. Haytham Al-Barrak is a Fired Equipment Engineering Consultant at Saudi Aramco. He holds an MS in mechanical engineering from University of Southern California. He has two patents in fired equipment monitoring. Mahendran Sella is a Heat Transfer and Combustion Engineer at Saudi Aramco. He holds a BS degree in mechanical engineering from Institute of Engineers, India. www.digitalrefining.com 08/12/2023 16:11:45 100% USDA PRIME FTC filtration keeps your cash cow flowing FTC filters provide consistent effluent quality with the most predictable filtration of impurities as feedstocks change in renewable fuel production. Keep your cash cow flowing with reliable pre-treatment of your catalyst feed. Beef up your filtration system. And eliminate unplanned shutdowns. 7 13.8 49.0849 ftc-houston.com FTC.indd 1 08/12/2023 12:51:42 It starts with water. With over 95 years of experience in industrial water and process management from Nalco Water, and digital twin technology from Siemens, you can reap the benefits of near-real-time, actionable insights - without large investments of time and money. Start taking steps right away to: Reduce energy consumption Improve asset reliability Lower operational costs Water is at the heart of productivity, efficiency, and reliability of your operations. Contact us today to help you achieve smart water and fast results. ecolab.com/climate-intelligence ©2023 Ecolab USA Inc. All rights reserved. AD-032 1223 nalco.indd 1 11/12/2023 10:36:34 Crude to chemicals: Part 2 Part 1 covered the basics of crude-to-chemicals. Part 2 explains how hydroprocessing technology can be used to convert any crude to chemicals to maximise yields Kandasamy M Sundaram, Ujjal K Mukherjee, Pedro M Santos and Ronald M Venner Lummus Technology S audi Aramco Technologies Company, Lummus Technology, and Chevron Lummus Global (CLG) conducted several years of research to develop an improved thermal crude-to-chemicals technology known as Thermal Crude to Chemicals (TC2C). This proprietary technology can produce high chemicals yields while extending the feedstock range beyond just very light crudes or condensates typically considered. The research and subsequent commercialisation of the technology involved the following vital steps: • Very detailed componential analysis of crudes and heavy oils • Development of specialised separation devices to separate the crude into fractions for optimised processing without having to utilise energy and Capex-intensive crude atmospheric and vacuum distillation • Utilisation of commercially proven integration of fixed bed, ebullated bed, and slurry reactor systems in crude conditioning so that the products from the crude conditioning section could be routed directly to the steam cracker • Development of unique catalyst systems for the fixed bed and ebullated reactors that would provide the right amount of hydrogenation without overcracking to naphtha, LPG, and light ends • Rigorous testing of the impact of varying amounts of pyrolysis fuel oil recycled from the recovery section. TC2C successfully upgrades the pyrolysis fuel oil to steam cracker reactor feed. Throughout the development, particular attention was paid to minimising equipment count (Capex), energy input, carbon footprint, emissions, catalyst deactivation rate, and the reactor fouling rates for various feeds. Overall, hydrogenation improved the steam cracking reactor feed quality. The integrated crude conditioning/steam cracking reactors/ recovery systems formulate the integrated TC2C technology. evaluated compounds with a hydrogen deficiency or ‘Z’ value. He showed that complete hydrogenation and ring opening with no change in carbon number could consume vastly different amounts of hydrogen depending on the ‘Z’ value. The general formula is: CnH2n+Z where Z = 2-2*(R+DB) n = number of carbon atoms R = number of rings, DB = number of double bonds, Z = hydrogen deficiency. In all crudes, the hydrogen deficiency increases with boiling point with a higher concentration of condensed rings, as previously shown in Part 1 (PTQ, Q4 2023). Typically, the highest boiling fractions in crude (containing what is broadly termed asphaltenes) are the most difficult to convert to transportation fuels or petrochemical feedstocks. Indeed, the analysis of asphaltenes using advanced techniques formed part of the research. In TC2C, a naturally abundant n-paraffin-rich light stream is separated with a novel separation device such that it eliminates heavier molecules from the product that is routed to the steam cracker, as previously shown in Part 1. This step uses dilution steam to vapourise the light cut. Bottoms from the separation device are routed through another separation Truncated VGO (470-495˚C BP) www.digitalrefining.com LUMMUS.indd 51 15 15 17 17 24 26 Full range VGO (500-525˚C BP) Crude analysis and conditioning There have been many attempts to characterise crude through detailed compositional analysis.1,3 In the lower carbon numbers, the total number of n-paraffins, i-paraffins, naphthenes, and aromatics is reasonable and easily identified. With increasing carbon numbers, the number of possible compounds increases exponentially. Boduszynski3 started evaluating crude using detailed compositional analysis. It is well known that diverse compounds with similar molecular weight cover a broad boiling range. Boduszynski 15 VR (580-605˚C BP) 19 22 Figure 1 DBE values of some species (DBE=C+1-H/2X/2+N/2; X is halogen, C, H, N are carbon, hydrogen, and H atoms respectively) PTQ Q1 2024 51 08/12/2023 16:32:29 Vacuum residue Pyrolysis oil 50 39 High 31 40 35 27 % Total DBE DBE 30 23 19 20 15 11 10 7 0 10 20 30 40 50 60 70 80 90 0 10 Low 20 30 Carbon number 40 50 60 70 80 90 Carbon number Figure 2 Double bond equivalent vs carbon number for residue and fuel oil Typical pyrolysis oil properties API Sulphur, wt% Nitrogen, wppm Hydrogen, wt% MCRT, wt% Simdist,ºC 0.5 wt% Table 1 52 LUMMUS.indd 52 PTQ Q1 2024 10.3 1.01 592 8.65 4.47 164 5 wt% 50 wt% 95 wt% 99 wt% Recovery, wt% Metals by ICP, wppm 200 267 606 735 98 44 The measured DBE of a typical ethylene plant pyrolysis fuel oil and a residue are shown in Figure 2. Typical pyrolysis fuel oil characteristics are shown in Table 1. Within the integrated hydrocracking system, the catalysts system and operating conditions are carefully controlled such that DBE is restricted to 15 or lower in the effluent. Slurry hydrocracking utilising a very special catalyst can increase the conversion of residue to more than 97%. The addition of pyrolysis fuel oil to the residue feed increased the residue conversion significantly. The remaining unconverted oil is filtered and sent over a fixed bed reactor system to meet IMO-compliant very low sulphur fuel oil (VLSFO) specifications (<0.5 wt% sulphur). Thus, TC2C ensures that no part of the converted crude is wasted while maximising the yield of chemicals. Changes in DBE before and after an LC technology are shown in Figure 3. High DBE value species are almost reduced to zero. When a crude is primarily used to produce chemicals only, it is important to know whether it is worthwhile to upgrade it or not. Upgrading typically requires either carbon rejection or hydrogen addition. Upgrading naphtha may not improve the olefin yields significantly, and it produces only a small quantity of fuel oil. 10 D2007 corrected abundance device that separates a heart cut with carbon number varying between 20 and 35, depending on the TC2C variant. The heart cut is sent for fixed bed hydroprocessing to remove nitrogen and sulphur, hydrogenation of aromatics, ring opening and hydrocracking. The catalyst systems are carefully selected to optimise the molecular profile for subsequent processing. The heaviest fraction of the crude with a carbon number exceeding 35 is routed to a liquid circulation (LC) reactor with either extrudate or slurry catalyst. These reactors have small online catalyst addition and withdrawal capabilities and can run continuously for more than five years. LC reactor information can be found elsewhere.2 The liquid circulation reactors convert the asphaltene and recycle pyrolysis oil from the ethylene plant to lighter components that are hydrotreated/ hydrocracked to suitable steam cracker feed. This system ensures no heavy polynuclear aromatics (HPNA) reach the steam cracker. Some known structures that impede the full conversion of residue hydrocracked VGO are shown in Figure 1. Through extensive analysis of commercial data from residue hydrocracking and tailored pilot plant tests, residue hydrocracking has an increased concentration of double bond equivalent (DBE) value of 15+ compounds. For pure hydrocarbons, DBE=C+1-H/2, where C is the number of carbon atoms, and H is the number of hydrogen atoms. It represents the level of unsaturation or hydrogen deficiency. 9 8 7 6 5 Before After 4 3 2 1 0 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 DBE Figure 3 Changes in DBE before (blue) and after (red) hydrocracking www.digitalrefining.com 08/12/2023 16:32:32 Hydrogen manufacturing Natural gas Hydrogen Light oil Heat Cooling Crude oil Desalter Middle oil Tailored separation HOPS Tricle flow reactors C9+ Low-value streams Liquid circulation reactors Crude conditioning section Stripped sour water Tricle flow reactors Sour water Stripped sour water unit Lean amine Steam cracker complex Chemicals Pyrolysis oil VLSFO Rich amine Amine regeneration unit Sulphur recovery unit Sulphur Figure 4 TC2C flow scheme with liquid circulation reactor configuration. The total yield of chemicals ranges from 70 to more than 85 wt%, depending on the nature of the crude The qualities of gasoil and vacuum gasoil are reasonable, but when cracked they produce a significant amount of fuel oil. The intent of a crude-to-chemicals project is to maximise chemicals production and, hence, the target was to minimise fuel oil. Hydroprocessing will upgrade the quality of the feeds. In the previous section, various cuts are obtained by vapourising the crude at a lower temperature by adding steam in the heavy oil processing system (HOPS) tower. Dilution steam is also required for thermal cracking to reduce hydrocarbon partial pressure to increase olefin yields and suppress coking. However, though a small quantity of saturated water in oil is not harmful to hydroprocessing catalysts, the levels required for thermal cracking are detrimental to the catalyst. TC2C utilises a novel separation device and targeted hydroprocessing of fractions to provide the right amount of hydrogenation of feeds to the steam cracker reactor for maximum crude conversion. The simplified flow scheme is shown in Figure 4. The importance of the desalter must be stressed at this time. Crude can come from different sources and different transport methods. This will contain some debris and salts. Ppm chloride levels cause havoc on material selection, requiring equipment to be alloyed up for resistance against chloride corrosion. Ppm sodium levels are sufficient to cause significant damage to catalysts, especially when the target run lengths exceed five years. Hence, the investment in desalters and feed filter systems is worthwhile and justified. The desalted crude goes to the first-stage HOPS, where naphtha mixed with steam is separated for the steam cracker. The material heavier than naphtha in the crude enters the tailored separation section. The fixed bed hydrocracking reactor and liquid circulation reactor technologies previously explained are used to condition the feed. Typically, www.digitalrefining.com LUMMUS.indd 53 an ethylene plant turnaround exceeds five years and, hence, all sections are also designed to last that period. An important TC2C feature is the ability to utilise the pyrolysis oil generated by the steam cracker in the liquid circulation reaction section. The addition of pyrolysis oil with the feed to the liquid circulation reaction section where asphaltene conversion occurs permits higher conversion of asphaltenes while maintaining product stability. During research and development, several types of pyrolysis oils were tested, including very high proportions of pyrolysis oil in the feed mix, to ensure the concept was robust. Extensive pilot plant results show that at low catalyst consumption, heavy boiling material can be converted easily to high-quality feeds for olefins production. This is one of the major benefits of the integrated steam cracker/LC reactor system. Low-value fuel oil is upgraded to high-value chemicals. More than 90% of feed conversions can be achieved at very low catalyst consumption in the liquid circulation reactor platform. Very low sediments were also observed, improving the operation of downstream units. Many CLG-designed integrated LC-Fining/hydrocracker plants have been in operation over the last 25 years for producing jet and diesel quality fuels and some as feed to ethylene plants. When certain catalysts and operating conditions are used in the hydrocracker, certain types of species are produced in the hydrocracker which are not present in the feed. A lot of research was conducted to limit the high DBE HPNA from reaching the cracker so there would be no highly condensed molecules such as coronenes (six ring) and ovalenes (10 ring) in the steam cracker feed. These molecules deposit as solids, fouling the transfer line exchanger.4 The resulting run length could be a few hours instead of a few PTQ Q1 2024 53 08/12/2023 16:32:38 in SRT ethylene furnaces are given in Table 2. The balances are based on Arab Light crude, and for Case 1, a typical Middle Eastern full-range naphtha is used for comparison. Case 1 2 Acetylene and MAPD are hydrogenated with appropriate Feed Naphtha Crude selectivities to their respective olefins. Ethane and propane Feed, KTA are recycled to extinction. For this case study, all C5 species Full-range naphtha 4,132 are fully hydrogenated and recycled to extinction. Benzene, Naphtha from crude + TC2C toluene, and xylenes (BTX) are extracted and considered crude conditioning 1,524 Gasoil from TC2C crude conditioning 3,045 valuable products. C6-C8 raffinate is recycled to extinction. LPG from crude + TC2C C9-204°C is a heavy gasoline containing a high concentracrude conditioning 233 tion of C9-C10 aromatics. It is processed in the feed prepaSteam reacted 4 5 ration section and recycled to heaters for crude cracking. Total 4,136 4,807 Pyrolysis gasoil (PGO) (204°C-288°C) and pyrolysis fuel oil Products, KTA (PFO) (288°C+) are generally sold as products. The salient H2 product 46 43 feature of TC2C technology is the ability to upgrade these Methane-rich off-gas 722 671 materials to high-value products, as shown in Figure 4. A PG ethylene 1,500 1,500 PG propylene 649 750 small amount of residue is always purged to minimise the Butadiene 195 245 coke precursors circulating in the system. This is taken out Other C4s 167 230 as VLSFO for Case 2, as shown in Figure 4. Case definitions BTX 569 603 shown in Table 2 are further discussed: Heavy gasoline 90 126 • Case 1 is a standard naphtha cracker. Only C2/C3 recycle, PGO 66 195 PFO 126 441 fully hydrogenated C5s, and hydrogenated C6-C8 raffinate Acid gases 4 3 are recycled to extinction. Total 4,136 4,807 • Case 2 – TC2C for the configuration shown in Figure 4. All recycles of Case 1 and recycles with C9-204°C and pyrolysis High-value chemicals 3,119 3,351 fuel oil after treatment. Amount of crude, KTA 4,444 Valuable chemicals include hydrogen, ethylene, propylene, Crude, BBL/day 93,344 butadiene, butene, and BTX. VLSFO is also valuable but not % HV chemicals to crude 75.4 included in this study since it is considered a fuel product. Table 2 Upgrading the feed (Case 2) by hydroprocessing produces the highest amount of valuable chemicals per unit of crude. months. Therefore, CLG and Lummus have strict monitoring The naphtha cracker is the simplest liquid cracker. When procedures for the HPNA of the cracker feeds. only thermal cracking (no hydroprocessing) is considered, a Optimum hydrocracker reactor operation and conversion significant amount of residue must be rejected. are essential for high ethylene yield and long run length. In addition, vacuum gasoil range molecules must be This is achieved by passing the products of the LC reactor cracked with a higher steam-to-oil ratio. They consume through the fixed bed reactor, which further improves the more crude and more energy. With hydrocracking options, quality of cracker feed and reduces polynuclear aromatics residue is also used to some extent. Almost all PGO and (PNAs). Not only materials (chemicals and refrigerants) are PFO produced in the cracker are recycled after upgrading. exchanged between the ethylene plant and hydroprocess- Therefore, crude consumption is significantly reduced. The ing (feed preparation) section, as heat integration (steam amount of high-value chemicals is also increased signifiand fuel system) is also essential for energy conservation cantly. A cost is associated with this configuration as it and CO₂ minimisation. requires the incorporation of select components for hydroTC2C maximises olefins from any crude. FCC is an effec- cracking, residue hydrocracking, and a hydrogen manufactive way to produce propylene, and Lummus has introduced turing plant. both Indmax and single regenerator dual catalyst (SRDC) Considering the reduction in crude and the increase in technology to maximise FCC propylene. Experimental data high-value chemicals, the increase in Capex is justified and is and model calculations clearly show the maximum amount substantially less than a classical refinery configuration. The of total valuable chemicals is achieved through the hydropro- payout is less than two years for most locations. With light cessing/steam cracker route, which also produces the high- crudes, such as Permian, as high as 70% high-value chemiest amount of ethylene with the lowest crude consumption. cals instead of 50% for Arab Light crude can be obtained in thermal mode,5,6 and with TC2C more than 80% high-value Ethylene plant chemicals production is possible. The previous sections discuss how the feeds to the ethylIn addition to the cracking heater, the recovery section ene pyrolysis reactors are prepared from crude. Since the plays a vital role in the ethylene plant. Fortunately, after the molecular structure is altered through different processing hot section, the recovery section configuration is nearly indemethods, ethylene and the byproduct distributions will vary pendent of the feed. Since a naphtha plant is chosen as a for different cases. Therefore, illustrative overall material reference, relative factors can be used to prorate the capacity balances for producing 1,500 KTA ethylene at high severity of the plant. Figure 5 shows specific energy relative to the Cracker overall material balance summary 54 LUMMUS.indd 54 PTQ Q1 2024 www.digitalrefining.com 08/12/2023 16:32:39 Shaped Support GridTM Johnson Screens’ Shaped Support Grid (SSG) technology allows traditionally wasted vessel space to be fully utilized. Maximize your Vessel’s Performance The SSG will deliver: Increased cycle time and run time Maximum absorbent and catalyst volumes Improved fluid distribution Easy installation & retrofit SSG Configuration Tool With the SSG Configuration Tool you can determine exactly how much the Shaped Support Grid will improve your process. Scan or Click the QR code below Invention Powered by Tradition To learn more, visit us at Johnsonscreens.com J Screens.indd 1 08/12/2023 12:53:25 1.4 1.3 1.2 1.1 1 C2H4 plant only 1.2 1.1 0.9 1 0.8 0.9 C2H4 plant + feed preparation 0.7 0.6 0.5 0.8 0.7 0.6 Naphtha HCRK 1.3 C2H4 plant + feed preparation HCRK(TC2C) Heater effluent Gasoline fractionator Quench tower Charge gas Refrigeration compressor Figure 5 Comparison of specific energy to a naphtha cracker (HCRK = TC2C with hydrocracker) Figure 6 Relative capacity factors for major ethylene plant recovery section reference naphtha cracker. In addition, major capacity factors are shown in Figure 6 relative to the naphtha cracker. Capacity factor represents the quantity of feed with that quality relative to reference feed cracking. These are based on simplified mass transfer models and sometimes based on two-component distillation models. Most of the unit capacity can be accurately predicted within +/-2%; hence, it is a standard design tool for preliminary design. Most sections have less than 5% over the reference plant except the charge gas compression and quench section. Naphtha feeds have higher ultimate ethylene yields than crude. Generally, crude and in this case, Arab Light crude, has high residue, reducing the ultimate yield. However, as shown in Table 2, crude conditioning (hydroprocessing) has significantly improved the yields. The specific energy is one of the key performance parameters of the ethylene plant. It is defined as the energy required to produce per unit weight of ethylene after accounting for energy generated in the plant. Industry-standard energy equivalents are used for the import/export of steam, fuel, and electricity. Cooling water is another parameter. After accounting for all credits and debits, the energy to produce per unit of ethylene is calculated as specific energy. The lowest one is desirable. In the industry, pure ethane cracking has the lowest specific energy value (~3,000 kcal/kg C₂H₄). In this exercise, no additional schemes are considered; hence, direct comparison with the reference plant gives a good indication of energy consumption for crude to chemicals. In the traditional way, a refinery is used to produce feeds (naphtha and gasoil) for the olefin plant. The refinery contributes additional Capex and energy. Therefore, for a proper comparison, the additional Capex and energy must be included for the naphtha plant in principle to account for the upfront naphtha production. That is based on some in-house data in Figure 6. Although the ethylene plant shows higher specific energy than the naphtha plant, including the refinery to produce that naphtha, it clearly shows that TC2C is superior. When the specific energy is reduced, that also reduces the CO₂ emission. This clearly shows that a crude-to-chemicals configuration bypassing the refinery not only reduces Capex but also energy consumption. More than 10 patents have been granted and/or pending for different feed treatment/ethylene plant configurations and technologies covering crude to chemicals. Although only complete crude to chemicals is discussed here, partial transportation fuel production depending upon the local market can also be considered. Extensive bench-scale, pilot-scale, and demo-scale feed preparation units (1 bbl/day) were operated over three years, and all relevant data were collected and modelled. A digital twin of the flow scheme was also constructed. One plant is currently under construction, which is expected to start up in 2026. There are other projects under various stages of design. TC2C not only reduces Capex but also reduces energy consumption and CO₂ emissions. The material balance shown is only an example and will vary case-by-case basis to project specific objectives. 56 LUMMUS.indd 56 PTQ Q1 2024 Conclusion Ethylene is produced by thermally cracking hydrocarbons mixed with dilution steam in tubular reactors at high temperatures in a short residence time. During this process, coke (a solid) deposits in the reactor and, hence, the cracking coils must be cleaned periodically using steam/air. The coking tendency of heavy molecules such as gasoil and vacuum gasoils is high, and the relative ethylene yield from these feeds is typically low compared with gaseous and naphtha feeds. Traditional feeds such as naphtha and gasoil to the cracker are obtained from crude through distillation in a refinery. These are made to specifications to meet the fuel standards. In this transcript, crude is cracked to produce ethylene bypassing the refinery. In TC2C technology, all crude molecules ranging from naphtha to residue are processed to produce light olefins. Detailed analysis and understanding of the crude characterisation have resulted in better catalyst and reactor systems to upgrade the crude for olefin production. Coke precursors that shorten the heater run length are reduced significantly with better characterisation and experimental techniques of crude characterisation. In the scheme proposed, in addition to the standard C2 to C6-C8NA recycles, pyrolysis gasoil and fuel oil produced in the ethylene plant are sent to the TC2C crude conditioning section, where they are upgraded to meet ethylene plant feed requirements. By doing this, the amount of crude required to meet the design ethylene production is significantly reduced. Only a small purge is taken out as valuable IMO-compliant VLSFO. For Arab Light crude with hydroprocessing, total high-value chemicals are increased to >75%, much higher than that www.digitalrefining.com 08/12/2023 16:32:40 without hydroprocessing. Capex for the integrated ethylene plant and crude conditioning section is reduced along with the specific energy reduction. Relative to a 100% naphtha cracker, the specific energy of a crude cracking ethylene plant increases only slightly. When the energy required to produce the naphtha cut from crude in the refinery is included, the TC2C technology route demonstrates lower specific energy and, hence, will emit lower CO₂ for the complex. With hydroprocessing, the complete refinery is bypassed. Therefore, Capex and energy savings are higher than an integrated ethylene plant/refinery. Extensive bench-scale and pilot plant studies for various sections of TC2C technology were run to collect data for design. A plant using this scheme is under construction and is expected to start up in 2026. Although the scheme is shown with Arab Light crude, the technology is applicable to all types of crudes. Lighter crudes such as Permian or Agbami will reduce the Capex and improve crude utilisation. TC2C is a mark of Lummus Technology. Acknowledgement The authors thank the Lummus, Chevron, and Saudi Aramco colleagues who worked with us in this project. References 1 Altgelt K H, Boduszynski M M, Composition and Analysis of heavy Petroleum Fractions, Marcel Deckker, NY 1994. 2 Sundaram K M, Mukherjee U, Baldassari M, Thermodynamic Model of sediment deposition in the LC-FINING Process, Energy & Fuels, 22, 2008. p.3226-3236. 3 Boduszynski M M, Composition based crude oil evaluation, Haverly Systems Asian Technical Conference, Jun 2001. 73 EST. 1951 4 Fernandez-Baujin J M, Maddock M J, Sundaram K M, A case study based on commercial experience: Vacuum gasoils to Petrochemicals, presented at AIChE Spring meeting, Orlando, Fl, March 18-20, 1990. 5 Sundaram K M, Mukherjee U K, Venner R M, Santos P M, Thermal crude to chemicals, presented at AIChE spring meeting, Houston, March 13-16, 2023. 6 Biswas G, Maesen T, Sundaram K M, Unlocking Permian value, Hydrocarbon Eng., Apr 2022, p.29. Kandasamy M Sundaram is a Technologist responsible for pyrolysis reactors and other process reactor designs. He holds a Bachelor’s in chemical engineering from Madras University, a Master’s in chemical engineering from the Indian Institute of Science, and a PhD from the University of Ghent, Belgium. Email: [email protected] Ujjal Mukherjee is Chief Technology Officer responsible for Lummus’ existing portfolio and developing technologies at the forefront of the energy transition and digitalisation. He holds a Bachelor’s in chemical engineering from National Institute of Technology, India, a Master’s in chemical and petroleum engineering from ENSPM, France, and a Master’s in business administration from Rutgers University, US. Email: [email protected] Pedro Santos is Technology Director leading the commercial deployment and further technology development of TC2C. He holds a Bachelor’s in chemical engineering from the New Jersey Institute of technology, and he has been granted five patents related to crude to chemicals. Email: [email protected] Ronald Venner is Chief Business Officer, Clean Fuels, leading the strategic direction and performance of Lummus’ clean fuels and crude-to-chemicals businesses, as well as the company’s joint venture Chevron Lummus Global. He holds a Bachelor’s in chemistry and a Master’s in chemical engineering from Manhattan College. Email: [email protected] Learn From Industry Experts at the 74TH ANNUAL LAURANCE REID GAS CONDITIONING CONFERENCE Feb. 26-29, 2024 The Laurance Reid Gas Conditioning Conference is an opportunity for engineers and those new to the gas processing industry to gain valuable knowledge and build relationships with industry experts. Register online at pacs.ou.edu/lrgcc For questions, contact Lily Martinez at [email protected]. The University of Oklahoma is an equal opportunity institution. www.ou.edu/eoo. Printed at no cost to Oklahoma taxpayers. www.digitalrefining.com LUMMUS.indd 57 PTQ Q1 2024 57 08/12/2023 16:32:41 HIGHEST GAS PURITY AND LOW ENERGY CONSUMPTION Process Gas Compressor inside Diaphragm Compressor inside Burckhardt Compression offers a complete portfolio of compressor solutions for hydrogen fuel stations and power-to-x applications. Our oil-free diaphragm (900 bar) and piston compressors (550 bar) stand for the highest gas purity at high pressures with low energy consumption and reduced maintenance costs. In addition, Burckhardt Compression has a global network of local service centers that enables us to offer local support with a quick response rate. Learn more: burckhardtcompression.com/hydrogen Q2-Burkhardt Compression.indd 1 bc_ad_Hydrogen_303x216_en_220311.indd 1 04/04/2022 12:09:20 11.03.2022 08:45:56 Revolutionising refining with digital twins Exploring applications and outputs across the refinery landscape Michelle Wicmandy, Jagadesh Donepudi and Rodolfo Tellez-Schmill KBC (A Yokogawa Company) R efiners are at the crossroads of innovation and challenge. They are facing disruptions ranging from oil price volatility to the complexities of the global energy transition. Adding to this complexity, Offshore Technology claims India is expanding its pipeline network to more than 29,600 km by 2025. This significant expansion is roughly three-quarters of the Earth’s circumference. As the industry confronts these uncertainties, securing the integrity of this expanding pipeline infrastructure becomes crucial for meeting the nation’s growing energy demands while reducing risks and accidents that can harm people, profits, and property.1 Navigating new refining challenges To navigate these new challenges, the refining industry is revamping how it produces, uses, and manages energy.² Although existing assets have data acquisition capabilities, the hurdle lies in reviewing, cleaning, and assessing this data. This process is necessary to determine both current and future operating conditions, as well as meet safety and environmental regulations. In this journey, Indian refiners are in the process of implementing digital twins across various refinery process units for long-term sustainability.3 This initiative centres around creating digital twins for diverse applications, which provides real-time visualisation of key performance indicators (KPIs) and benchmark parameters. By using digital twins, refiners can improve the plant’s efficiency and productivity while reducing miscommunication, data waste, and labour costs. Essentially, digital twin technology is revolutionising the way refiners operate and paving the way to long-term profitability.4 Furthermore, it is evident that all aspects of an entire refining supply chain are highly interrelated and complex. Thus, integrating digital twins into the supply chain delivers added value, too, by optimising processes, energy consumption, and control applications such as real-time optimisation (RTO) and advanced process control (APC) systems. In the supply chain, these applications help bridge the gap between forecasting and actual operations.4 Validating these gaps, or delta vectors, uncovers the disparities between the planned and actual operations in terms of demand, inventory, and production. By validating these delta vectors, supply chain managers can quickly assess and address gaps in their models and processes to accommodate changes in inputs and outputs.1 www.digitalrefining.com KBC.indd 59 In regard to process optimisation, which is integrated with supply-side optimisation for power, steam, and utility balances, energy demand takes centre stage. The comparison between linear programming (LP), actual data, and simulation enables automated vector updates and model recalibrations via artificial intelligence (AI) and machine learning (ML) methods. The following discussions explore various applications, including KPI visualisation, production accounting, LP model updates, process optimisation, real-time optimisation, and corrosion monitoring. The digital twin architecture includes connecting process models through open platform communications unified architecture (OPC UA) with historians to ensure proper calibration. Digital twin technology Digital twins offer a solution to transform the oil and gas industry by improving efficiency and reducing risk. According to researchers,5 these virtual models of physical assets seamlessly connect with real-time data across assets, columns, reactors, pipinmg, and equipment. Despite changes in crude quality, catalyst composition, and process conditions, digital twins continuously analyse industrial data to predict and optimise processes.4 Their perpetual operation brings multiple benefits, such as asset monitoring in planning and scheduling studies, refinery-wide flow sheeting, real-time optimisation, and more. Furthermore, digital twins set benchmarks for both the quantity and quality of units. These benchmarks are then transmitted to the RTO/APC layer for optimisation on a global scale.6 This iterative process involves ongoing validation and adjustments to maximise benefits derived through the APC in a closed loop. The APC, armed with its dynamic process model, aims to stabilise operations and reduce fluctuations. It effectively implements the desired setpoint from the RTO to achieve closed-loop optimisation.5 The optimiser identifies the optimal operational state and communicates it to the APC. Implementing a digital twin starts with identifying possibilities and choosing a pilot configuration with the highest ROI. After implementation, the digital twin becomes an integral part of the enterprise’s digital backbone.4 The final step involves monitoring the value created and modifying the digital twin to maximise economic benefits. Refiners apply digital twins in various applications to PTQ Q1 2024 59 12/12/2023 10:29:35 P tro-SIM KBC Explorer Process Digital Twin KPIs, DQPs, MPIs Raw data Dashboard Data Archive Historian and LIMS Advanced Analytics $ P tro-SIM™ Monitoring service Process model LP Submodel KPI estimation ERP Figure 1 Digital twin architecture improve plant performance. These applications include visualising KPIs for performance tracking, reconciling data in production accounting, updating LP models in the supply chain, optimising processes to improve yield and energy, conducting real-time optimisation through quick gain calculations, and managing corrosion to monitor equipment and system degradation. These applications underscore the value of digitalisation in the refining process and are addressed in the remainder of this study. Digital twin architecture The digital twins are process models connected through OPCs with historians such as IP.21, Exa Quantum, OSI PI, or any other real-time data gateways, as shown in Figure 1. The models are calibrated using test data to ensure energy and mass balance accuracy. After calibrating the model, it is scheduled to run, and the results appear on dashboards. Other applications use these to generate advanced analytics.4 The success achieved from this system depends on whether the model is accurate and current. An outdated model limits the operation’s potential, resulting in value leakage, lost opportunities, and substantial financial costs. Visualisation: Enhancing KPI management Fuel gas LPG Naphtha Distillate 1 Distillate 2 Bottoms Production accounting: Single version of the truth The typical production accounting digital twin serves as the facility’s single version of the truth, laying the foundation for the hydrocarbon balance and loss control initiatives as shown in Figure 4. The system not only generates the hydrocarbon balance accurately, but it also detects losses. Product yield, WT% In the refinery, KPIs act as a compass, guiding performance tracking of key metrics such as temperature, pressure, equipment status, and more. Digital twins, adept at tracking and measuring KPIs, calculate intrinsic parameters such as yields, energy consumption, and column performance such as flooding, heat exchanger fouling, furnace efficiencies, coking tendencies, and emissions along with the benchmark parameters. Closing these gaps between the actual measurements and the benchmarks adds value.7 KPI management uses a strategic approach that aligns with the company’s goals to optimise plant and equipment performance. This approach ensures measurable progress. Derived from plant measurements, KPIs offer real-time insights into critical parameters such as unit throughput, feed, and product quality. Furthermore, calculations address yields and fractionation efficiency to identify process improvement opportunities. The intrinsic layer, estimated via a process digital twin, dives into issues such as column flooding, exchanger UA and fouling factors, and coking inside heater tubes. Using these intrinsic KPIs, operators can maximise asset utilisation and proactively improve the plant’s efficiency. Essentially, this system not only evaluates performance holistically but also provides insight to continuously improve individual assets or the entire complex.7 Figures 2 and 3 illustrate trends in product yields and intrinsic parameters, respectively. Figure 2 indicates the product yields vs timeline such as day/month. Figure 3 shows the intrinsic parameter limits and trends for jet flooding and downcomer backup, which are regularly calculated. Day /Month Figure 2 KPI product yield (wt%) trends 60 KBC.indd 60 PTQ Q1 2024 www.digitalrefining.com 12/12/2023 10:29:37 It provides a systematic approach to reconciling data input errors. Reconciliation entails distributing mass imbalance errors across streams, adjusting specific streams to achieve a close mass balance, and using site-wide tools to seamlessly close the balance across assets.5 Additionally, the process digital twin enhances operational efficiency through various capabilities. First, it ensures a precise elemental balance apart from mass considerations, providing a comprehensive understanding of the hydrocarbon processes. Moreover, it contains details about plant and tank farm operations, offering insights into movements critical for effective management. As a result, the digital twin helps uncover gross errors early in the business process, ranging from data entry errors and instrument failures to missing movements. With automatic logic, it uses coke production and adapts to flow variance, ensuring uninterrupted production even during outages. Supply chain – LP model updates for robust planning In refinery and petrochemical complexes, LP models play a vital role in assessing crude selection, yields, and gross margin via optimisation functions. Despite their utility, these linear models often face challenges due to infrequent updates in sensitivities related to feed, severity, and product qualities. This discrepancy between model predictions and actual performance, particularly at the end of back casting, can negatively impact operational efficiency.4 Traditional LP models used for planning, scheduling, and optimising assets lack continuous validation. This deficiency, often performed by individuals, creates inaccuracies that contribute to suboptimal operations. To overcome these challenges, the digital twin continuously tracks asset performance. Thus, all stakeholders get a comprehensive view of asset performance, including optimum operating targets, enhanced scheduling, and inventory cost savings. Additionally, digital twins not only automate complex work processes such as kinetic model calibration and validation but also leverage AI and ML methods to automate workflows, check the application’s health, validate AI recalibration recommendations, and validate the accuracy of the vectors. As shown in Figure 5, the automated model maintenance tool determines when the model needs to be recalibrated and establishes protocols for validating the model. The result Max. Jet flooding 50 74.4% 50 40 90 100 30 Figure 3 Intrinsic parameters monitoring is ongoing health score tracking, data quality analysis, and actionable email alerts. Process optimisation: Bridging gaps and identifying opportunities Process optimisation can be achieved using a digital twin to identify gaps between actual and benchmark performance during plant operation or the design stage. The gaps are analysed for corrective actions such as changing operating parameters or modifying equipment, piping, or instrumentation. Digital twin applications for process optimisation include: • What-if analysis, debottlenecking, and optimisation • Constraint management • Molecular management • Unit/equipment optimisation • Product blending and stream routings • Identify margin improvement opportunities • Screen opportunities • Continuously track benefits for each implemented opportunity. Based on the authors’ experiences, the digital twin of an integrated refinery and petrochemical complex with a multifeed steam cracker complex helped identify operational improvement opportunities exceeding 100 million USD and Capex savings tipping 100 million USD during the design review of its configuration. Real-time optimisation: Dynamic control for operational excellence In traditional distributed control systems (DCS), the process parameter from specified boundaries is common. In APC, Mass Balance Raw mass imbalance using outage 1.25 0 1.3 -2 1.35 1.3 1.4 1.45 1.05 1 80 46.8% 90 100 40 CCR-Coke Ratio 1.15 1.1 70 60 80 60 Key Ratio 1.2 Max. Downcomer backup 70 1.5 Max. Reconciled in mass flow 2 4 4 -4 -2.4 WT% -6 -8 -10 10 6 7 3 6 8 5 5.2 WT% 2 1 8 9 0 10 Figure 4 Key performance indicators www.digitalrefining.com KBC.indd 61 PTQ Q1 2024 61 12/12/2023 10:29:39 Optimise NH3 injection flow rates Optimise wash water rates Generate integrity operating envelopes Estimate corrosion rates. Real time optimisation Planning & scheduling Enhanced unit monitoring Decarbonisation studies New Data Set Alert AMM Simulation / LP health scores Actionable alerts Best calibration case Calibration & tuning factors Corrosion monitoring: Guarding infrastructure integrity Digital Twin AMM Proposed Calibrated & Tuned model Figure 5 Automated model maintenance the process is maintained at desired operating conditions by reviewing process constraints, reducing process variability. During actual plant operations, equipment availability, economic conditions, and process disturbances result in changes in optimum conditions, as shown in Figure 6. Hence, the optimum operating conditions need to be re-calculated in real time. The RTO of set points requires two models: the economic model and the operating model. The economic model functions to minimise costs while maximising product values, and the operating model is a steady-state process model to identify the operating limits for the process variable. Case study: Showcasing digital twin applications This case study minimises corrosion for a refinery overhead system. As part of their digitalisation journey to improve asset reliability, this client sought a centralised corrosion monitoring system. To address corrosion issues in the crude distillation units’ (CDU) overhead system, KBC (A Yokogawa Company) deployed a corrosion digital twin. The following objectives were set to guide the deployment of a digital twin to monitor corrosion in the refinery’s CDU overhead section and optimise operations: Online prediction and monitoring of corrosion indicator parameters. a. Ionic dew point temperature and pH b. Salting point temperature c. Aqueous phase condensation temperature and pH Traditional: DCS only Control with fluctuation Corrosion in CDU overheads caused unplanned and costly unit outages.8 Eliminating or minimising corrosion in the overhead system of CDUs was challenging, as it could lead to pipe leaks. This corrosion stemmed from aqueous corrosion attributed to hydrogen chloride forming from hydrolysis of inorganic chlorides in crude preheat and furnace processes. Factors such as ammonium and/or hydrochloride salts that absorb moisture often cause corrosion above the dew point. Mitigation strategies involved optimising the injection of chemical agents or dew point control in the overhead system. This complexity made the overhead system one of the most vulnerable parts of each distillation unit. As shown in Figure 7, the corrosion digital twin provided a comprehensive solution that consolidated processes as well as chemical and corrosion data to streamline monitoring from a single location. The corrosion control delivered the following benefits: Minimised corrosive conditions Prevented excessive corrosion, thereby extending the service life of the pipe and process equipment Reduced and prevented unpredictable shutdowns or accidents Cut maintenance costs. The corrosion digital twin achieved these outcomes by tracking the following parameters: • Ionic dew point temperature • Salting point temperature • Aqueous phase condensation temperature and pH • Neutralising ammonia injection rate • Boot water pH • Wash water injection rate. An electrolyte-based fluid package with the proprietary OLI and Petro-SIM digital twin of the CDU overhead was developed to demonstrate the capabilities of a corrosionmonitoring digital solution. It provided key information to confirm corrosion mechanisms, rates, and comprehensive operational guidelines. Modern: APC + DCS Minimise fluctuation New standard: RTO + APC+ DCS Minimise fluctuation + maximise profit Optimal setpoint Manual setpoint Process data (ex. Product properties) Figure 6 Control systems 62 KBC.indd 62 PTQ Q1 2024 www.digitalrefining.com 12/12/2023 10:29:41 To use the model for troubleshooting Modelling, troubleshooting, case studies Data historian, lab analysis, corrosion data Petro-SIM + OLI engine Stream properties KPI (in Petro-SIM) Corrosion rate, metallurgy OLI application Corrosion analysis pH, Cl conc, solid, generalised corrosion rate*, velocity etc. To identify deviation based on low and high value *Only when operating below ionic dew point Figure 7 Corrosion digital twin Conclusion Standing at the crossroads of innovation and challenge, refiners face the complexities of the refinery and petrochemical industry. At this moment, KPIs emerge as valuable tools that monitor critical metrics such as temperature, pressure, and equipment status. These metrics not only provide insights but also serve as catalysts for innovation, helping refiners navigate the intricacies of yields, energy variances, column performances, and more. Refineries and petrochemical plants are increasingly adopting digital technologies. One such tool, the digital twin, has proven to be a multi-faceted solution for both operational and design stages based on our experience. In this article, we present a case study of a refinery that benefited from digital twin applications, including: • KPI visualisation incorporates intrinsic parameters like flooding and heat exchanger fouling characteristics • Production accounting systems leverage mass balances and elemental balances to identify and address real losses within the production process • Supply chain planning systems update LP vectors to represent non-linear sensitivities for more robust supply chain planning • Production optimisation closes gaps based on benchmarking parameters to improve gross margins • Real-time optimisation continuously calculates gains by optimising set points in real time • Corrosion monitoring minimises corrosion rates and implements corrective actions to prevent pipe corrosion, ensuring the longevity and reliability of the infrastructure. These applications emphasise the wide-ranging benefits that a process digital twin simulation software offers refiners, demonstrating its potential to revolutionise various aspects of plant operations and design. This point of convergence should not be seen as a period of uncertainty. Rather, it represents a strategic juncture where the industry holistically assesses its overall performance and implements strategies for continuous improvement. It serves as a roadmap that motivates the industry to drive toward a sustained state of excellence. References 1 Priyanka E B, Thangavel S, Gao X-S, Sivakumar N S, Digital twin for oil pipeline risk estimation using prognostic and machine learning www.digitalrefining.com KBC.indd 63 techniques, Journal of Industrial Information Integration, 26, 2022, pp.100,272. https://doi.org/10.1016/j.jii.2021.100272. 2 Yadav V G, Yadav G D, Patankar S C, The production of fuels and chemicals in the new world: critical analysis of the choice between crude oil and biomass vis-à-vis sustainability and the environment, Clean Technologies and Environmental Policy, 22(9), (2020), pp.1757-1774. https://doi.org/10.1007/s10098-020-01945-5. 3 Alsayoof L, Shams M, The role of crude oil selection in enhancing the profitability of a local refinery with lube hydro-processing capacity, Chemical Engineering Research and Design, 185, 2022, pp.146-162. https://doi.org/10.1016/j.cherd.2022.07.002. 4 Wanasinghe T R, Wroblewski L, Petersen B K, Gosine R G, James L A, De Silva O, Mann G K I, Warrian P J, Digital Twin for the Oil and Gas Industry: Overview, Research Trends, Opportunities, and Challenges, IEEE Access, 8, 2020, pp.104,175–104,197. https://doi.org/10.1109/ access.2020.2998723. 5 Min Q, Lu Y, Liu S, Su C, Wang B, Machine learning based digital twin framework for production optimisation in petrochemical Industry, International Journal of Information Management, 49, 2019, 502–519. https://doi.org/10.1016/j.ijinfomgt.2019.05.020. 6 Singh A, Be in Control of Your Operation – Integrating Real-Time Optimisation with Advanced Process Control for Optimum Energy Management and Optimisation. OnePetro, 2022. 7 Sarantinoudis N, Tsinarakis G, Dedousis P, Arampatsis G, ModelBased Simulation Framework for Digital Twins in the Process Industry. IEEE Access, 11, 2023, pp.111,701-111,714. https://doi.org/10.1109/ access.2023.3322926. 8 Schempp P, Kohler S, Mensebach M, Preuss K, Troger M, Proceedings of the European Corrosion Congress, Prague, Czech Republic, Paper No. 88826 (EFC Working Party 15: Corrosion in the Refinery Industry), 2017. Michelle Wicmandy is the Marketing Campaigns Manager at KBC (A Yokogawa Company) in Houston, Texas, with more than 20 years of experience in marketing and communications. She serves on the Forbes Communication Council and has contributed to both academic and trade publications. She holds a DBA in business administration. Jagadesh Donepudi is the Director for Business Development South Asia at KBC (A Yokogawa Company) in India. He has more than 30 years of experience adding value to refineries and upstream oil and gas companies via digitalisation, digital twins, and energy transitions. He holds a PhD in chemical engineering from the University of Mumbai. Rodolfo Tellez-Schmill is the Product Champion for Process Simulation at KBC (A Yokogawa Company) in Canada. He has more than 20 years of experience in chemical engineering, including process engineering, quality control, project management, R&D, technical support, and training He holds a PhD in chemical engineering from the University of Calgary. PTQ Q1 2024 63 12/12/2023 10:29:42 Find out more at arielcorp.com/applications PTQ Q4 Ariel.indd 1 08/09/2023 10:46:38 Optimising nitrogen utilisation in refinery operations Technical aspects and insights on managing nitrogen by considering actual operational scenarios Rajib Talukder and Prabhas K Mandal Aramco N itrogen gas, known for being chemically inert, non-flammable, colourless, odourless, and slightly lighter than air at atmospheric temperatures, has been extensively used in the chemical and process industry for many years. The oxygen content in empty vessels, equipment, and pipeline spaces is reduced by it to facilitate start-ups, or hydrocarbons are driven out by it on shutdowns. Due to its non-reactive nature and low solubility in liquids, it is commonly chosen as a blanketing gas, thereby virtually eliminating any risk of product contamination. In refineries, most of the nitrogen is consumed in gaseous form. Liquid nitrogen is stored and then vapourised into gaseous nitrogen as needed. The base nitrogen demand load for a refinery during normal operation is met by gaseous nitrogen, a demand that is an order of magnitude smaller than the peak load observed during plant shutdowns. The peak load demand is met by liquid nitrogen. This article does not address the methods by which the overall base or peak nitrogen demands of a refinery are determined. Instead, attention is given to several major contributors to the base or peak load where significant optimisation opportunities are believed to exist due to a high degree of conservatism associated with these contributors. In the following sections, major contributors, such as the nitrogen required for tank blanketing, surge drum blanketing, and starting up hydroprocessing units, are addressed. Nitrogen blanketing is utilised in vessels/tanks containing liquids, such as a surge drum or tanks, for the following reasons: • Safety: The use of nitrogen lessens the chance of oxygen penetration, thereby disrupting the formation of the fire triangle (fuel, heat, oxygen). This is especially relevant for vessels containing flammable liquid hydrocarbons. • Protection against oxidation: Preventing oxygen from entering hinders the oxidation process, which could otherwise harm the quality of the liquid inside the vessel. This is particularly important for lean amine and wash water surge drums. • Prevention of vapour loss: A nitrogen barrier restricts the amount of hydrocarbon vapour that can leave the vessel. Estimation of nitrogen blanketing for surge drums By maintaining an inert atmosphere over the stored liquid, nitrogen blanketing ensures quality, regulates pressure, and prevents incidents. www.digitalrefining.com ARAMCO.indd 65 To correctly estimate the flow rate of the blanket gas, it is important to keep the pressure inside the vessel within safe and operational limits. Here is a basic guide on how to measure the blanket gas flow rate: • Assess volume changes due to liquid outflow: The initial step involves identifying the maximum liquid volume that will exit the vessel over a certain period. This shift in volume results in a change in pressure inside the vessel, necessitating compensation via the blanket gas to maintain positive pressure. The Ideal Gas Law is used to convert the change in liquid volume into the needed gas volume. • Consider pressure changes due to liquid contraction: The impact of major pressure changes in the vessel resulting from variations in incoming feed temperature is also accounted for, such as the volume contraction caused by the entry of cold feed when the supply of hot feed is interrupted. When calculating the total need for blanketing gas for any surge drum, thermal inbreathing is generally not considered along with normal inbreathing resulting from liquid movement from the vessels, unlike in the case of tanks. This is primarily because the empty vapour space in a surge drum is much smaller than in tanks, and the likelihood of a coinciding loss of liquid inflow and contraction of the vessel’s vapour due to sudden ambient cooling from rain is extremely low. However, it is essential to note that nitrogen blanketing of vessels is not designed to address certain circumstances: • Using blanket gas as a safeguard for the vessel design for full vacuum: A total feed failure to the surge drum during the vessel’s emptying process is considered a severe situation. In such cases, according to API 521 standards, blanket gas cannot be used as a safety measure since control action credits (for instance, the blanket gas control valve) are not acknowledged as safety precautions. The vessel should be either constructed for full vacuum to ensure its safety or equipped with a safety instrumentation system to avert a vacuum under these emergency circumstances. • Supporting NPSHa for the pump connected to the surge drum: While estimating NPSHa, the blanket gas’s solubility in the liquids being pumped is considered, and the vapour pressure is presumed to be higher than the actual vapour pressure, equal to the surge drum’s normal operating PTQ Q1 2024 65 08/12/2023 17:06:45 requirements for the process units, subsequently driving up the total nitrogen demand for the facility. Moreover, it could Project Project A Project B result in an overly conservative sizing of Equipment name Lean amine surge drum Lean amine drum the nitrogen blanketing valve, which might Vessel pressure (bara) 3 2 introduce control challenges when the Vessel temperature (°C) 70 60 Vessel head type 2:1 Semi-ellipsoidal 2:1 Semi-ellipsoidal valve output is minimal, possibly triggering Vessel ID (mm) 3,000 2,500 unnecessary nitrogen wastage. Refiners Vessel T-T (mm) 10,000 9,000 are adding gap control for the blanketing Out flow (m³/h) 180 85 control valves, as described later in detail, Normal liquid level- NLL (mm) 7,000 6,000 and this practice results in near zero openLo Lo liquid level- LALL (mm) 750 500 ing of the nitrogen blanket control valve Nitrogen blanket gas flow (Nm³/h) during normal plant operation. 1. Method 1 358 139 2. Method 2 63 51 Observations from actual plant data 3. Design value 360 50 reveal a consistent level during normal operations. During emergency situations Table 1 when the inflow to the surge drum is diminished or completely lost, operator actions pressure. This is done to account for slight degassing in the ensure the feed surge drum level is maintained, preventing liquid and to prevent pump cavitation. the connected pump from being tripped due to the activation of the low liquid level trip. The surge drum’s hold-up Calculation of volume changes due to liquid outflow time is generally set between 10-15 minutes, providing The volume changes due to liquid outflow can be estimated ample time for operator intervention. using two different methods: Considering the ample time available for operator inter• Method 1: The flow of nitrogen blanketing is calculated vention and the lack of benefits from designing the nitrogen to maintain the normal operating pressure in the surge blanket flow with high conservativism using Method 1, it is drum when the outflow from the drum is continuous, but more pragmatic to adopt Method 2 for estimating the nitrothe inflow to the drum ceases. This estimation uses the API gen blanket gas flow. 2000 liquid outflow method. Licensor does not normally Pressure changes due to liquid contraction include thermal inbreathing. • Method 2: The nitrogen blanketing flow is calculated Volumetric contraction in the surge drum can happen due to maintain the vessel at a slightly positive pressure (1.1 to the replacement of hot feed with cold feed, especially for bara) when the outflow from the drum is continuous, but hot hydrocarbon feed. Reduction of pressure can be estimated as follows: the inflow to the drum fails. This is calculated based on the vapour volume change due to the decrease from the normal liquid level to the very low liquid level at which the con- Liquid volume change (dV) = VNLL x (1- ϱhot/ϱcold) nected pump is stopped. Vapour volume above NLL (Vvapour) = VTotal - VNLL The operation of the surge drum is different from that of tanks. While tanks are either in receiving or dispatch mode, Pfinal = Pnormal x [Vvapour/( Vvapour + dV)] surge drums are always in both receiving and dispatch mode. They are frequently positioned between process units to help Where: = Normal liquid level volume (m³) mitigate the impact of flow rate variations between intercon- VNLL = Vessel total volume (m³) nected process units. Unlike the typical control objective of VTotal = Hot liquid density (kg/m³) maintaining a measurement at a set point, the goal of surge ϱhot = Cold liquid density (kg/m³) drum level control is to buffer the changes in controlled flow ϱcold = Final vessel pressure (bara) while keeping the liquid level in the vessel within limits. For Pfinal surge drums, it is usually more important to allow levels to Pnormal = Vessel normal pressure (bara) = Density (Rho) ‘float’ to minimise flow rate variations. Therefore, the level r controller must permit this movement and try not to hold the level close to its set point. Instead, the controller should keep Example calculation: the surge vessel’s level between its upper and lower limits This example calculation is performed for a diesel hydrotreater feed surge drum (FSD) when hot feed is replaced with the least possible change to its flow output. The estimation of nitrogen blanketing for the lean amine with cold feed during hot feed failure. Assuming the FSD surge drum of two different licensors' diesel hydrotreater will continue to maintain a normal liquid level after replaceunits using both methods is presented in the Table 1. The ment, cold feed with a higher density will have a lower liquid head. The reduction of the liquid head will result in a calculation details can be found in Appendix 1. Employing Method 1 to determine the nitrogen blanket reduction in liquid volume at a normal liquid level, and this for the surge drum may lead to a high degree of conserv- volume reduction is estimated considering liquid volumetric ativism. This strategy could increase the normal nitrogen contraction. Required blanketing nitrogen gas 66 ARAMCO.indd 66 PTQ Q1 2024 www.digitalrefining.com 08/12/2023 17:06:46 We understand how you need to reduce complexities at your plant. CLEAN PROCESS + CLEAR PROGRESS You strengthen your plant’s safety, productivity and availability with innovations and resources. Endress+Hauser helps you to improve your processes: • With the largest portfolio of safety instruments that comply with international regulations • With applied technologies and people who have extensive industry application know-how • With access to accurate and traceable information Do you want to learn more? www.endress.com/oil-gas endress.indd 1 08/12/2023 12:50:41 The hot feed, initially at 125°C, is preheated to 218°C before entering the FSD. In situations where there is a failure in the hot feed supply, a cold feed is used as a replacement. This cold feed, starting at 40°C, is then preheated to 155°C before being introduced to the FSD. It is assumed that the FSD has a similar dimension to the lean amine surge drum of Project A above and the FSD is operating at the same pressure of 2.5 bara. From this, the following is calculated: VTotal VNLL ϱ hot ϱ cold Pnormal Pfinal = 78 m³ = 53 m³. = 700 kg/m³ = 751 kg/m³ = 2.5 bara = To estimate (bara) In the case of determining the nitrogen blanketing flow rate for tanks, the API 2000 method serves as a standardised procedure. Estimation of inbreathing due to liquid transfer effect According to Section 3.3.2.2.2 ‘Inbreathing’ of API 2000, the estimation of inbreathing, resulting from the maximum outflow of liquid from a tank, necessitates consideration of the rate of volume change of tank vapour space due to liquid movement. The requirement for inbreathing, denoted by VinL and measured in normal cubic meters per hour of air, should equal the maximum liquid discharging capacity for the tank, denoted by Vliq and measured in cubic meters per hour. This correlation is presented in Equation 1. Here, Vliq signifies the rated capacity of the pump connected to the tank: Liquid volume change (dV) = 53 X (1- 700/751) = 3.6 m³ VinL = Vliq Vapour volume above NLL (Vvapour) = 78 – 53 = 25 m³ Estimation of inbreathing due to thermal effect Pfinal = 2.5 X (25/(25+3.6) = 2.2 bara From the above calculation, it is evident that the pressure reduction due to liquid volumetric contraction when replacing hot feed with cold feed is relatively minor. Determination of nitrogen requirement for tank blanketing Inert gas systems, like those using nitrogen, help prevent air from entering a tank when there is a chance of vacuum generation inside it. These systems make tanks safer by reducing the chance of creating explosive atmospheres and minimising the risk of dangerous flashbacks. However, it is important to note that this nitrogen blanketing system should not replace vacuum relief devices. Despite having an inert gas system in place, the vacuum relief devices need to be large enough to handle situations where the inert gas might not be available. Vacuum conditions in a tank can occur due to two main causes: Liquid transfer effect: This phenomenon occurs when there is an outflow of liquid from the tank without a corresponding inflow, creating a vacuum. Thermal effect: Changes in atmospheric conditions, such as a drop in temperature or shifts in weather patterns (like wind changes or precipitation), can lead to the contraction or condensation of vapours, consequently resulting in a vacuum. Eq. 1 The API-2000 standard, specifically Section 3.3.2.3.3 ‘Thermal Inbreathing,’ provides guidelines for calculating inbreathing attributed to thermal effects. As per this section, the thermal inbreathing of the tank, measured in normal cubic meters per hour of air, is calculated in line with Equation 2: VinT = C X Vtk0.7 X Ri Eq. 2 Where: VinT is inbreathing flow rate (Nm³/h) C is a factor that depends on vapour pressure, average storage temperature, and latitude (ref API 2000 Table 2) Vtk, which represents the tank’s vapour volume, is expressed in cubic meters. For vertical cylindrical tanks, it is acceptable to calculate this volume based on the tank shell height, not including the tank roof. The term Ri refers to the reduction factor for insulation. In situations where no insulation is used, such as this, Ri is assigned a value of 1. When establishing inbreathing requirements, the design basis must account for the most significant single contingency or any plausible combination of contingencies. To ensure comprehensive coverage, the total normal inbreathing of the tank should, at a minimum, consider the combined effects of liquid transfer and thermal conditions during normal operations. As a result, the normal inbreathing C factors Latitude C factor for various conditions Vapour pressure similar to hexane Vapour pressure higher than hexane, or unknown Average storage temperature, ºC <25 ≥ 25 <25 ≥ 25 Below 42° 4 6.5 6.5 6.5 Between 42° and 58° 3 5 5 5 Above 58° 2.5 4 4 4 Table 2 68 ARAMCO.indd 68 PTQ Q1 2024 www.digitalrefining.com 12/12/2023 15:47:06 www.zwick-armaturen.de zwick.indd 1 08/12/2023 12:57:49 requirement for the tank is derived by summing the values from Equations 1 and 2, capturing both the liquid transfer and thermal influences on the inbreathing system. pragmatic approach, a more realistic estimation of nitrogen demand for tank inbreathing can be achieved, potentially reducing the overall nitrogen consumption significantly. Frequently, when estimating the total nitrogen inbreathAlternate method for estimating nitrogen ing requirement for a tank farm, a common practice is to inbreathing quantity add the inbreathing due to liquid movement to the thermal According to API 2000 section 3.5.3, when an inert gas inbreathing for all tanks. However, it is important to note system is employed to prevent the entry of air into the that, for a specific service, typically only one tank operates tank during vacuum conditions, thereby reducing the risk in despatch mode, driven by the connected pump. This genof a potentially explosive atmosphere inside the tank, the eral addition of inbreathing due to liquid movement leads Annex F method can be utilised to estimate inert gas blan- to a significant increase in the normal nitrogen inbreathing keting for tanks. requirement for the entire tank farm. As a result, a more In the context of refineries, tank vents are typically with- accurate and pragmatic approach is needed to optimise out any flame arrester, and thus, the sizing of venting nitrogen usage and better reflect the actual operational devices is determined using Annex F Level 3 equation, as conditions of the tanks. shown below: Various interpretations and methodologies have been observed when estimating nitrogen inbreathing for a tank 0.7 VI = 0.5C • RiVtk + Vpe farm. To facilitate a comparative analysis of inbreathing flow rates using different methods, nitrogen blanketing for VI = 0.12 • Vtk a selection of representative tanks with representative outflow has been estimated using the following approaches: Where: • Method 1: Liquid transfer effect according to API 2000 C is a factor that depends on vapour pressure, average section 3.3.2.2.2 + thermal inbreathing as per section storage temperature, and latitude (see Table 2) 3.3.2.3.3. In this approach, all tanks are assumed to be Ri is the reduction factor for insulation empty, and the outflow of liquid occurs from all tanks when Ri is 1 if no insulation is used there is no inflow to any of the tanks. Vtk is the tank volume • Method 2: Liquid transfer effect based on API 2000 secVpe is the maximum rate of liquid discharge tion 3.3.2.2.2 + thermal Inbreathing per section 3.3.2.3.3. Here, all tanks are assumed to be 50% empty, and the In both the methods above, the calculation of tank outflow of liquid occurs only from one tank for a specific thermal inbreathing requirement adopts a conservative service, with no inflow to that tank. approach, assuming that tanks are empty and filled with air • Method 3: Inbreathing as per Annex F of API 2000. In this before cooldown. However, it is believed that a more prag- method, all tanks are assumed to be 50% empty, and the matic approach can be adopted, leading to a reduction in outflow of liquid occurs only from one tank for a particular the normal nitrogen demand of the tank farm, which often type of liquid, with no inflow to that tank. accounts for more than 20% of the overall refinery’s normal For detailed calculations, refer to Appendix 2, and a sumnitrogen demand. marised result of various methods is shown in Table 3. In practice, storage tanks are typically not operated comTable 3 shows that the nitrogen inbreathing requirement pletely empty. They usually maintain some minimum inven- estimated using Method 1 is 1.7 times more than that estitory levels. For product tanks in a specific service, one tank mated using Method 2 and 3.3 times more than that estimay be in receiving mode, another under certification, and mated using Method 3. Additionally, Method 2 provides an another in despatch mode. Intermediate tanks are com- estimated nitrogen requirement 1.9 times higher than that monly kept at around 50% level, while feed tanks are tar- estimated using Method 3. These comparisons highlight geted to be kept full of inventory. the significant differences in nitrogen inbreathing estimaIt is pragmatic to consider a 50% level of inventory in the tions based on the different methods used. tanks while estimating the nitrogen requirement for tank The thermal inbreathing requirements given by API 2000 inbreathing. This approach finds support in Annex F of API are approximately equivalent to a rate of change in ambient 2000, which states that: “If several tanks with a common temperature of 38°C per hour. While this may seem excesinert gas supply are divided so that no single tank has a sive, it reflects a change of about 10°C in 15 minutes, which capacity exceeding 20% of the total capacity of all tanks, the is not uncommon as storm fronts move through. It also concalculated values may be reduced by 50%.” By applying this siders the impact of sudden cold rainfall on the shell of the tanks. Normal nitrogen inbreathing rate It is essential to consider that the change in volume is comMethod Liquid transfer (Nm³/h) Thermal inbreathing (Nm³/h) Total (Nm³/h) monly converted into equivalent Method 1 31,082 283,551 314,633 volumetric rates based on air Method 2 9,296 174,546 183,842 at standard or normal condiMethod 3 9,296 87,273 96,569 tions. Consequently, the voluTable 3 metric rates may not appear as 70 ARAMCO.indd 70 PTQ Q1 2024 www.digitalrefining.com 08/12/2023 17:06:47 Technical nuances and best practices in refinery units Gaseous nitrogen for purging One of the most frequent uses of nitrogen is to purge equipment of explosive or hazardous vapours before lining up the vessel after maintenance or handing it over for maintenance. This is usually done using a pressure/de-pressure cycle. The cycles needed to ensure the oxygen concentration is below the Lower Explosive Limit (LEL) can be determined through the equation: n = log[(Ci-Cn)/(Cf-Cn)]/log (Pf/Pi) Eq. 3 Where: Cn = mol% oxygen in nitrogen Ci = mol% oxygen initially in space to be purged Cf = mol% oxygen finally in space to be purged Pi = Initial pressure in bara Pf = Final pressure in bara n = Number of pressure/de-pressure cycles For oxygen removal from equipment, a method involving multiple pressurisation and depressurisation cycles is employed by refiners. The equipment is first pressurised to the maximum nitrogen header pressure. It is then depressurised from several points until a slight positive pressure of approximately 0.5 barg is reached. This process of pressurising and depressurising is repeated until an oxygen concentration below 4 mol% is achieved. For some cases, like reformer or hydrotreater, target oxygen is less than 0.5 vol%. Once this level has been reached, the equipment is pressurised to its normal operating pressure using nitrogen, ensuring it is prepared for hydrocarbon introduction. The method of pressurising equipment to the maximum nitrogen header pressure is associated with the following drawbacks: www.digitalrefining.com ARAMCO.indd 71 100 % of nitrogen flow equivalent displacement, especially when the assumed operating or ambient temperatures do not align with standard or normal conditions. The calculated inbreathing considers the assumption of ambient airflow through the tank vent, where it is customary to consider the ambient air to be at normal or standard conditions. In cases where a medium other than air is utilised for vacuum relief, it might be necessary to convert the rate to an air-equivalent flow. Adjustments may be required for inbreathing if the inbreathing medium significantly differs from air. However, no adjustments are necessary for nitrogen, as the molecular weight of nitrogen (28.02) and air (28.96) exhibits only a marginal difference (3.3% variation in molecular weight). In conclusion, facilities should assess the nitrogen inbreathing requirement for tanks using the appropriate method as described earlier. By doing so, they can potentially achieve significant reductions in overall nitrogen requirement, leading to substantial savings in Capex and Opex while ensuring safety and tank integrity are not compromised. This prudent approach allows for efficient resource allocation while maintaining the highest standards of operational safety. 100% 98% 94% 87% 80 78% 66% 60 47% 33% 40 20 0 2 3 4 5 7 6 8 9 Vessel pressure (bara) Figure 1 Reduction of nitrogen flow rate vs vessel pressure a) Flow reduction: As equipment is pressurised, a notable decrease in the nitrogen flow rate is observed, particularly when vessel pressure exceeds half of the header pressures. This phenomenon can be seen in Figure 1, which highlights the decline in flow rate under various pressures where the nitrogen header pressure is at 9 bara. b) Excessive consumption: To estimate the nitrogen volume needed to achieve an oxygen content below 4 mol%, a comparative estimation is carried out for three different scenarios. In each scenario, the first cycle of nitrogen pressurisation of the vessel, which is full of air, is considered. The vessel is pressurised from atmospheric pressure to different pressurisation scenarios. Here are three scenarios illustrating the differences: Scenario 1: Pressurised to 9 bara Scenario 2: Pressurised to 5 bara Scenario 3: Pressurised to 3 bara Upon reaching the targeted pressure, if the oxygen content is below 4 mol%, the vessel is depressurised to its normal operating pressure of 3 bara, making it ready for hydrocarbon introduction. Otherwise, it is brought down to 1.5 bara and then pressurised to start the next cycle of pressurisation/depressurisation. This cycle continues until the oxygen content meets the desired threshold, after which the vessel is pressurised to 3 bara using nitrogen. The results are shown in Table 4. In Table 4, it can be observed that for Scenario 1, the required nitrogen volume is the highest, being 1.5 times that of Scenario 2 and two times that of Scenario 3, even though only one cycle of pressurisation with nitrogen is required in Scenario 1. Key takeaway: Limiting pressurisation to half of the nitrogen header pressure is both cost-effective and efficient, as supported by the provided scenarios. Start-up nitrogen for hydroprocessing units’ high-pressure (HP) section The start-up of hydroprocessing units demands a substantial amount of nitrogen, primarily for leak tests and inertisation. For a typical 1,000 m3 volume hydroprocessing high-pressure loop, three cycles of pressurisations and depressurisations between 1.5 barg and 5 barg are essential. The goal is to reach O2<0.5 mol%, necessitating approximately 14,000 Nm3 of nitrogen. PTQ Q1 2024 71 08/12/2023 17:06:48 Comparison table – pressurising to different levels Cn = mol% oxygen in nitrogen Ci = mol% oxygen initially in space to be purged Cf = mol% oxygen finally in space to be purged Pi = Initial pressure in bara Pf = Final pressure in bara n = Number of pressure/de-pressure cycles Required nitrogen volume(Nm3) [vessel volume -V ] Total nitrogen volume for scenario (Nm³) Scenario 1 Scenario 2 Scenario 3 1st Cycle 1st Cycle 2nd Cycle 1st Cycle 2nd Cycle 0.10 0.10 0.10 0.10 0.10 21.00 21.00 4.28 21.00 7.07 2.42 4.28 2.19 7.07 3.58 1.00 1.00 1.50 1.00 1.50 9.00 5.00 3.001 3.00 3.0 1 1 1 1 1 8V 4 V 2V 2 V 2V 8 V 6V 4V Note 1: Pressurisation is limited to 3 bara as oxygen content was below the target value of 4 vol%. Table 4 Typically, hydroprocessing units undergo leak testing at varying pressure levels using nitrogen. For the context of this article, 20 barg is assumed as the maximum leak test nitrogen pressure. Upon successful completion of this test, a nitrogen circulation at 20 barg is established. The process involves an initial cycle for detecting and rectifying leakages. Then, a second cycle is used to stabilise the nitrogen circulation. Under conditions where the HP loop is successfully tested at 5 barg and pressurised in the first cycle from 5 barg to 20 barg, the total nitrogen requirement amounts to 35,000 Nm3, which includes leak test, inertising and pressurisation. Frequently, hydroprocessing licensors specify a nitrogen amount with a peak flow rate of 3,000 Nm3/h. The standard configuration for the nitrogen line to the HP loop is 3in, equipped with a full-bore globe valve. As per industry standards, the allowed depressurisation rate stands at 20 bar/hour, prompting operators to fully open the 3in globe valve. With a 3in API 600 type globe valve with a Cv of 106 for a 1,500 lb rating, the flow results in 12,000 Nm3/h. In contrast, when considering compressible flow through a 3in 80 sch. pipe, the nitrogen flow rate is 8,000 Nm³/h where upstream nitrogen pressure is at 8 barg and downstream at atmospheric pressure. Key takeaway: The start-up nitrogen line for reactor loop pressurisation should be sized to match licensor-prescribed nitrogen demand in the utility summary. A noteworthy observation is that the peak nitrogen demand of a hydroprocessing unit significantly influences the overall peak demand of the refinery, especially when the refinery has multiple hydroprocessing units. At the design stage, it is proposed by some refiners that the peak nitrogen demand for hydroprocessing units be met using a tanker connected directly at the unit level. By this method, the hydroprocessing units’ peak nitrogen demand is removed from the overall refinery nitrogen balance. Consequently, potential savings are realised, as the requirement for a nitrogen liquid tank and vapouriser is eliminated. However, practical implementation can pose challenges due to limited access during unit shutdowns, especially during catalyst loading/unloading. A prudent approach is to inertise one hydroprocessing unit at a time. To minimise risk, at present, hydroprocessing units are 72 ARAMCO.indd 72 PTQ Q1 2024 not practising vacuum pulling while inertising the HP loop. This precaution helps to prevent potential hazards, such as oxygen entering the system due to leaks. If oxygen does enter, it could react with hydrocarbons and catalysts in the system, as well as compromise the iron sulphide passivation layer. Key takeaway: For optimal refinery operations, inertise one hydroprocessing unit at a time, considering a minimum peak demand rate of more than 3,000 Nm3/h for a 3in nitrogen line. Start-up nitrogen for hydroprocessing units low-pressure (LP) section As discussed in the previous section, hydroprocessing units are identified as one of the major units demanding peak nitrogen during start-up. Because of this, the hydroprocessing unit’s LP section is commonly inertised with steam. Once sufficient steam out is completed, fuel gas is introduced after steam venting to the atmosphere is boxed up. The LP section is pressurised to the maximum fuel gas pressure, which is typically around 4 barg. However, it should be noted that if the normal pressure of the stripper exceeds, say, 10 barg, the provision for nitrogen pressurisation to the LP section is considered prudent since the nitrogen header pressure is approximately 8 barg. Such nitrogen pressurisation is found essential during the start-up phase, especially when the stripper requires pressurisation beyond 4 barg. Key takeaway: It is recommended to provide a nitrogen connection in addition to a fuel gas connection for the LP section. Gap control for blanketing gas for vessel Normally, the surge drum level is permitted to fluctuate within a small band, typically within 5%, instead of maintaining strict control. Due to this small fluctuation in level, a swing in the drum pressure is caused. This pressure swing causes the blanketing valve to open when the level drops and the vent to flare to open when the level rises. The continuous activation of these valves leads to a loss of nitrogen from the surge drum. Typically, a dead band is incorporated into the surge drum pressure controller output, allowing the pressure to fluctuate without opening the valves in the nitrogen and flare lines for minor demands. Key takeaway: By implementing this gap control for all www.digitalrefining.com 08/12/2023 17:06:49 blanketing pressure controllers, the consumption of nitrogen can be minimised. Flow through utility station of nitrogen Different approaches for determining the normal and peak demand for refiners exist, and the determination of overall normal and peak demand is considered beyond the scope of this article. Nonetheless, it is observed across refiners that for both normal and peak nitrogen demand, the nitrogen flow through at least one utility station is considered. The nitrogen flow through a utility station is typically seen to range from 200 Nm3/h to 400 Nm3/h. It was observed that when considering compressible flow through a 0.75in pipe, the nitrogen flow rate is 350 Nm³/h where upstream nitrogen pressure is at 8 barg and downstream at atmospheric pressure. Utility station sizes very often are 1in. Key takeaway: The designer should consider the maximum possible nitrogen flow through a utility station while estimating normal and peak nitrogen demand. Conclusion This article emphasises key considerations for nitrogen management in refinery operations at the design stage, focusing on nitrogen blanketing in surge drums and tankage. The findings reveal that conventional guidelines, notably those based on API 2000 standards, may lead to overestimation of nitrogen requirements. Such overestimation not only elevates nitrogen demand but also contributes to operational inefficiency and waste. ac24_Decarbonisation Technology Magazine_178x125.indd 1 www.digitalrefining.com ARAMCO.indd 73 Beyond the scope of tank and surge drum blanketing, the articles outlines crucial best practices for handling nitrogen throughout various units in a refinery. This encompasses optimal purging protocols, sizing of nitrogen lines for HP hydroprocessing units, actual peak nitrogen flow through the utility station, necessity of nitrogen connection for the LP section of hydroprocessing units, and effective control mechanisms for gas blanketing. In summary, this article endorses a customised approach to managing nitrogen, considering actual operational scenarios. It suggests a balanced use of both standard and alternative methods without compromising safety. Implementing these recommendations has the potential to result in significant cost reductions, more efficient resource allocation, and the upholding of stringent safety norms. Appendices 1 and 2 can be viewed in the digital issue. Rajib Talukder is a Process Specialist in the Global Manufacturing Excellence department at Aramco, Saudi Arabia. He has more than 30 years of experience in process engineering and holds a B.Tech in chemical engineering from NIT Tiruchirappalli, India. Email: [email protected] Prabhas K Mandal is an Operations Engineer Specialist at Aramco. He has more than 30 years of experience in petroleum refining, and supports front end design development for capital projects. He holds a B.Tech in chemical engineering and a M.Tech in petroleum engineering. Email: [email protected] 23.10.2023 07:52:37 PTQ Q1 2024 73 08/12/2023 17:06:51 WE’RE COMMITTED TO YOUR EFFICIENCY Our analyzers make tough SRU work a little easier We know how hard it is to manage sulfur recovery unit (SRU) processes, and the levels of skill, concentration, and dedication your team needs. That’s why we make sure you don’t have to worry about your analyzers, too. We’ve been designing industry-standard SRU analyzers for decades, focusing on reliability, longevity, accuracy, robust design, and ease of use. We make analyzers for every part of the sulfur removal process – from SRU feed gas to the measurement of stack emissions, and everything in-between - so you get one convenient source for unparalleled engineering and support. AMETEKPI.COM/SRU ametek.indd 1 10/03/2023 16:13:37 Simulating VGO, WLO, and WCO co-hydroprocessing: Part 2 Economic analysis performed when co-hydroprocessing VGO, WLO, and WCO shows that WLO studied percentages increase hydrocracking unit net profits Mohamed S El-Sawy, Fatma H Ashour and Ahmed Refaat Cairo University Tarek M Aboul-Fotouh Al-Azhar University S A Hanafi Egyptian Petroleum Research Institute P art 1 of this study (PTQ, Q4 2023) presents simulation and analytical studies made on vacuum gasoil (VGO), waste lubricating oil (WLO), and waste cooking oil (WCO) co-hydroprocessing over commercial hydrocracking catalyst. This study follows our previous work which studied the co-hydroprocessing of VGO, WLO, and WCO experimentally on a lab-scale reactor, utilising the commercial hydrocracking catalyst. Most fuel producers prefer to utilise existing units to co-hydroprocess WLO, WCO, and VGO rather than install new separate hydroprocessing units because there is a high degree of similarity between units used to hydroprocess petroleum cuts and units to hydroprocess waste oils mixture with VGO. In this discussion, market analysis and economic studies were conducted to illustrate the flexibility and prevalence of using these unconventional feed mixtures (blends of VGO with WLO and WCO) as industrial feedstock during the COVID-19 pandemic, which caused transportation limitations and market upsets. The analysis focused on the fluctuations in crude oil, petroleum fuels, and bio-diesel prices last year. By mixing WLO and WCO with VGO as hydrocracking feed, good opportunities for expense optimisation and net profit maximisation can be found, especially when crude oil prices increase. Resource optimisation Many countries were highly affected by the COVID-19 pandemic and its consequences on global markets and economics. Hard times usually lead to a concentrated effort to use all available resources. One of these resources is waste oils and their application to convert to fuels with traditional esterification for WCO, distillation followed by extraction for WLO or hydroprocessing of both. Waste recycling has several benefits, including using waste as an energy source, which will suppress toxic and hazardous emissions into the environment and reduce greenhouse gas (GHG) emissions. In addition, waste recycling is stimulating development in the region as well as aiding social structure, especially in developing countries. Furthermore, the refining industry faces numerous challenges in producing high-quality fuels at reasonable costs. Cold flow properties are often a concern when dealing with products derived from hydroprocessing waste oils or VGOs.1,² www.digitalrefining.com CAIRO UNI.indd 75 Generally, the hydroprocessing unit consists of a reaction section and a fractionation section to separate the reaction products into desired product streams. Hydroprocessing units’ reactors commonly use a trickle bed reactor (TBR) configuration due to its simplicity, reliability, and good operability. A TBR is a fixed bed reactor with a trickle flow regime of hydrocarbon and hydrogen mixture moving from the top to the bottom of the reactor, passing through catalyst bed(s). Usually, heavy hydrocarbons and middle distillates hydroprocessing reactors consist of more than one catalyst bed with intermediate hydrogen quenching streams to control reaction temperature, as all hydroprocessing reactions are exothermic. Co-hydroprocessing of VGO, WCO, and WLO is a mixedphase reaction where liquid moves downwards and forms a laminar stream around the catalyst pellets and hydrogen is distributed through available voids in the catalyst bed. Reactions start by diffusing a dissolved hydrocarbon feed mixture and hydrogen in the catalyst pores, reaching the active sites. On the active sites, cracking and hydrogenation reactions occur. These are enhanced by increasing the reaction temperature and hydrogen partial pressure.³ Modelling and simulation are important tools for optimising plant profit and operating conditions. Modelling and simulation of an existing industrial hydroprocessing unit need operating conditions and product yield identification. The simulation model case of the hydroprocessing unit consists mainly of a reaction section and a fractionation section. The most complicated aspect of building the simulation model is the calibration of the kinetic model, which forms the core of the simulation. The reaction kinetics depend on many factors, such as reaction temperature, hydrogen partial pressure, liquid hourly space velocity (LHSV), feed composition, and catalyst configuration. From these data, in addition to product yields and specifications, simulation software can predict calibration factors that will be the core of the simulation model. To overcome the complexity of building hydroprocessing reactions kinetic models, many studies and technical papers recommend using commercial software to execute the modelling and simulation of hydroprocessing units.⁴ An extensive literature review has been conducted to study the technologies and equipment used industrially in the hydroprocessing of WCO and WLO individually, and PTQ Q1 2024 75 08/12/2023 17:11:35 101 Conversion wt% 100 99 Mix 1 Pred. (VGO 80% + WCO 20%) Conv. (%) 98 Mix 3 Pred. (VGO 80% + WLO 10% + WCO 10%) 97 Mix 1 act. (VGO 80% + WCO 20%) 96 Mix 3 act. (VGO 80% + WLO 10% + WCO 10%) 95 Mix 2 Pred. (VGO 80% + WLO 20%) 94 93 Mix 4 Pred. (VGO 70% + WLO 20% + WCO 10%) 92 Mix 2 act. (VGO 80% + WLO 20%) 91 370 380 390 400 410 420 430 440 450 Mix 4 act. (VGO 70% + WLO 20% + WCO 10%) Temp. (˚C) Figure 1 Predicted and actual reaction conversion the co-hydroprocessing mixture blended with petroleum feedstock. Axens has recently introduced a new proprietary technology called Revivoil, developed jointly with Itelyum (formerly Viscolube Italiana SpA). This technology is a significant step forward in waste lube oil re-refining and has the potential to accelerate its success. UOP has also developed with ENI a proprietary technology called Ecofining for hydroprocessing plant-derived oil. Feedstocks include plant-derived oils like soybean, rapeseed and palm. The co-processing of waste oils is not only of interest to process technology developers, but also to refineries. For example, Petrobras has developed the H-BIO hydrogenation process to produce renewable diesel using a mixture of waste vegetable oil and mineral oil in existing oil refineries through hydrotreating units. The co-processing of waste frying oils in a gasoil hydrodesulphurisation unit (HDS-I) at CEPSA’s refinery in Tenerife has been successful. CanmetENERGY’s research centre supports and funds such research activities. It has been observed that most refiners choose to inject WCO (on a large scale) or WLO (on a small scale) with VGO for co-hydroprocessing units, rather than installing a separate unit to hydroprocess pure WCO or WLO, taking into consideration the high degree of similarity between technologies and catalysts used in these units. The novelty of this work is to study the co-hydroprocessing of VGO, WCO, and WLO blend over commercial industrial hydrocracking catalyst. This will be followed by an economic study of the produced model in the recent market changes caused by COVID-19.5,6,7 The aim of this study is to simulate a conceptual design of an industrial hydrocracking unit that utilises the same catalyst as our previous experimental work.1 This conceptual design has been performed using Aspen Hysys V.11, which comes with a built-in hydrocracker model (HCR). This model simulates the hydroprocessing of light and heavy petroleum fractions based on a built-in reaction network and kinetic lumps. This simulation can be used to evaluate technically and economically co-hydroprocessing normal unit feedstock of VGO vs blends of unconventional feedstocks of WCO and WLO with VGO. Process simulation case The industrial hydrocracking unit licensed by UOP 76 CAIRO UNI.indd 76 PTQ Q1 2024 (commercially called Unicracking unit) was simulated using Aspen Hysys V.11. This unit was selected because it utilises the experimentally used catalyst (TK-711 and DHC-8) and a similar reactor bed configuration. The reaction section of the unit consists of two reactors. The first reactor has three beds, with one for hydrotreating and the other two for hydrocracking. The second reactor has two beds, both for hydrocracking. All five beds are roughly equal in weight. The unit is designed to process 33,500 barrels per stream day (BPSD) of combined feed consisting mainly of vacuum gasoil (VGO) from the vacuum distillation unit and heavy cocker gasoil (HCGO) from the delayed cocker unit. The unit is targeted to produce light fuel products from heavy petroleum distillates while removing the majority of impurities such as sulphur, nitrogen, and oxygen. Performance evaluation of simulation model The hydrocracking unit represented in the simulation case includes two main sections: the reaction section and fractionation section. The performance of the reaction section can be evaluated by comparing the predicted feed with the actual feed conversion. Figure 1 shows both the actual and predicted feed conversion wt%, represented by solid and dash lines respectively. A clear positive gap can be observed between the actual and predicted values of conversion. This gap widens as the WCO content in the feed mixture increases and reaches its minimum value or disappears completely when WCO is not present in the mixture. This observation aligns with the results of our previous work, which clearly states that increasing the WCO content in the feed mixture increases catalyst acidity and activity, leading to a higher reaction conversion at the same reaction temperature. The model provides accurate predictions of the relationship between reaction temperature and conversion profile in the hydrocracking reactor. This is important for estimating product yields and hydrogen consumption (see Figure 2). This prediction tool helps in anticipating the operating cost of each case and determining its feasibility. There are seven different products in the simulated hydrocracking unit, namely: purge gas, fuel gas, LPG, hydrocracked naphtha (represented as gasoline in this study), kerosene (generally known as jet fuel or dual-purpose kerosene [DPK]), diesel (ultra-low sulphur diesel according to Euro www.digitalrefining.com 08/12/2023 17:11:39 n 1 AADs = –n ∑(|Ypred.- Yact.|) i=1 for the 16 runs expressed in the following graphs for product property value.⁸ These AAD values help in evaluating the degree of variation between actual and simulation cases. This represents the prediction of the model on each product yield rather than the overall yield, which is the revenue key of the refinery. In contrast, absolute deviation shows how the model affects the estimation of the refinery profit by considering deviations in the same scale towards overall production. Figure 4 compares the predicted gasoline yield (dash lines) and actual gasoline yield (solid lines) from studied test runs. It is evident that the predicted values are very close to the actual values in the range of 380-400°C. This is the recommended operating window of the commercial catalyst used in this study, as stated by the catalyst manufacturer and process unit licensor. Table 1 shows the calculated overall AADs for each studied product yield and stream property value. Market and economic analysis Crude oil prices are the most determining factor for fuel costs. Available crude oil price trends show gradual ascending logic behaviour, with two sharp declines at the end of 2018 and the beginning of 2020. The first decline was caused by political negotiations about production quantities ruled by the Organization of the Petroleum Exporting Countries (OPEC), especially the Kingdom of Saudi Arabia and its share in the oil market competing with Russia and Iran. The second decline was caused by the COVID-19 pandemic. Due to the pandemic, there were restrictions on movements, especially across countries, leading to a decrease in fuel demand and hence a reduction in crude oil prices. In response, the oil sector adjusted by reducing fuel production to achieve price balance. There was also a decrease in movement restrictions, the production of new vaccines, and an increase in the number of vaccinated people to achieve herd immunity or community immunity. These rapid changes in crude oil prices were interesting to study. In this section, a brief economic analysis studies how the business model of the hydrocracking unit changed over the previous year.⁷ H2 make up Nm3/Sm3 of fresh HC feed 490 480 H2 M/U Nm3/Sm3 fresh feed 5 specifications), and unconverted cooking oil (UCO). The four products that are the main focus of this study are LPG, gasoline, kerosene, and diesel, as they make up more than 95% of the total production. Figure 1 and other figures presented in this study show a comparison between the model predictions and actual values of resulting product yields. The average absolute deviations (AADs) are calculated using the following equation: 470 460 450 440 430 420 410 400 370 380 390 400 410 420 430 440 450 Temp. (˚C) Mix 1 Pred. (VGO 80% + WCO 20%) Mix 2 Pred. (VGO 80% + WLO 20%) Mix 3 Pred. (VGO 80% + WLO 10% + WCO 10%) Mix 4 Pred. (VGO 70% + WLO 20% + WCO 10%) Figure 2 Predicted make-up of hydrogen from hydrocracking simulation model at different reaction temperatures and feed mixtures In contrast, looking at the long-term behaviour of the oil market, supply is ensured since new deposits are continuously discovered. However, despite the steady supply, the demand for oil is not expected to increase as environmental restrictions become more stringent in developed countries. For example, the International Maritime Organization (IMO) lowered the limit for sulphur content in marine fuel from 3.5% to 0.5% in 2020. When reviewing the prices for VGO, WCO, and WLO, it has been noticed that there is a narrow margin between the selling price of ultra-low-sulphur diesel, jet fuel, and gasoline and feedstock price. This indicates that the fuel market for fossil fresh feed and waste recycle feed is highly competitive. As a result, selecting the capacity of the processing plant needs to be done with great care to ensure profitability. This study has already selected the process capacity, as the research work depends on the commercial catalyst used in the existing plant, while the operating conditions of this plant are used in building the simulation model. It is worth mentioning that research work has confirmed the availability of WCO and WLO quantities in the local market. This ensures a stable supply chain and stable production of the hydrocracking unit under the studied feed mixtures and pre-selected unit processing capacity. Based on this data, the capacity of the hydrocracking unit AAD values at different temperatures for each studied product yield and product property value Gasoline yield Kerosene yield Diesel yield (Kerosene + diesel) yield AAD @380 °C 0.43 0.99 0.79 0.06 AAD @400 °C 0.18 0.98 0.41 0.03 AAD @420 °C 0.28 0.98 0.68 0.06 AAD @440°C 0.38 0.98 0.94 0.12 AAD 0.32 0.98 0.71 0.07 Table 1 www.digitalrefining.com CAIRO UNI.indd 77 PTQ Q1 2024 77 08/12/2023 17:11:41 Operating cost items UOM basis Hour Nm3 Nm3 Nm3 kWh Ton m³ 10000 Cost, $ 250 0.21 0.18 0.08 0.07 14.7 0.24 Net profit (US $/hr) Item Indirect operating cost Fuel gas cost Natural gas cost Hydrogen make-up cost Electricity cost Steam cost Cooling water cost 15000 2 3 T = 380˚C T = 400˚C 4 -10000 -15000 -20000 Feed mixture T = 440˚C price continues to rise. Figure 6 shows that the profit margin increases as the price of crude oil compared to waste oil increases. Finally, economic models indicate that WLO offers significant cost savings and can increase unit net profit, regardless of fluctuations in crude oil prices. Conclusion Commercially available software was used to build a simulation case of an industrial hydrocracking unit using the same catalyst and reactor configuration as our previous experimental runs.¹ This case is a reliable prediction tool, with only a minor deviation from actual mass, heat balance, and product specifications. The total reaction conversion values predicted by the simulation model of 16 run cases show a good match between the simulation model and actual values, with a positive gap between the actual values in most cases. This gap widens as the WCO content in feed mixtures increases. This happens because the acidic nature of WCO increases catalyst cracking activity, leading to enhanced reaction conversion under the same operating conditions of reaction temperature, hydrogen partial pressure, and LHSV. The Aspen Hysys built-in fluid package (HCRSRK) needs to be modified to accurately predict hydrocracking catalyst activity in the presence of WCO, accounting for the 45000 40000 Net profit (US $/hr) 25000 20000 15000 10000 5000 0 T = 420˚C Figure 3 Net profit values of the studied cases at Dated Brent = 18.8 $/bbl 30000 Net profit (US $/hr) 1 -5000 -30000 has been set to 297 tons of hydrocarbon feed per hour. This implies total processing of around 98,000 tons of hydrocarbon oil feed mixture per year, with more than 90% of the feed mixture being converted into lighter valuable hydrocarbon product. As previously stated, three economic business models are examined in this study. The first model was made just before the start of the COVID-19 pandemic. It was selected at a Brent crude oil price of 18 $/bbl on 16 April 2020, affected by a worldwide lockdown. The second model was created after the crude oil price stabilised and air flights were partially opened. The Brent crude oil price was 42 $/bbl on 29 June 2020. The third model was created at the beginning of 2021 on the 12 February at a Brent crude price of 62 $/bbl when normal life conditions had resumed after more than a third of the world’s population had been vaccinated with the COVID-19 vaccine. The economic evaluation of the research work at three selected times showed different net profit rates depending on feedstocks and product prices. Economic analysis for each model are based on operating expense details mentioned in Table 2. The economic data of the three studied scenarios are represented in Figures 3, 4 and 5. Crude oil price increases benefit the net profit of the 16 studied cases. It is also observed that the highest net profit is achieved for the feed mixture evaluated at reaction temperature of 400°C, regardless of the crude oil price. So, there is a great opportunity for applying the studied feed mixtures to increase profit, especially if the crude barrel 1 2 3 4 Feed mixture T = 380˚C T = 400˚C T = 420˚C T = 440˚C Figure 4 Net profit values of the studied cases at Dated Brent = 41.8 $/bbl PTQ Q1 2024 35000 30000 25000 20000 15000 10000 5000 0 -5000 CAIRO UNI.indd 78 0 -25000 Table 2 78 5000 1 2 T = 380˚C T = 400˚C Feed mixture 3 T = 420˚C 4 T = 440˚C Figure 5 Net profit values of the studied cases at Dated Brent = 62 $/bbl www.digitalrefining.com 08/12/2023 17:11:43 actual resulting activity increase caused by the acid nature of WCO. Predicted values of gasoline and middle distillates (kerosene and diesel yields) product yields from the simulation case closely match the actual values from the experimental test run. However, the predicted individual values for kerosene and diesel do not match the experimental test run values due to different cut points between the experimental test runs and the fractionator built in the simulation case. Hydrogen consumption in the test runs is calculated through the simulation case, showing that accepted hydrogen consumption rises with an increase in conversion, reaction temperature or WCO content. Finally, an economic analysis of the proposed alternative feed mixtures shows high flexibility during energy market upsets caused by the COVID-19 pandemic. This analysis shows that using WLO with studied percentages increases the hydrocracking unit’s net profit (see Figure 7). On behalf of all authors, the corresponding author states there is no conflict of interest. References 1 El-Sawy M S, Hanafi S A, Ashour F, Aboul-Fotouh T M, Co-hydroprocessing and hydrocracking of alternative feed mixture (vacuum gas oil/waste lubricating oil/waste cooking oil) with the aim of producing high quality fuels, Fuel, Vol 269, pp.117,437, 2020. 2 Inform from website: www.eia.gov/outlooks/steo/archives/apr16.pdf. 3 Elshout R V, Bains C S, Moving up a Tier – Part 2: Upgrading the bottom of the barrel, Hydrocarbon Processing, Vol 97 pp.312, 2018. 4 Bezergianni S, Athanasios D, Temperature effect on co-hydroprocessing of heavy gas oil-waste cooking oil mixtures for hybrid diesel production, Fuel, Vol 103, pp.579-584, 2013. 5 Sbaaei E S, Ahmed T S, Predictive modeling and optimization for an industrial Coker Complex Hydrotreating unit – development and a case study, Fuel, Vol 212, pp.61-76, 2018. 6 Naderi H, Shokri S, Ahmadpanah S J, Optimization of kinetic lumping model parameters to improve products quality in the hydrocracking process, Brazilian Journal of Chem Eng, Vol 35, pp.757-768, 2018. 7 Dagde K K, Puyate Y T, Modelling and simulation of industrial FCC unit: Analysis based on five-lump kinetic scheme for gas-oil cracking, International Journal of Engineering Research and Applications, Vol 2, Issue 5, pp.698-714, 2012. 8 Bhutani N, Ray A K, Rangaiah G P, Modelling, simulation and multi 42500 26001 11775 0 10 0.4 20 30 0.7 40 50 60 70 Dated Brent price (USD) WLO price/Brent price WCO price/Brent price Net profit Case: T400-WLO20-WCO00-VGO80 Figure 6 Effect of change in (crude oil price/waste oils price) ratio on net profit for the case at 400ºC reactor temperature and 20% WLO, 0% WCO, and 80%VGO objective optimization of an industrial hydrocracking unit, Industrial & Engineering Chemistry Research, Vol 45, Issue 4, pp.1354-1372, 2006. Mohamed S El-Sawy is a Hydroprocessing Lead Process engineer at ‘Worley’ with a history of working in the oil and energy industry. He holds a PhD in chemical engineering from the Faculty of Engineering, Cairo University. Email: [email protected] Fatma H Ashour is the former Director of the Center of Hazard Mitigation, Environmental Studies, and Research at Cairo University and former chairperson of the Chemical Engineering Dept. at Cairo University. She holds a BSc, MSc and PhD in chemical engineering from Cairo University. Ahmed Refaat is an Assistant Professor at Cairo University/King Salman International University. He has published 12 international publications and 16 conference papers as well as an invited book chapter in Elsevier. Tarek M Aboul-Fotouh is an Associate Professor of Petroleum Refining Engineering in the Mining and Petroleum Engineering Dept. at Al-Azhar University. He holds a PhD in chemical engineering from Azerbaijan State Oil and Industry University. Samia A Hanafi is the Professor of Petroleum Refining at Egyptian Petroleum Research Institute. She holds a BSc, MSc, and PhD in chemical engineering from Cairo University. She has more than 30 international publications and supervised more than 20 MSc and 10 PhDs. LPG WCO Naphtha H2 WLO 1.6 1.1 0.5 0.2 Cat. Co-hydroprocessing Kerosene VGO Diesel Save money and environment Experimental work Simulation on existing unit Data validation Economic analysis Figure 7 Represental graphic www.digitalrefining.com CAIRO UNI.indd 79 PTQ Q1 2024 79 08/12/2023 17:11:45 We make chemistry happen Sulzer Chemtech is global market leader in reaction, separation, purification, static mixing as well as polymer processing technologies. With a comprehensive offering that includes process components all the way to complete process plants and technology licensing, we can serve a broad range of industries with key solutions to intensify processes, increase efficiency and improve product quality. With an ever-expanding portfolio of cutting-edge products that supports circularity while reducing material and energy use as well as emissions, we are the ideal partner to support the net zero transition of businesses across the chemical and polymer value chains. We also offer our technology innovations to support the sustainable manufacturing of bioplastics, renewable fuels, chemical recycling for unrecyclable materials as well as carbon capture technologies. sulzer.indd 1 08/12/2023 12:56:18 Considerations for crude unit preflash drums and preflash towers A guide to debottlenecking, revamping, designing, and operating crude unit preflash facilities based on literature and the authors’ experience Henry Z Kister and Walter J Stupin (dec.) Fluor Maureen Price Maureen Price Consulting LLC P reflash drums or towers are extensively used in crude feed trains between the desalter and the atmospheric tower heater. Preflash drums or towers have been discussed by many literature references, each focusing on one or a few important aspects and providing valuable guidelines. None of these attempted to bring together all these lessons in a manner that can guide engineers involved in the debottleneck, revamp, design, and operation of crude units. Purpose and location in the crude train In crude oil refining, a preflash drum or tower is a vessel that flashes a portion of the light components of the crude as well as some water upstream of the atmospheric tower charge furnace. The use of preflash drums or preflash towers between the desalter and the crude atmospheric tower is typically done to manage crude hydraulics, as part of grassroots unit design, to increase crude capacity, or to allow processing of lighter crudes as part of a revamp. As the preflashing term suggests, the primary function of these devices is to flash the lighter (volatile) portion of the crude oil before it enters the furnace inlet control valves. These control valves distribute the feed to the various heater passes. Flashing upstream of these valves makes it impossible to distribute the feed to the heater passes adequately. Pass flow imbalances cause heater bottlenecks, Top-PA Naphtha Water Mid-PA Steam Kerosene Bottom-PA Steam Diesel Desalter Crude atmospheric column Preflash drum Steam Gasoil Water Crude preheat Crude oil Steam Crude heater Atmospheric residue Figure 1 Preflash drum scheme with the drum overhead routed to the flash zone of the atmospheric tower www.digitalrefining.com KISTER FLUOR.indd 81 PTQ Q1 2024 81 08/12/2023 17:25:29 Top-PA Naphtha Water Mid-PA Steam Kerosene Bottom-PA Steam Diesel Desalter Crude atmospheric column Preflash drum Steam Gasoil Water Crude preheat Crude oil Steam Crude heater Atmospheric residue Figure 2 Preflash drum scheme with the drum overhead routed to a higher point in the atmospheric tower rapid coking, and even tube overheating and rupture. The alternative is to use high-pressure booster pumps with expensive high-pressure piping and exchangers to prevent flashing upstream of the valves. In addition, vapourisation in the crude train dramatically increases the pressure drop, which may restrict the crude feed rate. Depending on the configuration, preflashing may also be valuable in debottlenecking the furnace and/or the atmospheric tower, especially when processing lighter crudes (>30° API). Preflash devices can be located anywhere in the preheat train, with temperatures typically varying from 300°F to 500°F.1,2 Higher temperatures give higher preflashing rates. Preflash device pressure often ‘rides’ on the atmospheric tower pressure, but in some cases preflashing is performed at higher pressure by adding a control valve in the drum overhead vapour line. Preflash towers with condensers have their own pressure control systems. A key consideration is where the preflash drum overhead vapour is routed. In most crude trains, it is routed to the flash zone of the atmospheric tower (see Figure 1). In this configuration, it debottlenecks neither the furnace nor the tower. Its only merit, then, is to permit lower pressures to be used upstream of the furnace control valves. Any unloading it does on the furnace is countered by the need to add heat in the furnace to make up for the cooler drum overhead vapour bypassing the furnace into the flash zone of the atmospheric tower. The bypassing of lights raises the coil outlet temperature, raising the potential for coking or encountering metallurgical limitation. 82 KISTER FLUOR.indd 82 PTQ Q1 2024 Golden3 presents a case of a unit processing 26.3° API crude, with the heater coil outlet temperature maintained at 700°F. Raising the preflash temperature from 275ºF to 400°F reduced the heater duty by 12% but increased the resid yield on the crude from 48.2% to 51.1%. The significant loss of distillates to resid was because no heat was added in the furnace to make up for the cooler drum overhead vapours entering the atmospheric tower flash zone. If one wanted to keep the resid yield unchanged for the same increase in preflash temperature, the heater coil outlet temperature would have needed an increase of 22°F (to 722°F). An alternative configuration to debottleneck the furnace and atmospheric tower is to have the preflash drum overhead routed to a point further up in the atmospheric tower, as shown in Figure 2. In this configuration, the preflash drum unloads the furnace and the section of the atmospheric tower below the point of entry of the preflash drum vapour into the atmospheric tower, which in Figure 2 is above the diesel draw. The maximum unloading is achieved with a preflash tower (or pre-fractionator), as shown in Figure 3. This arrangement gives a large unloading both on the furnace and the entire atmospheric tower. With light crudes ( >30º API), debottlenecking of 10-20% can be achieved using a preflash tower. In some cases, some kerosene can also be drawn from a preflash tower a few trays above the feed. It has been estimated that approximately 20% of the crude distillation units in North America include an independent crude preflash tower.2 www.digitalrefining.com 08/12/2023 17:25:30 Light naphtha Top-PA Naphtha Water Preflash tower Mid-PA Steam Kerosene Bottom-PA Steam Diesel Desalter Crude atmospheric column Steam Gasoil Water Crude preheat Crude oil Steam Atmospheric residue Crude heater Figure 3 Preflash tower scheme Effect on atmospheric tower stripping: “The carrier effect” The unloading achieved by the Figure 2 and, more so, Figure 3 alternatives is not free. The preflashed naphtha bypasses the flash zone of the atmospheric tower. Naphtha is a light, and as a light, it helps the stripping in the bottom of the atmospheric tower. Having it bypass the flash zone means less stripping of lights from the resid. Stichlmair and Fair4 present charts showing that liquid yield from a flash declines when light components are added to the mixture. Adding a light component generates a significant partial pressure in the vapour phase, reducing the partial pressures of the heavier components and promoting their stripping. This effect was studied and discussed at length by Ji and Bagajewicz5 for the flash zone of the atmospheric crude tower. They show that when the K-value of a component is greater than 30, the light component (hexane and lighter) will have the same stripping effect on a molal basis as steam. Other naphtha components will have a smaller, yet significant, stripping effect. When some of these components are removed in a preflash drum or preflash tower and do not reach the flash zone of the atmospheric tower, there will be a greater need for stripping steam. Alternatively, especially if there is a constraint on the stripping steam, it means a greater loss of gasoil or diesel yield. In one case5 of light crude with no steam increase, the loss was shown to be as high as 2%. Typically, the steam can be increased to some extent, and the loss of gasoil to resid with light crudes is around 0.3-0.5% of the crude. With heavy www.digitalrefining.com KISTER FLUOR.indd 83 crudes, the loss with no steam increase is much smaller, often around 0.3%. Effect on water dew point When using a preflash tower with an independent condenser/reflux drum system (Figure 3), some of the naphtha is completely bypassed around the atmospheric tower, which raises the dew point and salt point at the tower overhead. This is tempered (usually to a small extent) by the removal of the entrained water in the crude, as well as some of the water dissolved in the crude, in the preflash tower. As this water ends up in the preflash tower overhead, it bypasses the atmospheric tower. With most atmospheric towers attempting to keep a margin (typically 25°F) above the water dew point, the naphtha bypassing means either cutting the stripping steam (usually practised) at the expense of larger loss of diesel or gasoil yield to the resid or raising the atmospheric tower overhead temperature, which loses kerosene to the naphtha. There are other means of countering the naphtha bypassing. One scheme is to send preflash naphtha or naphtha recycle to near the top of the atmospheric tower, but this comes at the price of loading up the upper section of the tower and reducing its thermal efficiency. Another scheme is Soun Ho Lee’s idea6 of refluxing the preflash tower with naphtha from the atmospheric tower and returning the preflash tower vapour to the atmospheric tower (see Figure 4). Finally, the metallurgy near the top of the atmospheric tower can be upgraded at a significant cost of course. PTQ Q1 2024 83 08/12/2023 17:25:31 Top-PA Naphtha Water Mid-PA Semi-preflash tower Steam Kerosene Bottom-PA Steam Diesel Desalter Crude atmospheric column Steam Water Gasoil Crude preheat Crude oil Steam Atmospheric residue Crude heater Figure 4 Preflash tower scheme with reflux from and vapour going to the atmospheric tower⁶ Foaming Foaming is a prime consideration for preflashing devices in crude oil distillation. In the words of one expert,7 ‘it is not a matter of if foaming is occurring, but rather to what degree it is occurring’. The foaming severity tends to vary with the crude, with some crudes generating much more severe foaming problems than others.⁸ Simple ‘bottle shake’ tests can often provide information on the degree of foaminess. The foaming could be due to traces of components with surface active properties combined with the effects of fine solid particles. Some of these components may originate in the desalter chemicals or those used for crude recovery at the well. Many of these chemicals decompose in the furnace, which is why preflash devices foam while stripping sections in atmospheric towers usually do not. In some cases, desalter upsets cause episodes of carryover from the preflash drum. When foam is carried over with the vapour to the upper sections of the atmospheric crude column, it adversely affects the quality of the products. Typical concerns are poor kerosene and diesel quality and high carbon residue and metals in atmospheric gasoil (AGO). Flashed crude is dark and has a high endpoint. When it enters the atmospheric tower above the flash zone, all product streams below the entry point will contain flashed crude. Even small amounts of foam carryover will cause colour and endpoint problems with kerosene and diesel. Once the crude gets into the upper sections of the atmospheric tower due to a foamover, it gets into the pumparounds and stays in the system for lengthy periods of time, 84 KISTER FLUOR.indd 84 PTQ Q1 2024 causing the product quality issue to linger. The crude also gets into the diesel and kero hydrotreaters and rapidly deactivates their catalysts. Combined diesel and AGO product yield losses as high as 6 vol % on crude have been reported due to flashed crude entrained with the preflashed vapour.1,9 The foam also brings naphthenic acids and sulphur into places not designed to handle them. Additional adverse effects of foamovers are cavitation of the preflash drum or tower bottom pump, which can interrupt the feed to the furnace and atmospheric tower and initiate a shutdown. If the drum overhead vapour passes through furnace convection coils, crude carryover can severely coke the convection coils. If the drum overhead goes to the atmospheric tower flash zone, the carryover will generate a cold spot upon tower entry that will suck vapour downward. Foaming can be controlled, to some degree, by antifoam injection, typically silicones, upstream of the preflash drum. This is not favoured by most refiners due to contamination of products, adverse effects of antifoams or their degradation products on hydroprocessing catalysts downstream, and high antifoam costs. For fear of foamovers and their consequences, most refiners route the overhead of their preflash drums to the flash zone of the atmospheric tower rather than to the upper sections of the tower (see Figure 1), at the price of forfeiting many of the unloading benefits that preflash drums can offer. Even when the drums are well-sized and contain de-foaming devices, many refiners still prefer to route the drum overhead into the flash zone for fear of the severe implications of even a few foamover events. www.digitalrefining.com 08/12/2023 17:25:31 Figure 5b VTC device Courtesy of EGS Systems, Inc. Figure 5a VTC Systems principle of operation Courtesy of EGS Systems Inc. This is where the preflash tower is at a major advantage. Should a foamover occur, it only affects its overhead product and does not contaminate the atmospheric tower or its Figure 6a GIRZ cyclonic gas inlet device pumparounds and hydrotreaters. In addition, with a pre- Courtesy of Sulzer Chemtech flash tower, operators get ample warning of a foamover. A foamover floods the preflash tower trays, which can easily the top, and the liquid drains from the bottom. Figure 6b be observed by a differential pressure rise (a reliable dif- demonstrates the effectiveness of the GIRZ cyclonic gas ferential pressure transmitter must be provided!). Once the inlet device in preventing foamovers. However, even though operators see a differential pressure rise, they have enough this technology helps reduce the chances of foaming, it was time to divert the naphtha product out of the product tank recommended⁶ that the preflash drum should be sized large into a slop tank, preventing any contamination. enough to prevent foaming. Even though vortex foam sepA thorough discussion of foam-related issues and their arators are highly reliable, infrequent failures have occurred, control when using crude unit preflash drums is presented mainly due to mechanical issues involving supports, and it by Barletta, Hartman, and Leake.1 This article discusses in takes only one good foamover to contaminate the products detail how the entrained foam impacts product yields and from an atmospheric tower badly. qualities. It also discusses the use of vortex tube clusters Although these separators may be costly, they are effec(VTC) systems in crude unit preflash drums. tive in eliminating foamovers and protecting product quality. When it comes to vortex or cyclone foam separators, there Fluor has good experience with both technologies, and has are two popular technologies. One is the VTC systems from pioneered the use of VTCs together with MPC.1⁰ EGS Systems, described above1,11 and shown in Figures 5a and 5b. The other is Sulzer’s proprietary GIRZ cyclonic inlet device, shown in Figures 6a and 6b. Figure 5a illustrates the principle of vortex foam separators operation. The foam is separated by the centrifugal forces that send the liquid to the walls, forming a continuous liquid phase, while the vapour forms a continuous phase that concentrates Figure 6b Action with and without GIRZ cyclonic gas inlet device in a Courtesy of Sulzer Chemtech in the centre. The vapour exits from demonstration flash drum with foam www.digitalrefining.com KISTER FLUOR.indd 85 PTQ Q1 2024 85 08/12/2023 17:25:34 Foam height (ft), (above HHLL) Sizing preflash devices 6 5 4 3 2 1 0 0 5 10 15 20 25 30 35 Superficial liquid velocity (gpm/ft2) Figure 7 Foam height vs superficial liquid velocity Basis Figure 5, Reference 8 In preflash towers, even with vortex foam separators, some entrainment from the flash zone remains, which would normally be washed down by the reflux. If the reflux on the tray above runs dry or very low, this entrainment may lead to a dark product, as we have experienced. Lastly, good instrumentation is invaluable in alleviating and managing foamovers. Pressure, levels, flow rates, and, most of all, temperatures can provide operators with an early indication of the onset of foamovers. Instability in drum level, pressure, and flashed crude flow rate forewarns the approach of a foaming episode. Reliable measurement of the drum level has been inherently problematic due to foam formation. Seeing a ‘split level’ in the sight glass indicates likely foam.3 A nuclear-level device has been advocated for monitoring the preflash drum or tower level.7 Watching the preflash drum overhead temperature and the bottom pump for cavitation is also invaluable for detecting foamovers. With preflash towers that have a kero side draw, it is imperative to closely monitor the colour of the draw because that is where the foamover is first seen.⁷ Naphtha Reflux Crude feed Preflash crude Figure 8 Adding this horizontal drum did not alleviate foaming 86 KISTER FLUOR.indd 86 PTQ Q1 2024 The ideal preflash drum is horizontal because the cross-sectional area for flashed crude flow is larger. However, the plot area available may be insufficient for a horizontal vessel, and a vertical vessel would be preferred, particularly in revamps. Because the cross-sectional area for flashed crude flow in the vertical drum is smaller, it will require more vessel height to retain the foam. A preflash drum, as well as the bottom section of a preflash tower, must have sufficient height to contain the foam to prevent the rising vapour from carrying foam (flashed crude) into the drum overhead or the upper preflash column trays. Conventional trays will not break foams and will flood upon foamovers. Barber and Wijn⁸ presented the results of experiments on pilot and full-scale preflash drums processing various crudes at several operating conditions. Based on these data, Barber and Wijn derived a model and correlation that can be used to design crude preflashing devices. According to their tests, the key sizing criterion for the drum or the tower bottom section is the flashed crude downward superficial velocity, which should be low enough to allow the foam to be retained inside the drum or in the bottom of the tower. As long as there is sufficient height above the maximum clear liquid level (HHLL), foamover is unlikely. The smaller the cross-sectional area for flashed crude, the higher the foam level inside. If the disengaging height above the maximum clear liquid level is small, then the superficial velocity must be low. Conversely, if the available height to retain the foam is high, then a higher superficial velocity can be tolerated before the foam is no longer retained. The Figure 7 correlation8 applies to a crude oil superficial liquid velocity in the range of 15 to 30 gpm/ft2. We have had excellent experience with this correlation, and it seems to extrapolate well to values up to 60 gpm/ft2, but extrapolation beyond 30 gpm/ft2 cannot be done with confidence. It is important to check the preflash tower or drum size for the lightest (and heaviest) crudes intended to run, including start-up conditions with slop reprocessing.3 Some literature sources advocate a residence time criterion for preflash drum sizing (for example, three minutes). The authors’ experience strongly favours the downward velocity criterion above but does not support a residence time criterion. In an attempt to alleviate severe foaming in one preflash tower (not a Fluor design), a refinery added a horizontal drum in parallel with the tower’s vertical sump. The liquid and vapour spaces of the drums were connected by large lines, as shown in Figure 8. Doubling the residence time with the addition of the horizontal drum did very little to alleviate the foaming. The downward velocity remained unchanged as all the crude was fed to the flash zone of the tower. Drum or tower inlet devices Barber and Wijn⁸ also found that foaming in the preflash drum or tower is strongly affected by the inlet device. The inlet device needs to be adequately designed and carefully checked. www.digitalrefining.com 08/12/2023 17:25:40 In one case, a new preflash drum was sized per Figure 7, but upon start-up the drum experienced severe entrainment. Following the Fluor FEED design, the detailed design was turned over to a local contractor who installed a baffle in front of the crude inlet nozzle that was open at the top and bottom and closed on the sides, causing an impingement jet onto the liquid level and shooting crude upwards. In another case (again, not a Fluor design), a preflash tower12 experienced frequent episodes – especially with light crudes – in which the naphtha stream leaving the tower turned dark, accompanied by a high tower dP. These episodes originated from crude entrainment and restricted the throughput of the entire crude unit. The root cause was diagnosed to be excessive feed velocities with poor feed entry design. The entrainment problem was eliminated, and the naphtha make could be raised by more than 20% by a unique feed entry design by Fluor for the very high-velocity feed. This was achieved by removing two segments of the top shed deck and by a specially designed impingement baffle to break the incoming momentum. Key takeaway: It is imperative to correctly specify the feed inlet design and/or thoroughly check inlet designs by others. Trays or packing in preflash towers Most preflash towers recover naphtha as the only product. Some also draw an additional kero stream as a side draw (usually a small flow) a few trays above the feed. When drawing kero, a pumparound that preheats crude is sometimes used right above the kero draw. The kero may be sent to the stripper or the kero-naphtha section of the atmospheric tower. Preflash towers have trays and reflux to fractionate overhead product from the kero side draw or bottom product streams. Random or large structured packings have also been used with success, although trays are preferred. It is important that the trays, at least those right above the feed, are fouling-resistant, as crude carryover, entrainment, and foamovers (especially during upsets and power cuts) tend to entrain foulants into the trayed sections. Entrained waxes and resins can bond together and crystallise out on the lower trays. Fouling of the lower trays has been experienced even when VTC has been installed in the flash zone (see Figure 9). Cases have been observed where moving valve trays and fixed mini-valve trays right above the flash zone plugged. Salting out and corrosion near the top have also been experienced and, again, favour using fouling-resistant trays such as Sulzer’s SVG fixed valves with 0.5in opening, LVG fixed valve trays, or Koch-Glitsch’s ProValves. The trays near the top should also have corrosion-resistant metallurgy. The economics dictates using a reflux ratio just enough to achieve the naphtha product specification (typically the 95% ASTM D86 temperature). Adding reflux beyond this recycles some of the naphtha back into the crude, which in turn counters the benefits of the tower. There are typically 15-20 trays used above the flash zone, giving about 8-10 theoretical stages. Minimising the reflux often generates spray regime conditions (low liquid rates and high vapour rates), with tray www.digitalrefining.com KISTER FLUOR.indd 87 Figure 9 Plugged mini-fixed valves in wash section of preflash tower drying and/or break of downcomer seal, accompanied by fouling, plugging, and instability. This is especially severe when drawing kero, as the ‘wash’ section below the draw is particularly liquid-lean with weir loads often below 1 gpm/in. Due to the temperature gradient, the driest spot is just above the flash zone, and here the potential for plugging and seal loss is maximised. A good spray regime design (avoiding excessive open area, keeping downcomer clearances low (1-1¼in), and judiciously using picket-fence weirs) is essential. Liquid reflux and the wash below the kero draw (if it exists) need to be on flow-controlled pumpback to avoid fluctuations that can dry out the trays and break the downcomer seals. Adding vortex tubes at the flash zone (Figures 5 and 6), or at least ensuring a good feed distributor, will improve reliability, alleviate foamovers and entrainment, and may be relatively inexpensive. In many preflash towers, especially those recovering kero as a side draw, designers add trays or packings below the flash zone and use stripping steam to recover more naphtha or kero from the crude. We prefer not to do this due to foaming concerns (see next paragraph), but some clients insist. If stripping steam is used, its ideal rate is 10 lb/bbl, but many units use less than that. There are also reboiled preflash towers using fired heaters. A study by Sloley² found that using a stripping section saves energy. Regular trays (fouling-resistant) or packings in the stripping sections work fine as long as severe foaming is not experienced, which is probably 50% of the time. However, trays or packings below the feed can be disastrous if foaming is experienced, which is the other 50%. There was one case in which it was necessary to remove the stripping trays to stop foaming in the stripping section trays from severely bottlenecking the entire crude unit. Trays or packings are, therefore, not recommended for the stripping section. Shed decks and grid packings have shown good performance in the stripping section of preflash towers. With their large open area, they can be designed to handle foam. Correct design of the shed decks and grid packing is essential in this service. PTQ Q1 2024 87 08/12/2023 17:25:40 AFPM Annual Meeting Grapevine, Texas · March 10 – 12, 2024 The world’s premier refining meeting. Assembling executives, decision-makers, investors, and technical experts from across the downstream sector. With the 2024 U.S. presidential election on the horizon, the 2024 AFPM Annual Meeting will focus on energy markets against an evolving national and geopolitical landscape. Register today! afpm.org/events/AnnualMeeting2024 4009_AFPM_2024_AM_Print_Ad_full_page_297x210_v1.indd 1 afpm.indd 1 12/12/23 09:46:38 11:54 AM 13/12/2023 Preflash tower condenser and drum Many preflash towers have their own condenser and reflux drum system, and their naphtha products are sent to the naphtha processing facilities downstream of the atmospheric tower (Figure 3). If the condenser and drum of the atmospheric tower have enough capacity, Capex can be saved by sending the preflash tower overhead to the atmospheric tower condenser and drawing reflux for the preflash tower from the atmospheric tower reflux drum. The scheme proposed by Lee,6 Figure 4, also eliminates the preflash tower condenser and drum and saves Capex. Adding a preflash tower and condenser (as in Figure 3) debottlenecks the atmospheric tower condenser. As many atmospheric crude towers are bottlenecked by their condenser capacities, this condenser debottleneck is invaluable not only for achieving a higher throughput from the unit but also for allowing better recovery of distillates (gasoil and diesel) from the resid. Additional atmospheric tower condenser capacity allows reducing pressure in the tower, which vapourises some of the resid into gasoil and diesel products. Also, atmospheric tower condenser limitations often constrain the amount of stripping steam that can be used, so debottlenecking the condenser allows more stripping steam to be used and again recovers more distillates out of the resid. In addition, this system provides better flexibility to keep the crude unit optimised for running variable API feeds depending on loading and turndown. On the debit side, this scheme aggravates the dew and salt point problems in the atmospheric tower, as discussed earlier. One important consideration is that many preflash towers remove the bulk of the light gases from the crude. This again helps the atmospheric tower condenser, as these gases reduce its heat transfer coefficient. The absence of these gases may convert the atmospheric tower condenser from a partial condenser to a total condenser. This necessitates changes to the tower pressure control scheme, and if these are not correctly performed, the atmospheric pressure control may become unstable. Energy savings For refineries where energy savings in the crude unit are a desirable target, it is important to explore how adding crude preflashing devices will affect energy consumption. The crude heater is one of the highest energy consumers in a refinery, and minimising its duty is a good target. A study by Feintuch et al13 demonstrates the importance of taking the preheat train constraints into account when comparing energy usage between preflashing and no preflashing options. In their revamp case, adding a preflash drum with its overhead going to the atmospheric tower flash zone (similar to Figure 1) was a significant energy saver because the lower downstream pressures permitted the reuse of existing exchangers. In that case, replacing the existing exchangers with new ones was too costly to be economical. Another comparison was conducted by Lee.6 In addition to the three cases of no preflash, preflash drum, and preflash tower, he added the semi-preflash tower option in Figure 4. The crude considered was a 60.7º API Eagle Ford crude. www.digitalrefining.com KISTER FLUOR.indd 89 The preflash drum overhead vapours were directed into the atmospheric tower flash zone. Lee’s study was based on the same product yields and the same overhead condenser duty of the atmospheric tower for all cases. Product overlaps were kept identical for all cases. To counter the carrier effect, Lee raised the coil outlet temperatures in the preflash cases. The preflash temperatures were set to comply with the atmospheric tower condenser limitation, varying from 282ºF for the preflash drum to 395ºF for the preflash tower and 353ºF for the semi-flash tower. In addition, Lee’s study adjusted the crude tower pumparound balance for each case to give the same product yield pattern as in the no preflash case. The changes in the pumparound duties were reflected as changes in furnace preheat temperatures. Per our experience, Lee’s comparison has a realistic basis that is reflective of many crude systems. Lee’s study found that the preflash drum (with its overhead entering the flash zone in the atmospheric tower) had little effect on the heater duty energy consumption and did little unloading in the atmospheric tower. The preflash tower reduced the heater duty by 18% compared to the no-preflash case and achieved a very large hydraulic unloading in the atmospheric tower, especially above the kero pumparound. The semi-preflash option gave a 13% reduction in heater duty and intermediate hydraulic unloading. In this semi-preflash option, the hydraulic unloading above the kero pumparound was much less than in the preflash tower option. The energy savings from the addition of a preflash tower depends on the location of the heat transfer surface area, the cut points, the unit constraints, and the preflash scheme. A consensus among several experts7 is that adding a preflash tower may or may not save energy. One thing both the previous studies teach is that it is important to carry out the comparisons on a basis that correctly reflects the specific crude train under consideration and its constraints. A different basis and different ground rules can lead to different conclusions. Each case should be considered on its own merit. Market conditions may also dictate which configuration is better suited for a specific project at a given time. Economics: Preflash drum, tower, or no preflash? The no preflash scheme saves the cost of the drum and piping but raises the cost of the preheat exchangers that would need to be designed for the higher pressure required to keep the feed liquid from flashing upstream of the heater feed control valves. In the revamp of an existing preheat train, being able to reuse existing exchangers and save the cost of new ones may shift the economics in favour of preflashing, as demonstrated in one case.13 The preflash column and semi-preflash options are not much more expensive than the flash drum, provided they make use of the atmospheric tower overhead condenser and reflux drum.⁹ The most expensive is the preflash tower option with its own condenser, reflux drum, and pumps. In a revamp, however, adding the preflash tower with the reflux drum and pumps can be more cost-effective and trouble-free than modifying the atmospheric tower and its overhead system. Further, the bulk of this construction can PTQ Q1 2024 89 08/12/2023 17:25:41 be performed while the crude unit is in operation, reducing the downtime during the turnaround. An optimisation study by Sloley2 concluded that for new units in general, independent preflash towers should be avoided, as building additional capacity in the crude tower and associated equipment lowers Capex and improves yields and heat recovery. In the cases where a preflash may be beneficial in a new unit, the preferred option would be to use a preflash drum. A study by Gomez-Prado et al14 for a grassroots design of a 120,000 BPD North American crude unit supports including a preflash drum. The benefits were more crude preheat, flexibility to process alternative lighter crudes, reduced preheat pressure to allow the use of a 300# flange rating instead of 600#, and reduced operating costs of the hot crude charge pumps. Specifically, they noted that with no preflashing, water entrainment had a high influence on the preheat exchangers’ cost. For example, with a water content of 0.8% LV, the difference due to water in the required pressure rating (preflash vs no preflash) reached about 200 psi vs 100 psi at the typical design point of 0.20.3% LV. As water upsets occur, the exchangers and piping need to be designed to withstand the pressure produced with the higher water content, The cost savings more than paid for the preflash drum and its associated facilities.14 For revamps, the factors that would favour independent preflash towers include:2,7 • Severe capacity constraints in the entire atmospheric crude tower • Strict limits on the duty available in the existing furnace • Strict limit on furnace outlet vapourisation with very light crudes (excessive coking at heater outlet) • Severe limits on the existing overhead system – a preflash tower would add a new overhead system (Figure 3) • Removing the C5 and lighter paraffins reduces asphaltene precipitation and fouling in downstream exchangers. This is far from a comprehensive list, and each case should be considered on its own merit. Sometimes, a preflash device is economically attractive in the least expected circumstances. Waintraub et al15 presented a case in which a preflash drum was attractive for processing a heavy high naphthenic crude (API 16º). With a preheat temperature of 590ºF and 0.6% LV water in the desalted crude, the operating pressure to prevent flashing before the furnace control valves would have been 640 psig. The exchangers would have needed to have special metallurgy to withstand the presence of chlorides in an aqueous phase and naphthenic acids. The cost of preflashing the water and the light ends was much lower. The light ends content was too low to justify a preflash tower, so the economic solution was a preflash drum with its overhead going to the transfer line. Often, there are unique considerations, such as when processing synthetic crudes or bitumen, which are mixed with naphtha diluent to cut viscosities and permit adequate flow, as described in detail by Grande and Gutscher.16 In diluent recovery units (DRUs), preflash drums are often used upstream of the furnace and DRU tower. The large volatility gap between the naphtha and the gasoil seldom justifies a 90 KISTER FLUOR.indd 90 PTQ Q1 2024 preflash tower. In this case, free water is a major issue and can largely raise the pressure requirement for the preheat exchangers and cause damage to the furnace and tower due to rapid vapourisation. To accommodate this, there is an incentive to perform preflashing using two preflash drums at different temperatures.16 The first drum removes most of the free water, and both remove diluent from the feed. Economics for preflash towers need to be examined carefully. It is conceivable that an entire parallel crude unit may be a more cost-effective expansion option. Each case needs to be considered on its own merits, with the broad picture kept in mind. This is illustrated by one of the case studies by Gomez-Prado et al.14 In that case, the preflash tower already existed, and the challenge was optimising the preheat temperature, with a constraint on the preflash tower overhead condenser. While additional preheat reduced the crude furnace duty, it also decreased the yield of the more valuable distillate. A model of the entire refinery was needed to optimise the preflash temperature correctly. Plot space considerations may also play a role in favouring one scheme or another. Reliability and environmental considerations There is one more important reliability consideration favouring preflash towers. Environmental and safety concerns have recently forced refiners to route discharges from small relief valves, previously going into atmospheric drums, back into the process. Desalter relief valves, as well as relief valves from liquid crude-handling circuits, have been routed into the atmospheric tower flash zone. Pockets of water in the reliefs or sitting in the relief valve discharge piping are common. In some instances, these pockets have ended up in the hot flash zone of the atmospheric tower, rapidly vapourising and causing a pressure surge. This can damage several trays in the fractionator, causing yield losses and forcing a premature crude unit shutdown. When a preflash tower exists, these discharges are routed to near the top of the tower, where the temperatures are low enough to tolerate water without pressure surges. Takeaways Preflash drums and towers are invaluable for debottlenecking preheat exchangers, crude heaters, and atmospheric towers, particularly when processing light crudes. Potential penalties are some loss of gasoil or diesel to the atmospheric resid and aggravation of the water dew point and salt point issues near the top of the atmospheric crude tower. To be effective, these devices need to be adequately designed, with special emphasis on containing foam and, in towers, resisting fouling. Regarding their economics, each case needs to be considered on its own merit, with unit constraints taken into account. This article was originally presented at the Distillation Experts Conclave Meeting, Mumbai, India, October 12-13, 2023. This article is dedicated to the legacy of Walter Stupin, an expert, mentor, and friend who contributed so much to advance chemical engineering, distillation, and to help and encourage young engineers. May his memory be blessed. www.digitalrefining.com 08/12/2023 17:25:42 References 1 Barletta T, Hartman E, Leake D J, Foam control in crude units, PTQ, Autumn 2004, p.117. 2 Sloley A W, Atmospheric preflash towers, Proceedings Kister Distillation Symposium, p.63, AIChE Spring Meeting, Austin, Texas, April 26-30, AIChE, 2015. 3 Golden S W, Prevent preflash drum foaming, Hydroc. Proc., May 1997, p.141. 4 Stichlmair J C, Fair J R, Distillation Principles and Practice, Wiley-VCH, NY, 1998, p.76. 5 Ji S, Bagajewicz M Designing crude fractionation units with preflashing or pre-fractionation: energy targeting, Ind. Eng. Chem. Res. 41, 2002, p.3003. 6 Lee, S H, Optimising preflash for light tight oil processing, PTQ, Q3, 2015, p.51. 7 AFPM 2015 Q&A and Technology Forum, Crude/Vacuum Distillation & Coking, Q-61, 2015, p.65. 8 Barber A D, Wijn E F, Foaming in Crude Distillation Units, IChemE Symposium Series, No 56, p3.1/15. 9 Golden S, Crude unit preflash drums and columns, PTQ Revamps & Operations, 2005, p.11. 10 Turner J, Asquith R J, Atkinson R, Stop foaming on hydrotreater ‘hot’ separator, Hydroc. Proc., June 1999, p.119. 11 www.egs-systems.com 12 Blum B, Kister H, Tsang R, Good distributor design for high-velocity feed debottlenecks a crude preflash tower, Hydroc. Proc., June 2021, p.29. 13 Feintuch H M, Peer V, Bucukoglu M Z, A preflash drum can conserve energy in a crude preheat train, Energy Progress, Sept 1985, p.165. 14 Gomez-Prado J, Goodrich R, Hoppens D, Simulating crude units with preflash, PTQ, Q4 2016. 15 Waintraub S, Coutinho R C, Esposito R O, Preflash drum when processing heavy oils: Paradox or reality? in Distillation 2007, Topical Conference Proceedings, p.161, AIChE Spring National Meeting, Houston, Texas, April 22-26, 2007. 16 Grande M, Gutscher M, Designing atmospheric crude distillation for bitumen service, Hydroc. Proc., Feb 2011. Henry Z Kister is a Fluor Senior Fellow and Director of Fractionation Technology. He has more than 35 years of experience in design, troubleshooting, revamping, field consulting, control and start-up of fractionation processes and equipment. He is the author of three books, the distillation equipment chapter in Perry’s Handbook, and more than 150 articles. He has taught the IChemE-sponsored Practical Distillation Technology course more than 550 times in 26 countries. He holds BE and ME degrees from the University of NSW in Australia. Walter J Stupin was an in-house consultant on special technical problems in process engineering for petroleum refining and chemical plants. His more than 50 years of process engineering experience included positions as Executive Director of Process Engineering at Fluor and Vice-President of Technology at C F Braun Inc.. He has published more than 40 technical papers and held BS, MS, and PhD degrees in chemical engineering from the University of Southern California, Los Angeles. Maureen Price has more than 38 years of experience as a chemical engineer, including 31 years with Fluor. She provides expert technical consultation for clean fuels, crude and vacuum revamp, renewable energy, and complex integration projects. She specialises in project definition for new and revamp work at all levels of front-end planning as well as detailed engineering, execution, and construction. She holds a Bachelor of engineering (chemical engineering) degree from California State University, Long Beach, and is a registered Canadian professional engineer in the province of New Brunswick. 50+ VARIABLES in engineering an efficient scrubber/quench system C M Y CM MY CY CMY K Consult with us to improve performance on: > Absorbers > Gas Quench > Gas Wash Systems > Spray Dryers > Injectors > Fuel Burners 140 Years of Designing Spray Based Mass Transfer Technology (800) 777-2926 | [email protected] | www.lechlerusa.com www.digitalrefining.com KISTER FLUOR.indd 91 PTQ Q1 2024 91 13/12/2023 09:48:31 24th Delayed Coking | Fluid Catalytic Cracking | Sulfur Production & Processing REFCOMM 2024 ® Training, Conference & Exhibition April 29 - May 3, 2024 • Galveston, Texas, USA See you in Galveston I picked up a lot of good information. I would definitely encourage those that are interested to participate and not to miss this conference. Gregg Lorimor, Sr. Engineering Specialist, HollyFrontier Tulsa Reasons to attend: Learn from 50+ technical presentation in the multi-track agenda Agenda covers coking, cat cracking, sulfur and SDA Network with a large audience of refiners and technical experts Develop practical solutions for optimising your coking unit with our fundamentals and advanced training courses 642 ATTENDEES 245 COMPANIES 80+ Platinum Sponsors EXHIBITORS 233 Gold Sponsors REFINERS ® *Stats from Galveston 2023 Bronze Sponsors Discover more at: www.refcomm.com refcomm.indd 1 12/12/2023 15:33:56 Technology in Action Hydrogenation technology and catalysts reduce PVC byproducts Approximately 34 million tons of polyvinyl chloride (PVC) are produced annually. A versatile material that is costeffective to produce, it boasts numerous applications: building and construction, packaging, vehicle parts, electronics, medical devices, and more. However, it is also the production where an issue is found. Byproducts of PVC can be toxic, and removing and disposing of them can be costly. These undesired chlorinated byproducts are formed during ethylene dichloride (EDC) cracking to vinyl chloride monomer (VCM) – the raw material for PVC production – and hydrochloric acid (HCI). Specifically, acetylene (C₂H₂) traces are formed and, when returned to the process in the HCI recycling stream, create said byproducts in the oxychlorination reactor. There is good news, however, in the fact that a more economically and environmentally friendly approach to PVC production is possible. Hydrogenation technology Hydrogenation technology presents itself as the solution to this problem. Approximately 860 tons of toxic chlorinated byproducts in a 300 kta production of VCM can be prevented when using this technology. Moreover, when Without (%) With (%) 1,2 Di-trans Hydrogenation unit 0.010 0.002 CCl4 0.101 0.067 1,2 Di-cis 0.012 0.008 1,1,2 Trien 0.035 0.002 Total low boilers 0.158 0.079 Tetrachlorethylene 0.112 0.001 1,1,2,2 Tetrachlorethane 0.130 0.034 Total high boilers 0.242 0.035 Total byproducts 1,2 EDC 860 tons of toxic byproducts avoided 98.669 98.921 ∆ = +0.252 Illustrative calculation for 300 kta VCM unit Figure 1 Calculation for 300 kta VCM unit TIA Q1.indd 93 ∆ = –0.207 ∆ = –0.286 Yield increased by 0.3% www.digitalrefining.com ∆ = –0.079 selective hydrogenation of C₂H₂ to ethylene (C₂H₄) in HCl recycle streams is paired with fixed-bed catalysts throughout the VCM process, undesired byproducts can be avoided, and valuable raw material can be returned to the process. Evonik has been producing hydrogenation catalysts for acetylene-to-ethylene within the HCl recycle stream in VCM plants for the past 40 years. VCM hydrogenation Implementing the hydrogenation unit and avoiding acetylene reaching the oxychlorination reactor prevents chlorinated byproduct formation catalysts are produced by Evonik based on proprietary knowledge. These catalysts are suitable for hydrogenation units as part of fluid-bed and fixed-bed VCM synthesis reactors. The hydrogenation catalysts have been successfully used with the highest performance in all existing VCM process technologies, such as Vinnolit, Oxyvinyls, INEOS, Mitsui, and Solvay. Catalyst tailored to hydrogenation process Developed by Evonik in co-operation with Vinnolit GmbH & Co. KG, the proprietary Noblyst E39 catalysts are a frontrunner in providing catalysts tailored to the hydrogenation process, and were tested and used in Vinnolit’s commercial plants. The series of palladium on silica crystal catalysts were designed specifically for the selective hydrogenation of acetylene-to-ethylene within the VCM production process, improving ethane dichloride selectivity and minimising byproduct formation in the oxychlorination step. Implementing the hydrogenation unit and avoiding acetylene reaching the oxychlorination reactor prevents chlorinated byproduct formation. Acetylene will be chlorinated to low boiling compounds like di or tri chloroethane and high boilers like tetrachloroethane and tetrachloroethene. In addition, the polymerisation of acetylene and ethylene or acetylene and acetylene, including chlorination, can take place, causing chlorinated tar formation. As seen in Figure 1, by reducing the said formation, the quality of EDC increased substantially; the EDC yield also increased by about 0.3%. So, we can conclude that the increased yield can potentially save producers using a hydrogenation reactor a significant amount in operational and capital expenditure costs. Evonik Catalysts Contact: [email protected] PTQ Q1 2024 93 12/12/2023 12:15:51 Worker safety when entering reactors with an inert atmosphere The products from petrochemical processing touch almost every aspect of modern living. The importance of these products to industry and society emphasises the critical nature of facility maintenance and efficient turnarounds that keep production going. The lost revenue and costs associated with shutting down a process for media bed changeouts, preventative maintenance, or repairs are significant. During these outages, every element of the turnaround must be carefully planned and executed efficiently by plant workers to meet tight schedules and get the plant back on-line. As a result, worker safety is always critical, especially when entering the confined space and hazardous environment inside petrochemical reactors. Injury or accidents of a worker can result in significant impact to workers, families, and project schedules. Problem Professional process engineers and managers in the industry are well-trained, knowledgeable, and equipped to comply with safety standards and guidelines from OSHA, API, NFPA, and ASSP/ANSI for continuous worker safety.1-4 They are trained to understand and mitigate the risks to workers and ensure that the processes and protocols in place are carefully followed to guarantee worker safety throughout turnaround activities. Regulatory and industry safety standards for rendering the internal atmosphere of a reactor inert and allowing workers to enter the confined workspace are detailed and complex. After a vessel is purged and flooded with inert gas to mitigate potential explosions, many significant hazards to workers persist, including asphyxiation, working conditions, and changes to the internal atmosphere. Fortunately, several regulatory and recommended safety standards are in place to address and minimise these hazards. Defined as permit-required spaces, OSHA 1910.146, NFPA 350 Standards detail the requirements of the written Permit-Required Confined Space (PRCS) Program that includes area identification and barriers, atmospheric testing, documentation, entry permitting and close-out, emergency retrieval, stand-by personnel, continuous environmental monitoring inside the vessel, vessel purging/ inerting, ventilation, worker breathing equipment, personal protection equipment (PPE), worker communications, lighting, rescue and emergency equipment, and ongoing training. API Recommendation 2217A references the above standards while providing additional details on each aspect, including maintaining the inert atmosphere with nitrogen and the potential hazards of ‘catalyst crusting’, testing, and mitigation. Petrochemical plants are well versed in implementing these programmes and guidelines while ensuring they are followed for the safety of workers on the turnaround team 94 TIA Q1.indd 94 PTQ Q1 2024 and specifically those who will be entering these ‘entry permit required’ spaces to perform maintenance. Challenge Implementation and compliance with regulatory and industry guidelines for entering PRCSs is critical, yet complex and expensive to execute and implement. As such, companies are constantly evaluating their turnaround processes and procedures to determine if any changes can be made to minimise risk to workers and the necessity for implementing these protocols at various stages of the turnaround in fixed-bed reactors. From a regulatory standpoint, anytime workers need to enter a vessel, the protocols for PRCS must be followed. Changing the media when it has reached the end of its useful life, for example, requires that workers enter the vessel to remove the hold-down screens or the manways in top screens to allow access for the media removal equipment. Of course, once the media is removed, the vessel can be ventilated completely to create a safe and stable atmosphere where workers can enter the vessel and perform service or repair to the vessel internals. However, many hazards still exist, and once again the safety protocols and permitting process for entering the confined space must be followed. With an eye on reducing costs, reducing risk to workers, and improving turnaround times, many companies and process engineers have begun to ask how the process for simple media bed changes can be simplified to eliminate the need for a worker to enter the vessel to remove the media. This would help to streamline the initial stage of the turnaround and shorten the overall process. In some cases, companies have already begun to mandate that employees not enter vessels when removing media during a turnaround. These corporate mandates create unique challenges for process engineering teams at the beginning stage of a turnaround. Solution Johnson Screens believes reactor internals can help processors maintain regulatory and corporate policy compliance while enhancing worker safety and has created unique solutions to address these challenges. These innovative new products will be highlighted in future articles. References 1 API (American Petroleum Institute) Recommended Practice 2217A, 5th Edition, July 2017. 2 OSHA (Occupational Safety and Health Association) Standard 1910.146 Permit-Required Confined Spaces. 3 National Fire Protection Association, NFPA 350 – Guide for Safe Confined Space Entry and Work. 4 American Society of Safety Professionals and Approved American National Standard (ASSP/ANSI) Z117.1, 2022, Safety Requirements for Entering Confined Spaces. Johnson Screens Contact: [email protected] www.digitalrefining.com 12/12/2023 12:15:52 THE AGENDA IS HERE! Take a look at the packed agenda for 2024 which will explore cuttingedge decarbonisation strategies and technologies together with the emergence of new industrial clusters driving energy transition. Tuesday, 16th April 2024 Wednesday 17th April 2024 09:00 Arrival, registration & breakfast networking 09:50 Chairperson’s welcome 09:50 Welcome and opening remarks 10:00 10:00 Panel: How (well) are policy and key industry stakeholders working together for a decarbonised future? Panel: Catalysing the decarbonisation of the industrial clusters and hubs 10:45 Coffee break & networking 11:15 Demand for low carbon-materials and implications for the supply chain 11:45 Embracing circularity in the transition away from emissions-intensive energy 10:45 Panel: Policy benchmarking: The global status of decarbonisation policy, strategy, and industry collaboration 11:30 Coffee break & networking 12:00 Mobilising capital and private investment to drive funding for industrial decarbonisation 12:15 12:30 Panel: What do industries need to see in the finance, investment, and policy landscape to move faster? Panel: Gasification - upgrading bottom-of-thebarrel and other low-value streams into usable fuel 13:00 Networking lunch 14:00 Driving sustainability in petrochemicals: Sulzer Chemtech’s innovations in alternative fuels and circular economy 14:30 Realising energy transition - Unleashing the potential of clean hydrogen to hit net zero targets 15:00 Closing keynote: Committing to green electricity 15:30 Conference wrap-up and closing remarks from the Chair 15:45 Coffee break & networking 13:15 Networking lunch 14:15 Development of processes to utilise captured CO2 to manufacture new materials 14:45 Panel: Accelerating the standardization of CCS to improve the technology, cost, scheduling, and safety 15:30 Coffee break & networking 16:00 Case study: Sustainable steel - Ovako’s next frontiers 16:30 Panel: Hydrogen - Potential vs progress in policy, technology and investment 17:15 Day 1 round-up 17:30 Drinks reception & canapes BOOK NOW! decarbonisationtechnologysummit.com Brought to you by: Decard 24 ad 210x297 121223.indd 1 dt summit.indd 1 Platinum Partner: 12/12/2023 14:19 12/12/2023 15:38:30 Pump operating issue case study: Identifying the poor performance root cause Problem An alkylation unit’s main fractionator reboiler pumps were experiencing operational problems. Two 100% pumps were available: one online and one 100% spare P-900/901. A rotating equipment engineer described the problem: When placed online, the P-900 control valve is 70% open at 130,000 BPD flow. Shortly after start-up, the flow starts decreasing, and the control valve opens. It gets to a point where the control valve is wide open, and the flow is still dropping off. When the pumps are switched, the same behaviour is observed. The pump starts up per design, but the flow quickly deteriorates. It was concluded that the pump behaviour was indicative of a net positive suction head (NPSH) issue. It was thought that the net positive suction head available (NPSHa) was lower than the net positive suction head required (NPSHr). A new pump with a lower NPSHr was specified. Analysis A replacement pump was selected with input from the original equipment manufacturer (OEM) and was about to be purchased. Management asked the process engineering group to approve the new pump before the order was placed. In Stratus’ three decades of providing service to the hydrocarbon processing industry, the most common misdiagnosed and undiagnosed engineering issue seen has been hydraulics. Often, this is due to a lack of effective engineering tools, but it can also be due to improper application of available engineering tools. For this problem, the process engineer used Process Engineering ToolS (PETS) software to analyse the proposed replacement pump. Physical properties, hydraulic pressure drop, and NPSH evaluation were performed. The analyses Figure 1 PETS showed no NPSH issue was evident 96 TIA Q1.indd 96 PTQ Q1 2024 Figure 2 The PETS Pipe System Hydraulics Tool modelled the system and checked it at various conditions showed that no pump suction flashing should occur at the operating conditions. No NPSH issue was evident (see Figure 1). The analyses showed that the NPSHa was well above the installed pump’s NPSHr. Additionally, the proposed replacement pump had very similar NPSH requirements to the installed pumps. The Fittings Equivalent Lengths Tool was used to obtain the equivalent lengths for the pump suction and discharge piping. The PETS Pump Curve Tool was used to enter the pump curve data. The control valve datasheet information was entered into the Control Valve Tool. The Pipe System Hydraulics Tool was used to put it all together and model the system (see Figure 2). The model was used to check the system at various conditions. The model showed that the system was process capable, that the existing pump had no NPSH issues, and that there was no flashing in the system. PETS showed the pump operational issues were not due to suction flashing, assuming typical pipe condition. However, the pump’s operational issues were real. What was causing it? The pump was taken apart to investigate. A pump suction witches hat strainer (unknown and with no visible handle) was installed backwards in the system. Debris was found inside the witches hat (see Figure 3). Figure 3 Debris found inside the witches hat www.digitalrefining.com 12/12/2023 12:15:56 Combining Prime-G+ and GT-BTX PluS to upgrade a refinery with crucial operating flexibility The landscape of the petroleum refining industry has undergone a significant transformation in the aftermath of the global pandemic. The volatile and unpredictable nature of market demands post-pandemic has underscored the critical importance of adaptability for refineries. In this rapidly evolving environment, the ability to swiftly adjust production focus to meet changing market requirements has become paramount. The integration of Prime-G+ and GT-BTX PluS technologies offers refineries a unique solution to address these challenges by providing built-in operating flexibility. Figure 4 Debris accumulated inside the backwards witches hat impeded flow into the pump Conclusion Challenges of current refineries Based on the findings, it was concluded that the pumps were starting up fine and after operating a short time the accumulated debris shifted in the inside cone area of the backwards witches hat, impeding flow into the pump. When the pump was stopped, the debris fell to the bottom of the strainer, resulting in a lower pressure drop at start-up but with the debris ready to shift and more fully plug the pump’s inlet the next time the pumps were switched. Equipment performance problems can be difficult to diagnose. A thorough evaluation considering all possible causes is beneficial. Using the right engineering calculation tool, such as Process Engineering ToolS software, to examine the process is imperative to assist in analysis and making correct decisions. In this case, the investigation prevented the replacement of a pump that was designed properly and process capable. Stratus Engineering Contact: [email protected] Modern refineries are divided between those that emphasise fuel production, particularly gasoline, and those that prioritise the maximisation of petrochemicals output. For gasoline-focused refineries, the octane number is a key determinant of profitability, with even marginal improvements translating to substantial gains. In developing countries, refineries are compelled to elevate gasoline specifications to meet Euro-5 standards while simultaneously reducing sulphur levels to <1 ppm. The challenge lies in maintaining octane numbers while achieving such stringent sulphur reduction. Meanwhile, petrochemicalcentric refineries seek efficient ways to convert gasoline into high-value petrochemical products while minimising investments. Combined technology in gasoline mode for gasoline production with max profitability The amalgamation of Prime-G+ and GT-BTX PluS technologies introduces an innovative approach that yields impressive benefits. This combination entails the installation of a new GT-BTX PluS unit alongside an existing Prime-G+ unit Raffinate Extract P A Feed P araffins O lefins N aphthenes Raffinate O Extract S N Extractive distillation column (EDC) Hydrocarbon feed Solvent recovery column (SRC) A romatics S ulphurs Rich solvent TECHTIV® DS Lean solvent Figure 1 GT-BTX PluS simplified process scheme www.digitalrefining.com TIA Q1.indd 97 PTQ Q1 2024 97 12/12/2023 12:16:00 LCN Olefin distribution FCC/RFCC Naphtha SHU MCN 70–150˚C (Olefin-rich) MCN HCN % fraction LCN Hydrogen C6 C5 C7 C8 C9 C10 HCN 150˚C - EP (Olefin-lean) Figure 2 Fractionation of FCC gasoline for the combined technology if present or grassroot of both technologies if there is no FCC gasoline hydrotreating yet. The GT-BTX PluS unit, a cost-effective two-column extractive distillation system, facilitates the extraction of sulphur from the FCC gasoline, preserving olefins in the raffinate stream with less than 10 ppm sulphur. The indicative configuration of the GT-BTX PluS unit is illustrated in the Figure 1. To implement the combined technology, middle cut naphtha (MCN) that contains high-octane olefins and high sulphurs is purposely fractionated after Prime-G+’s selective hydrotreating unit (SHU), leaving light cracked naphtha (LCN) that has high-octane olefins but low sulphurs, and heavy cracked naphtha (HCN) that has low olefin content but high sulphurs. Such fractionation is illustrated in Figure 2. With such fractionation, the high-octane olefin-rich and low-sulphur LCN will be sent to the gasoline pool. The high-olefin and high-sulphur MCN will be processed in the GT-BTX PluS unit, where the sulphur and olefin components will be separated to the extract and raffinate, respectively, as illustrated in Figure 1. At the combined technology’s gasoline mode, the preserved raffinate can be blended into the gasoline pool, contributing to the retention of olefins and octane numbers, even in compliance with Euro-5 ultra-low sulphur standards. Meanwhile, the extract with concentrated sulphurs but nearly no olefins will be combined with HCN to be hydrodesulphurised by Prime-G+’s HDS without worrying olefin saturation. The configuration of this combined technology is shown in Figure 3. Notably, this configuration virtually eliminates octane loss while significantly reducing hydrogen consumption, culminating in a refinery’s peak profitability in Euro-5 gasoline production. Combined technology in petrochemical mode for gasoline-to-petrochemicals The same combined technology of Prime-G+ and GT-BTX PluS unveils an avenue for converting gasoline into valuable petrochemical products. In its petrochemical mode with the same configuration, the GT-BTX PluS extract, a nearly pure aromatic stream with sulphur being the only impurities, undergoes intensified hydrodesulphurisation LCN FCC/RFCC Naphtha SHU P O A S MCN N P Extraction (GT-BTX PluS) Extract Hydrogen O N Raffinate ULS gasoline <10ppm S A S HCN HDS <10ppm S Hydrogen Figure 3 Configuration of the combined Prime-G+ and GT-BTX PluS technology in gasoline mode 98 TIA Q1.indd 98 PTQ Q1 2024 www.digitalrefining.com 12/12/2023 12:16:02 LCN Option of BTX and Propylene production P A FCC/RFCC Naphtha O N S P Extraction (GT-BTX PluS) MCN SHU Recycle to FCC for extra Propylene C6–C8 Extract Hydrogen O N Raffinate ULS gasoline B/T/X/C9A A S Higher severity HDS HCN Hydrogen Diesel LCN Option of only BTX production FCC/RFCC Naphtha SHU P O A S N MCN C6–C8 P Extraction (GT-BTX PluS) Extract Hydrogen O N Raffinate ULS gasoline GT-Aromisation B/T/X/C9A A S Higher severity HDS HCN Hydrogen Diesel Figure 4 Configuration of the combined Prime-G+ and GT-BTX PluS technology in petrochemical mode (HDS) in the Prime-G+unit, culminating in a high-quality petrochemical BTX product (benzene, toluene, xylenes). Furthermore, the olefin-rich non-aromatics raffinate stream derived from GT-BTX PluS proves invaluable for FCC recycling, producing significantly additional propylene and enhancing the FCC propylene yield. Alternatively, if aromatics is the focused product, this raffinate can be routed to a fixed-bed GT-Aromatization unit, coupled optionally with LCN, driving substantial BTX production. Figure 4 shows the mentioned two options of combined technology in the petrochemical mode for converting a significant portion of FCC gasoline into petrochemical products. Operating flexibility of the combined technology The true strength of the Prime-G+ and GT-BTX PluS integration lies in its exceptional operating flexibility. Refineries can seamlessly switch between gasoline-focused and petrochemical-centric modes of operation. This adaptability is crucial as market demands oscillate, necessitating rapid shifts in production focus. By adopting this combined technology, refineries across diverse regions gain the agility to swiftly align their production strategy with prevailing market requirements. www.digitalrefining.com TIA Q1.indd 99 Summary Incorporating the combined Prime-G+ and GT-BTX PluS technologies is a transformative investment for refineries. This single investment affords refineries the dual capability to optimise both gasoline and petrochemical production, irrespective of ever-fluctuating market dynamics. The intrinsic operating flexibility enables refineries to pivot their focus instantly, whether the demand is for gasoline or petrochemicals. In an industry where adaptability is synonymous with success, the Prime-G+ and GT-BTX PluS integration emerges as an indispensable asset for all FCC-equipped refineries. By embracing this technology, refineries can confidently navigate the intricate landscape of post-pandemic refining, reaping significant benefits and securing a competitive edge. GT-Aromatization and GT-BTX PluS are trademarks of Sulzer Chemtech. Prime-G+ is a trademark of Axens. 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