May. 06, 2024
Minerals & Metallurgy
Introduction and Context
Click here to get more.
This short guide provides some practical responses to common questions about hydrotreating and hydrocracking processing units.
The answers provided are based on my extensive experience in the field. They are meant to be informative, though not the sole solutions applicable in every scenario. Differing perspectives are always valued, especially in the downstream industry.
I am an Engineer in a residue hydrotreater unit. As this is a harsh environment (360C+), we regularly experience issues with the feed filter dP and first reactor dP after a few months. Troubleshooting has already been done on feed composition and unit conditions.
The query involves the feed tanks upstream from the unit. With water and sediments present in the feed (from ADU), these should settle in the tank sump and be drained before the tank feeds the hydrotreater. My rough estimation using Stokes' law, tank height, water, and feed properties shows that water would need roughly 24h to settle to the tank bottom. Is this approach correct? How to deal with sediments?
The tanks are old and were previously used in VGO service. Recent inspections did not reveal internal corrosion. However, with residue services, the SpGr is closer to water, so settling takes more time.
We also fear that some of the tank sump may plug the reactor catalyst, contributing to the dP increase, despite using an automatic BW filter. Any feedback is appreciated.
I would suggest a two-fold approach:
1 - Concerning the Tank and Feedstock filter: Was the tank cleaned before the change of service? Chemical incompatibility between residue and VGO could lead to asphaltenic compound precipitation, blocking downstream filters. Ensure backup tanks for periodic cleaning (maybe once a year). Automatic backwash systems for feedstock filters are crucial for maintaining an adequate lifecycle.
2 - Regarding Hydrotreating Reactors: Ensure proper catalyst grading if the feedstock is adequately characterized. The right catalyst grading, including the use of contaminant traps, can minimize pressure drops in the catalyst bed during operational campaigns, particularly in residue hydrotreaters operating under high severity and with high contaminant content.
What is the importance of analyzing basic nitrogen and non-basic nitrogen in Hydrotreater and Hydrocracking feeds? How do they affect the process and catalysts?
Nitrogen compounds, particularly basic nitrogen, are known inhibitors of hydrotreating catalysts. While basic nitrogen compounds primarily concern catalyst activity, non-basic nitrogen compounds can also inhibit hydrotreating processes, affecting hydrodesulfurization performance by competitive adsorption on catalyst active sites. Given their chemical stability, nitrogen compounds are typically hard to hydro-treat. Controlling nitrogen content using adequate catalyst grading and contaminant traps is essential in residue hydrotreating/hydrocracking units. In fixed-bed Types of Seamless Carbon Steel Pipes hydrocracking units operating with high nitrogen content feeds, a hydrotreating section is often used upstream to protect the costly hydrocracking catalyst, supplemented by separation vessels to reduce nitrogen concentration.
What is the purpose of Multi-catalyst Bed philosophy in hydrotreating of Diesel and Vacuum gas oil cuts? How does the reaction proceed across different catalyst beds, and what controls these reaction phases?
The Multi-catalyst bed philosophy in hydrotreating units ensures optimized processing by creating volume swell in the reactor. Typically, guard beds at the top control contaminant concentration using macro-porous catalysts that trap fouling agents like corrosion products and metals. Following layers maximize hydrogen uptake, with HDS and polyaromatic hydrogenation reactions occurring below the guard bed. Subsequent zones promote HDN and monoaromatic saturation reactions, with further hydrogenation reactions taking place as nitrogen content decreases. Reaction percentages (HDS/HDN/HDA) depend on unit characteristics like hydrogen pressure, temperature, quench strategy, catalyst properties, and feedstock characteristics.
What causes coking on Diesel and Vacuum gas Oil hydrotreating catalysts when treating cracked and straight-run feeds?
Coking in hydrotreating units generally results from cracking and dehydrogenation reactions in catalyst beds, favored by high temperature and feedstock quality. Units processing heavier feeds with high olefinic, polyaromatic, and asphaltenic compound concentrations typically exhibit higher coke laydown rates. Operating under high hydrogen excess helps overcome hydrogen diffusion limitations. Since hydrogenation reactions are exothermic, temperatures rise in catalyst beds, favoring cracking and additional side reactions like dehydrogenation, leading to coking. Proper design and operation of quench and temperature control systems are crucial for processing unstable feeds (cracked feeds and residue) to ensure adequate catalyst bed temperature control.
What is the importance of analyzing wt % H2 content in Vacuum gas oil feed and product?
Hydrogen content in Vacuum Gas Oil (VGO) is a crucial characterization factor for determining its crackability as an FCC feed. VGOs with high crackability typically exhibit high paraffin and hydrogen content, while refractory VGOs show lower hydrogen content, indicating high aromatic compound concentration. Hydrogen content helps estimate FCC product yield; higher hydrogen content in FCC feedstock results in more distributable hydrogen in FCC products, enhancing molecular value. Residue upgrading technologies aim to improve the H/C ratio in hydrocarbon molecules, achieved either through carbon rejection (e.g., Delayed Coking, Solvent Deasphalting) or hydrogen addition (e.g., residue hydrotreaters, hydrocrackers). Minimum hydrogen content in VGO ensures FCC units' performance, as low hydrogen content feedstocks reduce crackability, potentially increasing low-value product yields and coke deposition over FCC catalysts, causing high temperatures in FCC units. Therefore, cracked feed side effects (e.g., Coker Gas Oil) and its lower hydrogen content should be considered in FCC performance evaluations. Increasing VGO hydrogen content raises product hydrogen content, enhancing crackability and FCC feed performance, though process objectives should always be considered.
Our Diesel Hydrotreater feed has CCR 0.01 wt ppm and Total Aromatics of 31.5%. Given such low CCR values indicating low coke formation tendencies, what causes coking on diesel hydrotreating catalysts? Our Vacuum gas oil hydrotreater feed contains CCR 0.85% and Asphaltene <300ppm, and product CCR is <500ppm. Does CCR reduction in VGO hydrotreater occur via coke formation on catalysts, or is there another mechanism?
Despite the low CCR of the feed, coking in hydrotreating catalytic beds depends on several factors. Aromatics in the diesel hydrotreating feed can produce high coke laydown rates on catalysts. Ensuring adequate reactor hydrogen partial pressure and appropriate interbed quench strategy is crucial to prevent hot points in catalyst beds, which favor cracking and dehydrogenation reactions leading to coke deposition. In VGO hydrotreaters, reducing asphaltenes via feedstream blending with lighter streams can help, though chemical compatibility studies are essential to avoid asphaltenes precipitation. Proper operational conditions like hydrogen partial pressure, temperature, and interbed quench strategy ensure optimal hydrotreating unit performance.
What is the importance of maintaining a specific operating temperature range for the Hot HP separator in hydrotreating units? What is the relation between H2 gas and salt solubility (e.g., Ammonium Bisulfide and Ammonium Chloride) with the temperature of the gas/liquid mixture upstream of the Hot HP separator?
Maintaining appropriate operating temperatures in hydrotreating units, particularly those processing heavier feeds with high contaminant content (e.g., sulfur, nitrogen), is crucial to prevent ammonium salts’ deposition, corrosion, and subsequent unit lifespan reduction or accidents. Lighter feed units like naphtha present different separation needs due to hydrotreated stream properties. In heavier feeds like Light Cycle Oil (LCO) and Gasoils, both High Pressure (HP) and Low Pressure (LP) separation vessels are necessary due to closer physical properties to water, requiring larger interface areas for separation. Temperature ranges aim to prevent ammonium salts’ deposition, typically controlled through water injection post-reaction section above salt precipitation temperature, crucial for high chloride content feed units.
Our Vacuum gas oil hydrotreater feed blend includes Light Vacuum Gas Oil, Heavy Vacuum Gas Oil from VDU, and Heavy Coker Gas Oil from Delayed Coker unit. Post-hydrotreatment, we draw Diesel and Naphtha from the fractionation column. Since the feed doesn’t contain Naphtha and Diesel cuts, and we are using a hydrotreater rather than a hydrocracker, how is Naphtha and Diesel generation in the fractionation column occurring? Is it purely by thermal cracking at hydrotreater conditions?
Despite being a Residue Hydrotreater, cracking reactions can occur under specific conditions. High temperature operational conditions in residue hydrotreaters can favor thermal cracking reactions, especially towards the end of operational campaigns. Conversion rates of 10-20% for hydrotreaters are common, while mild hydrocrackers range from 20-50%, and severe hydrocrackers exceed 50%. Reviewing operational unit severity (temperature, interbed quench strategy) is advisable to identify conditions favoring thermal cracking.
In Diesel Hydrotreaters, what factors determine using Hot HP Separator/Cold HP Separator/Cold LP Separator configurations, or combinations thereof?
Hydrotreating units processing lighter feeds like naphtha may use single separation vessels due to different physical properties from water. Heavier feeds like LCO and Gas oils necessitate two separating vessels for more complex separations. Typical configurations include High Pressure (HP) and Low Pressure (LP) separators to manage hydrotreated streams with water-like properties. The choice between Hot HP Separator (HHPS), Cold HP Separator (CHPS), and Cold LP Separator (CLPS) often hinges on energy consumption analysis. HHPS configurations save energy by feeding the hydrotreated stream to the stripping section without reheating, reducing air-cooler system dimensions, and minimizing noble metallurgy use. CHPS, offering lower contaminants in recycle gas, can maintain hydrotreating reaction performance despite higher make-up hydrogen consumption.
In Hydrotreaters, Naphtha Hydrotreater units use a simple steam reboiler at the bottom of the stripper, while Diesel and Vacuum Gas Oil hydrotreaters use direct steam injection. Why can’t reboiler systems be used in Diesel and VGO hydrotreaters strippers instead of direct steam injection?
Reboiler systems face heat charge limitations due to thermodynamic and heat transfer restrictions, limiting maximum temperatures. Therefore, reboilers suit lighter products like naphtha, while heavier derivatives like diesel and VGO benefit from direct steam injection, providing higher temperatures and reducing hydrocarbons' partial pressure, enhancing stripping performance. The choice also considers water content tolerance in final hydrotreated products, with reboilers preferred in processes like naphtha hydrotreating where downstream units handle lower water content. Live steam injection generates sour water, typically chosen for heavier streams due to associated costs and operational considerations.
Why does our Material Balance show higher H2 dissolution in Hot HP Separator (HHPS) liquid than Cold HP Separator (CHPS) liquid, despite higher temperature in HHPS and marginally higher pressure compared to CHPS? Additionally, why does Diesel Hydrotreater HHPS have higher H2 dissolution than VGO Hydrotreater HHPS, despite lower pressure and temperature at Diesel Hydrotreater HHPS?
Hydrogen solubility increases with temperature and pressure, explaining higher H2 dissolution in HHPS liquids. Regarding Diesel and VGO Hydrotreaters, hydrogen solubility is higher in lighter hydrocarbons like diesel compared to VGO, as heavier hydrocarbons with high aromatics and heteroatoms reduce hydrogen solubility.
What is the main role of the support material in hydrotreater catalysts like CoMo/NiMo? Does it participate in hydrogenation reactions for HDS/HDN/HDA? Hydrotreater catalysts are sometimes described as acidic and sometimes as neutral. Which is true? Is catalyst acidity due to catalyst material or support material?
Support materials in hydrotreater catalysts provide mechanical resistance, high surface area for active phase distribution, and control catalyst acidity, desired to be low in hydrotreating units. Supports generally don't participate in hydrogenation reactions, carried out at metal sites. Supports ensure proper pore distribution, minimizing catalyst plugging from coke or metals deposition, which is crucial for residue hydrotreating units. In severe services, hydrocracking catalysts exhibit both acidic and hydrogenation properties. They may be amorphous (alumina, silica-alumina) and crystalline (zeolites) with bifunctional characteristics for simultaneous cracking (acid sites) and hydrogenation (metal sites) reactions. Common active metals include Ni, Co, Mo, and W, often combined with noble metals like Pt and Pd. Efficient hydrocracking requires catalyst and hydrogen synergy, balancing exothermic hydrogenation and endothermic cracking reactions under high hydrogen partial pressures, with temperature control achieved via cold hydrogen injection between catalytic beds. Acidic support materials like amorphous silica-alumina (ASA) and zeolites facilitate cracking while metal sites handle Characteristics of Titanium | Titanium | Products hydrogenation reactions.
For Diesel hydrotreaters, how do you choose between only CoMo, only NiMo, and a combination of NiMo/CoMo catalysts? Why is it said that NiMo catalysts consume more H2 than CoMo catalysts?
Catalyst grading in diesel hydrotreaters relies on feed stream quality, especially contaminants like sulfur and nitrogen, and cracked stream participation. High contaminant feeds use catalyst grading with more active catalysts like NiMo over alumina. CoMo catalysts improve sulfur removal and olefins saturation, while NiMo catalysts promote nitrogen removal and aromatics saturation, crucial for feeds with high contaminants like elements in 10 Questions You Should to Know about titanium sheet. Typically, catalyst beds start with guard beds against contaminants like metals, followed by NiMo and CoMo blends, ending with NiMo for hydrodenitrogenation and high-dehydrogenation performance CoMo. Higher hydrogen consumption of NiMo catalysts relates to their higher chemical activity for treating nitrogen and refractory contaminants.
What is the difference between Type 1, Type 2, Brim, and Hybrim catalysts? What are Direct and Indirect desulfurization routes in HDS reactions in hydrotreaters, and what affects these pathways? What is the relationship between catalyst selection and HDS route preference, and how does it impact final product specifications?
The catalyst classification relates to Mo-S2 structures in hydrotreating catalysts. Type I structures involve strong interactions between the active phase and carrier (e.g., Mo and support oxygen), raising desulfurization reaction energy. Type II structures feature weak active phase-carrier interactions, offering higher catalytic activity. BRIM catalysts, introduced by Haldor Topsoe in 2003, and improved HyBRIM catalysts feature increased active phase dispersion and optimized interaction for higher performance. Direct desulfurization treats whole atmospheric residue with hydrodesulfurization, while indirect desulfurization separates heavier fractions from the residue (e.g., vacuum distillation, carbon rejection) to indirectly reduce sulfur content in lighter fractions. Catalyst choice and sulfur compound nature significantly affect HDS reaction routes and product specifications.
What distinguishes direct and indirect desulfurization routes in heavy oil hydrotreaters for HDS reactions? Does catalyst type (NiMo/CoMo) or sulfur molecule nature determine the H
Previous: Types of Seamless Carbon Steel Pipes
Next: Which applications benefit from tungsten carbide buttons?
If you are interested in sending in a Guest Blogger Submission,welcome to write for us!
All Comments ( 0 )