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For Diesel hydrotreaters. How to finalize the catalyst from only CoMo & only NiMo and combination of NiMo/CoMo? Why is it said to be that NiMo catalyst consumes more H2 than CoMo catalyst?
Replies: 1
What are water partial pressure & chloride partial pressure in the fixed bed catalyst of Naphtha Reforming Unit ? And how can be controlled ?
What is the best MOC for the NMP recovery and Dehydration portions of a Solvent Extraction System? We are finding that acid in the feed oil concentrates in the recirculating NMP and that this is degrading the 304SS process vessels. Is 316SS a good choice or will we need to go to more exotic alloys? The recirculating NMP can hit a pH of 4.0 and sometimes down to 3.7.
What's the philosophy of desalting system in Crude Distillation Unit, with respect to High Voltage & Demulsifier?
Replies: 2
What is the main role of support material of the hydrotreater catalyst CoMo/NiMo? Does Support material participate in the hydrogenation reactions for HDS/HDN/HDA?
Hydrotreater catalyst at times said to be acidic and at times to be neutral as per the documents, which is true? Acidic nature for the catalyst is due to catalyst material or due to support material? Kindly guide.
What are the other methods to reduce feed foaming in DCU reactor, apart from the use of anti-foaming agents, increasing pressure and temperature?
How does quantity of HP steam (34kgf/cm2) to strippers of hydrotreaters (10-11kgf/cm2g) for removal of H2S is finalized? What is the basis for it?
1. In any Hydrotreater unit, it is observed from our Material Balance sheets, that H2 dissolution is more in Hot HP Separator liquid than in Cold HP Separator liquid, even though the temperature is high in HHPS with marginal high pressure on the vessel compared to CHPS? Why is it so?
2. It is observed that Diesel Hydrotreater HHPS H2 dissolution is found to be on higher side compared to VGO Hydrotreater HHPS H2 dissolution, even though both pressure and temperature at HHPS of Diesel hydrotreater is less than VGO hydrotreater? Why is it so?
In Hydrotreaters for Stripping of H2S from Hydrocarbon stream, Naphtha Hydrotreater unit uses simple steam reboiler at the bottom of the stripper, whereas Diesel and Vacuum Gas Oil hydrotreaters uses direct steam injection in strippers. why? Why can't we use reboiler system in Diesel and Vacuum gas Oil hydrotreaters strippers instead of direct steam injection?
In our Hydrogen plant designed by KT, we have 2 steam drums and during every start up, we face severe hammering in both steam drums intially. I worked before in other Hydrogen plants and have never experienced such hammering?
Replies: 0
I am currently working on a project about chlorination processes and mechanisms. One day I was reading about direct chlorination of ethylene through the process called "Low Temperature Direct Chlorination" which was developed by Vinnolit. There is no more information about the catalyst, or newest technological development of the said company. The patent (US20170267610A1) describes the newer process and its ingenious configuration. "Low Temperature Direct Chlorination" astonishes me and I'd like to learn more about it.
Since all of the EDC producers in my country are high temperatures, I was wondering if someone could inform me about the catalyst of this process, or the mechanism of such a catalyst in commercial applications or promising articles about it.
In Diesel Hydrotreater, what factors decides to go with Hot HP Separator / Cold HP Separator / Cold LP Separtor configuration or only CHPS/CLPS configuration or only CHPS configuration?
Our Vacuum gas oil hydrotreater feed blend has got three feeds, Light Vacuum Gas Oil/Heavy Vacuum gas oil from VDU & Heavy Coker gas oil from Delayed coker unit (Blend distillation IBP to FBP in the range of 260 to 600 degC and specifically Temperature to distill 5% volume is approx at 350degC). After hydrotreating, in the fractionation column we draw Diesel and Naphtha. As the feed doesn't contain Naphtha and Diesel cuts specifically & being hydrotreater but not hydrocracker, how does generation of Naphtha and Diesel in the fractionation column is happening (Both product streams combined Approx 14%)? Is it purely by thermal cracking at the hydrotreater conditions of Vacuum Gas Oil? How should I understand this?
Importance of maintaining specific range of temperature to Hot HP separator in hydrotreating units?
Relation of H2 gas and salts ie: Ammonium Bisulfide and Ammonium chloride solubility with temperature of the gas/liquid mixture upstream of Hot HP separator?
Our Diesel Hydrotreater feed is containing CCR 0.01wtppm and Total Aromatics of 31.5%, if CCR of feed is in such low values, indicating coke forming tendencies of feed is very low, then what causes coking on diesel hydrotreating catalysts?
Our Vaccum gas oil hydrotreater feed contains CCR 0.85% and Asphaltenes <300ppm and product CCR is <500ppm. The route for reduction of CCR in VGO hydrotreater is by formation of coke on catalysts or is there any other mechanism of reduction of CCR without coke formation?
What is the meaning and importance of analyzing wt% H2 content in Vacuum gas oil feed and product?
Our VGO hydrotreater product specification is said to have min 1.0% Delta hydrogen content w.r.t feed design value of 11.8wt%. If feed wt% H2 content is more than feed design value, will it make any difference to VGO product %wt H2 content?
What exactly causes coking on Diesel and Vaccum gas Oil hydrotreating catalysts (treating Crack and Straight run feeds)?
Spent caustic after treating LPG in Continuous film contractor is regenerated in oxidizer column using process air and heat followed by removal of disulphide oil with solvent hydrotreated Naphtha. Offgas generated in oxidizer column are burnt in heater. From Past few year, problem of chocking in overhead line of oxidizer column is found which is disturbing overall regeneration process. However, replacement of overhead line was carried out for one time, but after 1-1.5 years, same chocking problem is occuring. Any observation or experience regarding situation and troubleshooting to control and mitigate?
What is the purpose of Multi-catalyst Bed philosphy in hydrotreating of Diesel and Vaccum gas oil cuts?
Besides this, for Multi - Catalyst bed configuration, some x or y % of HDS / HDN / HDA happens in each bed, before getting admitted into next catalyst bed. How and who (factors) controls that x or y%?
A wider range of feedstocks are considered for refinery processing, including bio-based feedstocks and polymeric compounds from waste plastics. Are there new types of corrosion control chemistries that can help prevent corrosion and fouling of process assets from feedstocks with harmful components (such as high TAN, chlorides)?
Replies: 3
Pyrolysis-based technology can convert plastics-rich refuse-derived fuel into extractor-ready BTX product, but the substantial energy input and processing challenges compel the petrochemical industry to consider waste gasification alternatives. How do you see this evolving?
Replies: 7
Increasing hydrocracker reactor heater temperature is a typical strategy when upgrading heavy feedstocks but should be balanced against higher energy costs and emissions considerations. Further complicating matters is fouling and corrosion of hydrocracker unit heat exchangers by unconverted oils (UCOs). What trends do you see in resolving increased fouling from UCOs?
Replies: 6
Considering the enormous amounts of thermal energy and stripping steam required for crude distillation unit (CDU) throughputs, are there any new crude oil processing schemes for reducing CDU operating costs?
In view of the recent wave of refinery closures, including five in the US during 2021 and other closings, what technologies and market strategies are emerging to keep plants operating?
Replies: 5
What is the importance of analyzing basic nitrogen and non basic nitrogen in Hydrotreater and Hydrocracking feeds. How does they affects the process and catalysts?
1) Increasing of the water content (H2O) of the Heavy Naphtha in the Storage Tanks .. and the moisture in the Recycle Gas . What are the causes??
2) If the required concentration of chlorine (Cl) in the feed is (2 ppm). Provided that: Unit capacity (Reforming Unit) = 40 m³/hr (Density of Heavy Naphtha= 0.742 gm/cc ; Density of PDC (Propelene Dichloride C3H5Cl2) added = 1.15 gm/cc )
So, what's the amount of PDC to be added so that we obtain the above concentration (2 ppm)??
At one of our gas processing plants, we are using hybrid amine solution MDEA for acid gas recovery. H2S 3% and CO2 1%. Our filter replacement frequency is very high, observed corrosion, sample analysis reflects, Iron count 14ppm. Other results are high acetates 13000 ppm in amine, PH reducing trend ...HSAS 1.5%. There is no any chemical injected on wellsite. What could be cause of corrosion /filter change out? What could be other source for acetates as production chemicals are not used on wellsite?
Replies: 4
In Crude Distillation Unit CDU, we inject caustic soda (NaOH) for treating salts in crude oil (<= 20ppm ), but if the concentration of the salt in crude became too high (e.g 40ppm), desalter (desalting system) is required for that. The query is, if the desalter is out of service, what procedures are to be taken for treating salts? And what are the disadvantages of increasing the injection of caustic soda (NaOH)?
A water sample from KO drum (downstream to HP absorber at sweating unit) is black in colour, rotten smelling, pH = 10, Fe = 4 mg/l... MDEA used for sweating, CO2 at feed gas about 3.5%, H2S nil. What is the reason for the black colour and rise in pH?
What is source of organic chlorides in crudes? why some crudes report organic chlorides while others not?
What happens if during the catalyst sulfidation, Hydrogen flow is much higher than the target value?
Why sulphiding of Diesel and Vaccum gas oil hydrotreaters catalyst sulphiding is done in 2 stages, one at 225degC for a break through of 3000ppm H2S and other at 330degC for a break through of 1.5-2%?
I am Engineer in a residue hydrotreater unit. As this is severe service (360C+), we often see upsets in the feed filter dP and the first reactor dP increases after a few months. Troubleshooting already done on feed composition, unit conditions.
The question concerns the feed tanks upstream the unit. For as there is water and sediments in the feed (from ADU), that should settle into the tank sump and be drained before the tank is lined up to feed the hydrotreater. I did rough estimation via Stokes law and involving the tank height, water and feed SpGr, viscosity @ T, etc...
It shows that water would need roughly 24h to settle to the tank bottom. 1) Is this approach correct? 2) How to do this concerning sediments? 3) The tanks are old, have been in VGO service before. Last inspections did not reveil any internal corrosion. Now with residue service, SpGr became closer to water, so settling of water would take more time. I scare the tanks are not adequate for this new service.
We also think that even having an automatic BW filter, some of the tank sump comes to plug the reactor catalyst leading at least partly (the rest is coke) to the dP.
Thank you in advance for any feedback on this.
