What process and operational areas have refiners demonstrated a positive ROI in the application of artificial intelligence and machine learning strategies?

I would like to know which are de main strategies (related to WABT of the beds) for operating an hydrocracker unit in order to minimize the catalyst deactivation and extend as much as possible the catalyst life. The unit has three beds: the first one with pretreating catalysts, the second one half preatrating half hydrocracking catalysts and the last one with 2/3 of hydrocracking catalyst and the other 1/3 with isodewaxing catalyst. There are 2 quenches between bed 1 & 2 and bed 2 & 3.

How can I calculate the salt point in an atmospheric crude distillation tower to avoid the precipitation of salts, what literature recommends.

(Cómo puedo calcular el punto de sal en una torre de destilación atmosférica de crudo para evitar la precipitación de las sales, que literaturas recomiendan)

In our vacuum distillation unit, in HVGO section temperature difference between vapors entering into the bed from below and temperature in the bed has come down to less than 10 degc from almost 50 degc after unit emergency shutdown. This has lead to high temperature across bed 1-3. What could be possible reason for this and what are potential impact of this column yield pattern? And what are the remedial measures for controlling this without going for any shutdown?

Are there any chemicals being used for increasing the Coker furnace run length. If yes, what are the pros and cons on usage of these chemicals. How much was the furnace run length increased?

Fluid Catalytic Cracking (FCC), Flue Gas Scrubber SO3 break through. We are facing with Wet Gas Scrubber (FGSU) outlet stack dense plume issue. It is taking longer to disperse and getting landed in nearby area causing eye irritations. As per licensor, this dense plume is due to SO3 breakthrough. Stack outlet analyzer only measures SO2 and and values are within limit. These phenomena happening during Heavy Sulphur feed processing and issue gets aggravated during winter season. We tried to limit the excess Oxygen in flue gas. Also maximized the circulating water. But no noticeable changes occurred Is any refinery facing the same issue and what are the troubleshooting activities have been carried out to resolve this issue? Will SO2 breakthrough occurs first before SO3, which not happening in this case? Flue gas composition: SO2, SO3, CO2, O2, N2.

What FCC and hydrotreater modifications are needed to increase refinery coprocessing of renewable feedstocks?

How can the FCC unit be upgraded to benefit petrochemical integration?

What type of flexibility can be built into a hydrocracker to quickly shift from naphtha to diesel output?

What are the optimal pathways towards increasing naphtha and LPG production (for petrochemical feedstocks)?

Why it is recommended to shutdown a hydrocraker / hydroprocessing unit if the system pressure goes below 80% of operating pressure? (Other than the issue of potential coking)

How to decide the turndown of plant during design phase?

Is there any dependence on the temperature of diesel fuel for separating water when supplying it to the park for storage. That is, for example, when separating fuel and water, for example in an electric dehydrator, how does the temperature of the incoming diesel fuel affect it?

In our Vacuum Unit we have 2 Identical Trains, Train -1 constructed in 1984 and 2 constructed in 1989. Our Vacuum system is Wet Vacuum with 2 Pre- Condensers in parallel and 3 Stage Ejector system, each having 3 no. of Vacuum Ejectors, with Condenser, with the cooling medium being Sea Water and the Sea Water entry is to the Pre-Condensers and it's return going to the other 3 Stage condensers simultaneously and also provided with a By-Pass to increase the flow to those condensers if and when required. Actually in the middle of May 2023, we experienced sudden break in vacuum in only Train - 1 and this phenomenon was continuing on & off, with this phenomenon occurring every 7-10 days and would resolve by switching the Ejectors and /or hammering the Pre-Condensers leg lines, till our Scheduled Biennial Turnaround in October 2023. And after Start-up of the unit on October 31, 2023, till December 30/31 2023 for about a couple of months the unit was running very smoothly, before the vacuum issue started cropping up again and this time the frequency of the drop/break in Vacuum was about 10-15 days, continuing upto March 2024. But, our Operation personnel thought this is due to the Pre-condensers leg line getting blocked due to Metal rust & corrosion and instructed to externally Hammer those leg lines twice in every shift from February upto Middle of March 2024., and by that that issue also resolved. And for a period of more than 6 months upto 2024 October first week, we did not face any issue except little increase in Vacuum twice or thrice when sea water flow was getting dropped, or more lighter in feed from Tankfarm. Also, as compared to the other Train, we were having 2 ejectors more online i.e.., 6 Ejectors with 2 each in all the 3 stages. But again we faced sudden break in Vacuum itself on October 5th at around 04:00 hrs, even with unit running on extremely low Throughput. So, I kindly request you to help with this issue. Note:- As per my observation, I have noticed 2 separate phenomenon happening with none being related to each other or happening together even once. 1. Pre-Condensers leg line temperatures getting low 2. 3rd Stage Condenser outlet temperature getting high which in turn increases the pressure of the non-condensible from the Hotwell increasing the back-pressure of the system irrespective of burning in our Heater or flaring it.

Currently, the refinery is processing crude oil with a high H2S content. How can this affect the distillation unit? Would it affect the cap and transfer lines? What do you recommend I apply?

We have a new hydrogen production unit designed by Haldor topsoe. The outside temperature of reformer skin exceeds 350c in some point especially in locations close to burners. The contractor cool it down by directing low pressure steam to the outside surface by flexible hoses. Here I have two questions:

1: Is it normal to have such a high temperature at the outside while it is designed based on Euro 5.

2: Is it accepted to cool it down using LPS? Will that damage the iron structure or not?

What’s the difference between the filming amine and corrosion inhibitors? Can we use corrosion inhibitors as a filming amine?

If anyone could help me in calculating Vapour Pressure of heavy hydrocarbon products such as fuel oil, base oil, vacuum residue etc... by any means of other physical properties like flash point, density, viscosity, etc..., I would be highly appreciated. That's for pump performance calculations!

What is needed to significantly increase production of bio-LPG, renewable marine diesel, and bio-aromatic hydrocarbons like BTX?

Integrated refinery and cracker plant, processing Naphtha, Ethane, Propane, LPG as feed, experiencing high Vinyl Acetylene in their Mixed C4 feed. Severity controlled, however, VA concentration is very high. We are interested in understanding the likely reasons for high Vinyl Acetylene formation? What are the parameter need to be checked to control Vinyl Acetylene concentration? What parameters should be monitored to maximize the throughput of the butadiene unit while limiting Vinyl Acetylene contamination?

Q1. I would like to understand the importance of Diesel feed introduction at 180degC as feed in VGO hydrotreating units before VGO gets replaced with diesel at 260-280degC?

Q2. What is the issue if VGO feed is introduced directly to the VGO hydrotreating reactor at 180degC?

Q3. Where does congealing in VGO units occur and why? It is often seen cold Straight VGO coming from storage tanks maintained at 80 degC flowing freely?

Q1. In Hydrotreating units(Diesel and VGO), why is that Feed introduction is not allowed above 200degC?

Q2. During Normal startup post maintanence work, having H2S in HP loop above 1000ppm, why feed introduction is done at 180degC only, what would be the issue if feed introduction is done at 230 or 240degC and why it is not generally not recommended?

I am facing a problem in vibration of control valve controlling atmospheric residue at 10 bar pressure,175 'C temperature and 620-630 m3/hr flow. Instrument team dropped the valve and found internals parts damaged and they explained that the reason of damaging the valve internals due to low opening of 15-16%.

The attended and fixed the valve but same vibrations still coming.

Can anyone explain the exact reason and solution for this?

How can hydroprocessing operators better manage the high heat release during O2 and olefin hydrogenation (for example, when processing lipid feeds)?

Why are some of the world’s best refineries more efficient than some of the world’s newest refineries?