Regional shifts in higher refinery capacity seem to correspond with the need for more intensive water treatment programmes involving wastewater recycle processes while protecting heat exchangers and linked assets from fouling and corrosion. At what level of investment have you seen refinery operators commit to plant water quality while reducing its consumption?

Please share any references which provides the guidelines regarding process variable alarm value for H HH L LL specifically to pressure and temperature.

At DHT RX Eff/ Separator Liquid exchange train got leaked once and we plan to install pressure transmitter on sep liquid side to detect any leakage.

Our desalter is facing a rag layer issue when we process cabinda crude. The brine turns black. It seems like our current emulsion breaker can not solve this problem. Is there any ideas or recommendations?

Can we add valave Before Flash zone in CDU, to use it when we have a maintenance on the heater without the need to empty the tower?

What are the optimal routes to valorisation of olefins-rich FCC unit and coker unit off-gas?

We faced problem in the particulate contamination specification of jet fuel product in the two tanks , and from our survey the specification from the unit of hydrobon unit is ok ,on the other hand in the refinery we refine sweet crude with API 42 and we got this problem for first time, in your view can you advice me?

What are types of Corrosion Inhibitor (Filmer) and neutralizing amine used in crude distillation units. What is the philosophy of their work and the concentration of injection?

How can I know the water mole fraction in the overhead stream in the CDU? I need it to know the optimum temperature of the top reflexes.

For a desalter system with low performance, we made an RCA that revealed multiple issues to the desalter hardware, including that the equipment is undersized and electro-coalescne not happening, while grid is still ON. Could anybody advise equipment retrofitters to shift the existing desalter almost electrodynamic type to low velocity type ?

We have low PH (3 to 4) in the CDU overhead but in same time we have low chloride values ( 3 to 10 ) and already we injected high values of neutralizing amine and corrosion inhibiter. What is the reason that causes this drop in PH value?

I would like to learn about the usage of Pyrolysis oil produced from Ethylene Cracker in the Delayed Coker Unit. I would like to use this pyrolysis oil which is around 2.5 wt% of total feed as a feed in the Delayed Coker Unit. Do you know any applications like this? If it is, have you encountered any issue to process pyrolysis oil to the coker unit?

In addition, what if I use this pyrolysis oil as wash oil stream in the coker fractionator column instead of using as a feed? Do you know any applications or example?

Can high-grade needle coke (such as P66 or Seadrift) be used for synthetic graphite in EV battery anode materials? If the quality exceeds specifications and needs to be downgraded, is it easy to modify the needle coke manufacturing process? Or, is it easy to source lower-grade decant oil? 

Is CCR value directly linked with asphaltene content? In hyrocracker feed specification why limit is fixed for both CCR and Asphaltene content? Why both parameters are measured separately?

How to resolve high differential pressure issue in FCC amine absorber?

Is there some way of reversing silicon poisoning in our hydrotreating catalyst?

Please share an article on processing of used engine oil distillate through Hydroprocessing. How long the catalyst lasts? Do we need to put metal trap separtely?

We have a black sludge formation at the interphase of naphtha and water in OVHD accumulator. But all the OVHD paramters like pH, Iron  and Chloride are normal. The crude unit has a partail condensation ovhd system and the black sludge is observed in the second boot (Cold reflux boot). There is a CI dosing in the accumulator upstream. What could be the reason for this sludge?

Diesel hydrotreater feed introduction to Reactor is designed to be done at 180 to 200 DegC. Is there any issue, if feed introduction is done at 240degC or 260degC during Normal startup (Assuming HP Loop contains above Minimum prescribed H2S 2000 ppm). 

What are the ways or methods to ensure that sulphiding of the Diesel and VGO hydrotreater units catalyst is completed? What are the check points?

1. Is it purely by injecting the stoichiometric required DMDS into the reactor that decides sulphiding is completed?

2. Is there any thumb rule for quantity of dmds that needs to be dosed during first stage of sulphiding at 220degC or quantity of dmds that needs to be injected for second stage of sulphiding at 330degC?

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?

Why does NiMo catalyst has more hydrogenation potential than CoMo? What nature of it is enabling it to do so? 

Why does Nitrogen molecules in hydrotreating units takes the path of hydrogenation followed by hydrogenolysis instead of direct hydrogenolysis unlike sulphur molecules which gets hydrogenolysis directly? 

Between CoMo and NiMo, Which catalyst has more deactivation rate and why?

For a residue hydrotreater, feedstock about 360C+, what would be accaptable values for TI (toluene Insoluble) following ASTM D 4072? We encounter often pressure drop issues in the first reactor and we would like to sample the feed mix for TI. But there is no guideline what is acceptable and what is too much. Any idea?

Regional shifts in higher refinery capacity seem to correspond with the need for more intensive water treatment programmes involving wastewater recycle processes while protecting heat exchangers and linked assets from fouling and corrosion. At what level of investment have you seen refinery operators commit to plant water quality while reducing its consumption?

How can I know there is weak acids in crude oil and what's the effect of weak acid on the overhead conditions in the crude distillation unit?

How to confirm the run away reactions in Diesel and Vaccum Gas Oil hydrotreater units reactors? Is it localized phenomena at particular location or gets spread on wide area of the catalyst?

As the 1st bed hydrotreater bed exotherm for our unit already stays at above 40degC during normal operation, I would like to understand how to confirm the run away phenomenon and take necessary actions like actuation of EDPS. Kindly guide.