In our NHT licensed by Topsoe. We have once through process. We don't have any recycle gas compressor. We directly take hydrogen from 40 bar header to maintain a system pressure 24.5 bar. Does it have any significance?

We pressurize the system with nitrogen gas before start up period in order to sweep the whole water from the system. However every time the gas gets stuck somewhere in the equipments. For example; we had a problem last time. We pressurize the system up to 0.5 bar. Then nitrogen gas has drained from everywhere until the system has not contain any water. Then we start to take flushing oil into the system (a kind of crude blend like slop). While taking flushing oil, we have noticed that the temperature of the middle of the column has not risen. Normally the temperature in that point is 160 oC instead of 110 oC. We have observed same scenario at another column. As a result, after we took flushing oil into the system, we have a lot of difficulty about draining nitrogen from the system. What can you think about that issue, what can you suggest about nitrogen usage for draining fluid state from the system.

In our refinery, the COD (chemical oxygen demand) of treated wastewater is analyzed in both laboratory and field analyzers. Lately, the COD in the analyzer has been increased by 4 times compared to the COD in the laboratory. We use the same method-Acidic Permanganate for both, but the additional AgNO3 is used for only the laboratory. However, the chloride content in treated wastewater hasn't been increased. What is the reason for the difference between the field analyzer and laboratory? 

HVGO cut in Vacuum distillation unit color increased from brownish to dark green during processing of Urals crude. No exchangers found leaking in preheat train. Draw off temperature and VDU heater COT also reduced to improve the color but no much improvement seen. Why does this happen?

Can an ultra heavy crude oil of 12 deg API be converted to 22 Deg API by mixing Diesel?

Any guide for Natural draft heater ducy sizing and stack effect calculation?

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?

Pitting corrosion found at bottom/shell side charcoal filter at (lean amine filtration system) Lean amine = MDEA 30% demi water used for preparation and makeup (Diss O₂ present) feed gas CO₂ 4%, H₂S 0.0 HSAS 0.18%, cl 300 ppm at lean amine sample. What do you think are the factors responsible for corrosion?

What is the roadmap to achieve autonomous refining in a complex oil refinery using digital technology?

We are observing a lot of vacuum pressure fluctuations in our VDU which is operated at 21 mm Hg. During fluctuations, we tried to switch over ejectors with different capacities, however, no effect was observed. Pressure fluctuations are happening on their own and it is becoming steady after a certain time, say one day. How do we solve this problem and what is the possible root cause?

How do you test maximum silicon capacity on Si trap in laboratory? I have difficulty in deciding the model silicon molecules and reaction conditions.

In the DHDS unit, the amine scrubber is having a foaming issue. Antifoam dosing was not yet commissioned from almost 20 years but suddenly foaming problems have started. Antifoam helps to control the problem but continuous dosing is also not suggested. What may be the reasons when we are maintaining other parameters and proper Delta T between amine and process gas and how can we encounter this issue?

In the naphtha hydrotreating unit, the sulphur is removed, and then in the CCR Platformer feed DMDS is dosed again. Why can't we maintain the required sulphur level in the CCR Platformer directly from the NHT unit (suppose in the NHT unit feed Sulus is 786 wppm and we have to maintain 0.75 wppm in CCR PF feed)? Why it is necessary to remove sulphur first and then add sulphur (DMDS) again?

We have a heavy coker gas oil hydrotreating unit and its reactor MOC is 2.25 Cr, 1 Mo, 0.25 V. As per the licensor manual, the MPT (minimum pressurisation temperature) is 93C. However, as per the fabricator, it is 38C. The query is which MPT value will be governing and be used during pressurisation of the unit at startup.

If the steam turbine motive steam pressure becomes lower than the actual pressure, let's say 30 bar operating pressure and dropped to 20 bar, can you please elaborate what is the effect of pressure on the governor – will it trip the compressor on what basis?

Are there options for online cleaning a preheat exchanger network?

We’ve increased the opportunity crude content of our feed and are experiencing high calcium issues. How can we best address this?

Please suggest ways of reducing steam demand in our sour water stripper.

For best product quality from vegetable oils should we hydrotreat them with conventional petroleum feed or use them as straight feed?

Our air compressor trips off immediately after it powers on. Is this a mechanical or process issue?

We’d like to produce less light naphtha and more liquid fuels from our hydrocracker. How do we go about it?

What is the best route for maximum propylene from a resid feed to the FCC?

We didn’t expect severe corrosion issues in the carbon steel of our amine unit. What is causing it?

The CDU boots water is red-orange color. It has been more than a week now. We are not sure where this problem comes from and how this can affect the process. (When we add corrosion inhibitor in the water, the part of it was turned into brown color.) Could anyone please share the knowledge regarding this issue?

For a crude tank with a capacity of 610,000 bbl capacity, what mechanised cleaning system would be required and how long would it take to clean the tank especially of sludge. This is a refinery cum petrochemical complex project to be undertaken and we are in the process of optimised tank sizing.