How are catalyst suppliers further enhancing catalyst formulations for refiners focused on processing a wider array of feedstocks (such as renewables, plastic waste, and heavy crudes)?

In our CDU we have stablizer and sipliter columns, stablizer for separating LPG from Naphtha, after the annual maintenance, we have a problem in the boot of the overhead drum of stablizer column we have a Black water and high iron number so what's the problem that makes this black water ? 

How to prevent gumming or carbon formation in prereformer catalyst aside from maintaning an inlet temperature? Is hydrogen recycle in the prereformer beneficial in preventing gum formation?

I have three questions: 1) What reactions are source of high hydrogen purity at naphtha platforming (catalytic reforming) unit? Either naphthene's or paraffins reactions?

2) The NHT-Plaformer unit was down for couple of days. The startup was executed after 1 week. After startup it was observed that, system pressure was not meeting the set point of 350 psi. But in previous history, where ever startup was performed, at turndown capacity the system pressure of 350 psi was meet. This is its not even reaching to system pressure of 350 psi. While hydrogen purity is also decreased up to 60%. HCL is recycle gas is almost ranges between 0.5 to 1 ppm and H2S is also 1 ppm. During startup at 880F, the HCL was found in traces while H2S was found 2ppm. Platformer catalyst is UOP-R56.

3) Further more about NHT, it's not removing sulfur properly even though we have done skimming recently. Due to low hydrogen purity of platformer, the ratio is limited to 340 to 350. While ratio must be 380. The reaction temperature is 630 F (which is 5 F higher then EOR for catalyst). Still it's not removing properly, The stripper is operating and minimum pressure and maximum bottom temperature.  NHT catalyst is UOP-HYT-1119 Can you tell me about this to improve sulfur removal currently?

What role are AI systems expected to play when optimising plant-wide operations?

What is the best way to reduce HCGO end point, apart of increasing the flow on the sprays?

What is the expected volumetric efficiency in the diesel product treating only SRGO? (It is understood that it is less than 103.4% due to the decrease in the content of aromatics and olefins)

I am currently workin on a decommissioned polyethylene plant. Can anyone suggest a good reference, and or, databases or applications for estimating cost of turnaround, pre-comm, comm and re-start? Thanks in advance.

Any chemical catalytic conversion technology for converting waste gases (rich in CO2, CO) to Ethanol? if yes please elaborate on capex, opex part and process philosophy to achieve more than 50% conversion?

In our Delayed Coker unit Furnace, Plate type APH supplied by GEA Eco flex India Pvt Ltd is installed. Since last few months we are unable to increase Induced draft fan suction temperature as per our process requirement (To maintain acid dew point delta). Keeping in view of not increasing suction temperature we suspecting this furnace Combustion air APH may be leak and during furnace pigging/shutdown opportunity we thoroughly checked this APH but couldn’t find the leak If anyone having experience/expertise in above described matters, kindly share with us (like how to identify leak in furnace APH and what is standard practice follow to arrest the leak) Your valuable response will be appreciated!

According to the Inspection Guidelines for Corrosion Control in Hydroprocessing Reactor Effluent Air Cooler (REAC), we need to ensure that at least 25% of the wash water is liquid. My question is how do we calculate it practically?

We are an Indian refinery and recently commissioned our full conversion VGO hydrocracker unit. Within 2 months after start up, we observed higher COT's in one of the heater pass. Our heater is 4 pass heater. What could be reason for this?

We carried out flushing with high gas/liquid flow rate with jerks as well. Still dp across the pass is very high. Finally we wanted to carry out pigging as issue still persists.

What could be reasons for this and how to avoid such scenarios in future. Request to share your ideas and similar experiences.

We have a problem in one of the main towers (capacity = 150000 bbl/day ) in the company I'm working for. There is an inclination in the tower which may affect the efficiency of separation. So, what's the maximum allowable inclination so that no effect in the separation efficiency may occur?

How is the dual focus on increasing butylene and propylene production being met?

What contaminants removal capabilities are available to expand the SAF feedstock base?

With the chemical value of hydrogen (H₂) increasing, what are the best options for extracting H₂ from fuel gas?

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?

Thermal Shock in Heat Exchangers. Degree of Temperature change per time is the key factor to take a decision whether any heat exchanger is likely to undergo a thermal shock or not. Is there any formula for computing this limit of danger for taking immediate prevention action?

T1 and T2 - Temperature range of colder side

T3 and T4 - Temperature range of Hotter side
Needless to say T1<T2<T3<T4.

Boiling point of the Colder fluid is very well higher than T4. How will it be possible for the colder fluid to boil and evaporate vigorously to attain Thermal shock status when its Boiling point is very well higher than T4?

What are the control and prevention means to ensure and avoid Thermal shocks?

We are experiencing a pungent foul smell in the polypropylene product pellets. The source of the same has remained untraceable having attempted various changes in the process, as required. Can someone please share a similar experience and the possible troubleshooting options?

I am currently working on fixed bed platforming unit. The unit is Semi-regenrative catalytic reforming. The unit was commissioned on 1989.  The unit is designed for Arabian light crude heavy naphtha. We have processed, Iranian light naphtha, Murban naphtha. Currently we are processing Arabian super light naphtha. I see that, the reactor delta T's are high enough (more than the one when process arabian light), but gases production increased, hydrogen purity is between 70 to 43% and reformate yield is OK but RON decreases. The water chloride management is in range. With this, recycle gas compressor discharge temperature and pressure increases as gas production increases. The discharge temperature are so high (200-230F). Common discharge header pressure also increases. As recycle gas flow increases, reactor effluent trim cooler which is before HP separator temperature increases. The temperature must be in range of 100-105F. The current temperatures ranges between 120-140F.

What could the reason's of above query. What action should we take to resolve these problems.

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?

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.

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?