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Industry sources project FCC market expansion to more than $8.75 billion by 2030 (vs $6.78 billion today). To what extent is this due to new reactor and catalyst formulations?
Replies: 2
With the most profitable refiners focusing on the production of basic chemicals such as aromatics, olefins, and polyolefins, what catalyst and reactor technology is key to this focus?
Replies: 0
What AI and data analysis techniques do catalyst and reactor technology developers offer refiners for higher yields while meeting near-zero emissions specifications?
Replies: 4
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)?
A CO2 removal unit with MDEA solvent has experienced severe foaming issue in the regenerator which has lead to solvent loss to the regenerator vent. When foaming happens in the regenerator, observed high/ fluctuating DP across the packed bed and wash water tray (bubble cap trays) on the regenerator section. On the absorber side, the DP maintain stable and no solvent carry over to downstream vessel during foaming incident. However, the foaming in regenrator has led to inefficient solvent regeneration and caused high CO2 breakthrough at the absorber overhead (treated gas).
The process gas to the absorber is mainly coming from the syngas produced from upstream Steam Methane Reformer unit with Natural Gas feed. The Process Gas to absorber mainly composed of CH4, CO, CO2 (7-8 mol%) and H2.
Analysis on the cause of the foaming incident in the MDEA regenerator is suspected due to solvent contamination with particulate matters as contamination due to long chain hydrocarbon is not possible in this process. MDEA solvent has been analyzed with the TSS has been observed between 3 - 10 mg/mL. The solvent appearance remains clear without any coloration which would indicate solvent degradation. Lab analysis has also shown low HSS and no signs of solvent degradation.
Hence, the way forward to avoid the foaming in the regenerator is to replace the filter element of the side stream filter from 10 micron nominal to 5 micron absolute. This is to ensure small particulate matters are sufficiently filtered during normal operation with 5 micron absolute filter.
However, would like to check if following parameters can also cause amine foaming inside the regenerator: * Can over stripping from the regenerator reboiler caused turbulence and foaming especially at the rich amine inlet to the regenerator feed gallery? * Rich amine at inlet of regenerator is located below of the wash water trays (bubble cap trays). Some amine would expected to be entrained with CO2 to the bubble cap trays. Should the antifoam be injected at the regenerator reflux line to break down the foam which could build up at the bubble cap tray section?
Appreciate your feedback/ thoughts on this.
What are the best practices in degassing the recycle gas circuit of a hydrotreater in preparation for major works or turnaround?
Replies: 1
We are having caustic regenration facility in our LPG treating unit. During caustic regneration,Disulpide oil (DSO) will be removed by absorbing with help of naphtha in CFC. We are expreincing higher levels DSO in the regenrated caustic.
My questions are :
1. Does LPG quality will be impacted if regenrating caustic is higher levels of DSO. (Design says NIL)?
2. What the possible ways to reduce the DSO content in regenerated caustic?
3. Is there any correlation on DSO based on LPG inlet mercaptans?
The Hydrogen Production Unit (SMR) is designed for both natural gas and naphtha. The sulfur in naphtha feed is in limit. My queries are: 1) What will be effect of PONA of naphtha on hydrogen production and methane production?
2) What will happen if naphtha feed contains more amount of naphthenes (more then permissible)?
3) What is possiblity of conversion of naphthenes into methane?
Our water maker is facing a problem while processing the crude oil mixture. The electrostatic plates are reversed because it is not possible to break the emulsion present.
Composition of the crude mixture: - Mars blend 58% - Basrah Medium 20% - Bouri 8% - Lokele 7% - Frade 2% - WTI 2%
Wash water Desalter 4.5%, brine desalter not present. - DeltaMix valve 0.35 kg/cm2. - Raw density 845 kg/m3 - watermaker inlet temperature 120°C - Water OUT desalter pH 8 - IN water sample not present - Head water pH 8
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?
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 ?
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 is the best way to reduce HCGO end point, apart of increasing the flow on the sprays?
How is the dual focus on increasing butylene and propylene production being met?
Gasoline, diesel, and aviation fuel are still expected to dominate refinery markets to 2030; what reactor and catalyst systems will be the most effective in maximising fuel production?
Replies: 5
What role are AI systems expected to play when optimising plant-wide operations?
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?
One of our Unit has four furnaces viz. F-1, F-2, F-3 & F-4. There are two fire boxes: one for F-1/F-2 and one for F-3/F-4. Both fire boxes have two parallel convention banks and a common stack. The furnaces have the issue of low steam generation from convection banks, high stack temperature, BFW flow mal-distribution in convection banks and hence a lower efficiency than design. Sketch of the furnaces with current & design flows are provided below for reference. What could be the possible reasons and remedial solutions.
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.
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?
Assuming 3 different Hydrogen Pressure Swing Adsorption (PSA) technology - A, B and C. Has anyone / any plant (refinery, steam cracker etc.) had the experience in loading PSA adsorbents supplied by A in other PSA technology - in this case B or C?
If it has been done before, how is it managed in terms of operational (PLC tuning) and optimization?
What are the potential issues if one plant is to proceed with the above approach - i.e. different adsorbent supplier and PSA technology?
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?
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)
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!
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?