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Lean Amine (MDEA) from Amine Regenerator bottom pre-heats the feed to regenerator and then is pumped to users while passing through Air Fin cooler (AFC). A slip stream is sent to pre-coat filter and filtered MDEA joins the rundown. We are facing high MDEA rundown temp (>75 degC) due to internal fouling of the rundown Air fin cooler (AFC) which is designed to reduce MDEA temp from 104 degC to 60 degC. MDEA rundown results is as follows: Fe (5-6 ppmw), HSS (1.5-2.0), Na (400-500 ppmw), TSS (200-400 ppmw). There is no trim cooler at downstream of AFC. There is a HSS removal from MDEA skid which was recently commissioned in Mar'23. What could be the reason for fouing of AFCs? Is there any reference of online cleaning of Lean Amine AFC without impacting the quality?
Replies: 1
How can cycle time be optimised in needle coke production while refurbishing a fuel grade coker?
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How to prevent fouling in feed / effluent exchanger of hydrotreatement unit in refinery?
In a crude processing unit we have two stages of separation (gas, oil & water) and two stages of desalter. I need to know if we should heat the crude between two separators or before the first desalter? and why?
In our plant, DSN tank exists for cold feeding to CCR unit in case of interruption in u/s hot feed from NHT unit or during total power failure start-up of Refinery. Cold DSN is fed to NHT stripper and thereby to CCR unit via Depentanizer and Re-run columns to produce Hydrogen for NHT start-up. Once Hydrogen is produced, NHT feed in is done. Stripper bottom is recycled back to FSD till DSN is on spec. When DSN is on-spec, feed from DSN tank is isolated. How to avoid poisoning of CCR catalyst while keeping NHT running with off-spec DSN? Further, can DSN from Tank be sent directly to Depentanizer bypassing Stripper in absence HP nitrogen input in Stripper? What are the precautions to be taken for operation of CCR unit?
Replies: 4
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?
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?
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?
What AI and data analysis techniques do catalyst and reactor technology developers offer refiners for higher yields while meeting near-zero emissions specifications?
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)?
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?
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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.
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Under what conditions do you see opportunities for blending petrochemical byproducts with refinery fuel feedstocks to lower conversion costs?
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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?
Replies: 8