Q & A > Delayed Coking
Date  Replies
08/06/2010 Q: What is the purpose of a flood nipple in a nozzle of a Column which goes to reboiler?  
21/10/2009 Q: With Increased pressure, Increased COT, Increased Temperature, & low Residence Time in the Coke Drum, we are facing high gas make with increased Methane in the Gas. High Coking is also seen. The API of the Coker Feed is 3.544. Can anyone explain the reasons why we are achieving high amount of Methane make in the process? (1)
21/10/2009 Q: How can one predict the composition of off gases from Coker? What are feed characteristics used to get a better prediction of olefins in Coker off gases and LPG?  
21/10/2009 Q: We operate one of the largest cokers in the world and are keen to increase the distillate yield. There is lots of information currently floating around wrt concepts like 'zero recycle', use of additives to reduce coke yield, recycling of LCGO to recover distillates, etc. As zero recycle is promising, our questions are:-
1. Yield improvement obtained with zero recycle?
2. Quality of HCGO post implementation of zero recycle wrt Metals, CCR, particulates, etc.
3. Destination of any extra heavier HCGO stream (from main fractionator bottom) along with quality of this stream.
4. Any issue wrt reliability of the plant post zero recycle option. 		(1)
23/09/2009 Q: We are stress-modelling existing coker drum piping for major piping upgrades, eventually for both static and dynamic modes. We came across the "banana effect" phenomena which is thermal bowing of the drums at quench cycle, and asked that such lateral movements be included with our upper-level piping analysis. We were told to model as much as 1 foot or more of movement, but very difficult to satisfy this. To date, we can only input as much as 4" and above that, results show failure or large overstress. The field says historically there is not much movement at the drum top for years now, which we are quite reluctant to accept.
Can anyone share their experiences with delayed cokers in other facilities, in particular, this banana effect? Any related input, especially with piping movements, thermal cycling, etc. should greatly help with our analysis dilemma. 		 
24/07/2009 Q: The Delayed Coker Unit (DCU) and the FCC GasCon Dry Gas is treated in an Amine Unit (with MDEA), in order to eliminate H2S, prior to injection into the refinery fuel gas system. However, operational problems have been experienced at the Amine Unit, due to MDEA degradation and the presence of heat stable salts (HSS), among other factors.
We know that HSS formation is due to an irreversible reaction between some contaminants (strong acids anions such as formate, acetate, thiosulfate, thiocyanate and chloride) and the amines molecules. Furthermore, we know that the DCU Gas contains anions such as acetate, formate and cyanide.
However, we have no available information about the contaminant concentration in the DCU Gas or FCC GasCon Dry Gas.
Do you have any information related to a typical contaminant concentration (e.g. strong acids anions) for a DCU and/or FCC GasCon Dry Gas? Moreover, any additional information would be appreciated (E.g. What kind of process do you think would be appropriate for reducing contaminants concentration? We have heard that a water wash stage previous the amine treating could be useful). 		(2)
12/05/2009 Q: Flow measurement into cokers is traditionally done with DP meters (orifice, wedges , venturi etc). I am trying to get an idea about the maintenance costs associated with DP devices (pressure line purging, purging liquids etc)  
07/02/2009 Q: Where can I obtain information about Vacuum distillation unit overhead sourgas minimization?
What are the parameters that effect the sour gas generation rate? Are there any correlations available to relate those parameters to sourgas rate?
What are the methods and ways to minimize the cracking of reduced crude oil in vacuum unit charge heater? what are the main effecting parameters of fouling the vacuum charge heater? 		(4)
21/06/2008 Q: Is there a noticeable increase in blending clarified FCC slurry oil into No. 6 fuel oil? Since this obviously circumvents the need for blending lighter, higher-value products into the No. 6 fuel oil, how much of an impact on total refinery profitability can be expected? Are some refiners instead opting to use higher percentages of slurry oil as feedstock to a coker unit or a hydrocracker? (1)
12/06/2008 Q: How are existing distillate hydrotreaters revamped to process higher volumes of feedstocks performing? What are some of the latest reactor and catalyst improvements that permit processing higher volumes of FCC LCO, coker naphtha or light coker gas oil through the distillate hydrotreater, and what are the corresponding benefits to downstream naphtha hydrotreater performance? (1)
23/05/2008 Q: We have local crudes which are very waxy in nature. The reduced crude from these crudes has a wax content of 40 pct wax and 1 pct asphaltene. The pour point is very high requiring cutter and depressant.
We were thinking of a thermal process like visbreaking or thermal cracking, but this resid is very light and quite a lot of it vaporises at common visbreaking condition unless pressure is increased substantially.
We are trying some pilot runs using makeshift arrangement. Has anyone tried this for light waxy feed and what were the results and operating condition used? 		 
01/05/2008 Q: What are the conditions leading to brine production in a Catalyst cooler?  
06/04/2008 Q: Certain refiners are feeding vacuum residue and FCC slurry oil to the coker unit as part of their strategy for reducing (or eliminating) fuel oil production. To this end, what operational and hardware changes should be made to the vacuum tower and FCC main fractionator? (1)
11/02/2008 Q: Recently we have started using refinery slop oil as reactor overhead quench. Due to presence of some water (free as well as emulsified) in slop oil the fractionator operation is getting disturbed. What is the most efficient way of separation of water from slop oil (along with proper tank preparation)? Would putting a coalescer in slop oil service (density varies from 0.8 to 0.9) be effective?  
07/11/2007 Q: We are processing reduced crude oil coming out from CDU bottoms (35 API). The feed to the coker has a typical API of around 15 to 17.5. The chamber is operated at 2.2 to 2.3 kg/cm2g and the furnace coil O/L temp maintained at 498 deg C. The recycle ratio is maintained at around 0.9-1.
Now we want to increase Naphtha and c3/c4 yields, which are 8% (95% volatility 110 deg C) and 4% respectively. Please suggest which way to approach. 		(2)
05/09/2007 Q: We are trying to add heat to the front end (feed stream) of a vacuum unit (part of a crude unit) and wonder if anyone has done this in recent years by using skid mounted equip of some sort or small "package" units of exchangers/heaters, etc. We only want to do this on a temporary basis, say for 4-6 months (1)