Q & A > Revamps and Turnarounds
Date  Replies
27/02/2017 Q: We have a peculiar case where the Coke Drum has twisted. Any suggestions on the repair procedure? (1)
15/02/2017 Q: In a CDU overhead drum reflux, which are the advantages of a three phase separator versus a flooded one with a naphtha + gas outlet, a naphtha to reflux outlet and a water separation? And how can you estimate them? In both cases the reflux temperature is the same. (1)
19/01/2017 Q: We have a 50,000 bbl/d capacity crude unit designed for Iranian light crude oil. The main crude column needs to be replaced due to ageing. We would like to take this opportunity to revamp to unit capacity as well to about 70,000 bbl/d. Based on a previous study carried out, the unit capacity can be increased up to 70,000 bbl/d by installing a pre-flash drum before the charge heater. However, now we have to replace the main column. In another study carried out, it has been identified that the some modifications are required to be done to the charge heater such as re-tubing with different metallurgy and changing the passes from 1 to 2 etc. if the unit capacity is increased up to 70,000 bbl/d (without a pre flash drum).
I would like to know whether installation of straight 70,000 bbl/d capacity column or installation of same capacity 50,000 bbl/d along with a new flash drum (to avoid charge heater modifications) is more economical.
04/01/2017 Q: In my refinery there is a 15 kBPSD LSRG sweetening unit in which caustic washing procedure followed by MEROX oxidation process. In case of feed change scenario, is there any solution in terms of gas condensate sweetening by means of before mentioned facilities? If yes, what are the changes in terms of capacity, chemical consumption, and mercaptan removal efficiency? If there is any revamp, which sections need to be resized? (2)
03/01/2017 Q: We are facing plugging of 350 distillate pump strainers in the VDU (lube oil refinery). The 350 distillate is the middle cut of the distillation column.
Since Sunday, the pump strainer has been cleaned more than 5 times due to coke deposition. All operating parameters have been compared to the PFD and no deviation has been observed except that the pumparound flow above the 350 distillate bed is less than the required.
Also this problem started after a revamp on our vacuum distillation column in 2013. Since then there has been severe coking in this pump and it requires monthly cleaning. But as of now the problem has become severe and the strainer is getting plugged in a matter of hours.
Your advice/insight on troubleshooting the problem will be appreciated.

Additional info:
We have sent the samples for analysis and are waiting for the results.
The heater skin temperatures were running high, and we adjusted it.
However, we are still seeing coke in the strainer. Although the frequency of plugging is reduced.
How can I increase the flow on the 1st pumpdown. The flow of the 2nd and 3rd pumpdown is above 50 m3/h but the 1st pumpdown is less than 35 m3/h.
10/05/2016 Q: Our crude vacuum distillation column overflash pump suction strainer gets fequently full of coke.
Overflash pump suction temperature is 374℃~385℃, flash zone pressure 21mmhg, top pressure 5mmhg.
Metal contents of overflash are 154.7ppmw(Ni 36ppm, vanadium 118.7ppm) and Metal contents of Vacuum Residue are 223.8ppmw(Ni 49.2ppm, Vanadium 174.6ppm). How can we prevent this?
25/03/2015 Q: I would like to know if when we design a transfer line of CDU or VDU heater then do we consider erosional velocity as a constraint? The mixed phase velocities in transfer line are frequently higher than calculated erosional velocity (from API-14E). (4)
13/08/2014 Q: What is the welding procedure of T-joints in 8 mm bottom plate of tank? Can T-joints be welded before completing short and long joints?  
05/02/2014 Q: In our vacuum distillation column three valve trays are replaced from glistch packing in order to obtain more deeper cut of SAE-40 and wash recycle is provided to wash the packing but whenever unit is down due to any failure the wash recycle line gets plugged. We are using SAE-20/SAE-10 as a wash recycle oil. Can we use HVGO for that purpose or any other solution for that problem? (3)
23/12/2012 Q: In our CDU column we draw off naphtha (overhead) , kerosene , light diesel , heavy diesel and AGO fractions and 4 pumparound circuits (on kero, light diesel , heavy diesel and AGO sections). The top of the column is cooled by reflux (overhead –air coolers-receiver – column) . From a simulation it appears that approximately 55 % of heat from the atmospheric column is wasted in overhead line (air coolers) and the rest 45% is recovered in pumparounds heat-exchangers. We would like to introduce the additional pumparound (TPA) and recover some of the heat in new heat exchanger(s) upstream the desalter - of course the exact location of the added heat exchanger will be analyzed with pinch study. What do you think about the solution of introducing the additional pumparound in order to recover some of the heat which is currently wasted in air coolers? Maybe some other recommendations about recovering this heat to the process. (7)
09/12/2012 Q: Is it a myth or reality that in a refinery fired heater for the same throughput, same coil outlet temperature and everything else being the same, a fuel oil fired furnace will give a lower skin temperature in the convection section than a natural gas fired one? (5)
04/10/2012 Q: As per section 11.1.3 of API 574:
"In low-pressure and low-temperature applications, the required pipe thicknesses determined by the Barlow formula can be so small that the pipe would have insufficient structural strength. For this reason, an absolute minimum thickness to prevent sag, buckling, and collapse at supports should be determined by the user for each size of pipe."
Table 6 of the same code provides some data for Carbon and Low-alloy Steel Pipe at less than 205 degree centigrade condition.
My question is how this strength is measured and in case of temperature higher than 205 degree centigrade what are the values?
26/09/2012 Q: While cutting a replaceable tube inside furnace, a cut mark by gas cutting tool is found on adjacent good tube. A cut mark of 3 mm depth and 6 mm diameter is created on a 3 inch (originally 5.49 mm thickness) A335 Gr. P5 tube. Should I replace the tube or locally repair the mark by welding? I should add that overall thickness of the tube is satisfactory. (1)
24/09/2012 Q: I work on CDU/ VDU plant as a process engineer . We commissioned performance of the feasibility study concerning revamp of the vacuum system. It appears that we may achieve different vacuum at the top of the vacuum column with different solutions, so we have to consider the best option in terms of the yields of the fractions.
Is it possible to simulate in Sulzers proprietary application SULCOL how the yields will change from the vacuum column
1. when I set various pressures at the top of the column (without modification to vacuum column)
2. when I change the structured beds from current structured packing Mellapack to Mellapack Plus or other.
I would be very grateful for some information with regard to technical capabilities of this program or maybe some recommendations for other free software of this kind.
10/09/2012 Q: How does Vapor/ Liquid ratio at the bottom tray and Reflux to Feed ratio affect stripping quality? What happens when number of trays is increased? (1)
10/09/2012 Q: Why do Olefins have a higher Cetane Number than I-Paraffins? (2)
23/08/2012 Q: One of our condensers --using cooling water as coolant media -- is located at elevated position. We can periodically isolate and dismantle this condenser, and upon inspection , the tube side (cooling water side) of this condenser always suffers from signifcant amount of fouling.
One of our colleagues suggests we install an "inline centrifugal pump " on the cooling water supply line into this particular exchanger in order to increase the amount of water flowing through condenser's tube hence minimizing the fouling rate.
I'm a bit doubtful about this suggestion, as this exchanger receives the cooling water supply from network header, thus the amount of water supplied to the inline pump will still be the same as the amount of water supplied directly to the exchanger without inline pump. An inline pump, in my opinion, will only increase the inlet pressure of cooling water into this particular exchanger. In my opinion, any attempt to increase the discharge valve opening of inline pump cavitate the pump if discharge flow is higher than suction flow received from network header.
I would like to hear the opinion from experts about the inline pump of cooling water network.

Thanks for all..
The suggestion from Mr. Banik sounds interesting, and I'm going to evaluate it.
Anyway, I'm still curious with the case of inline pump installed in the cooling water supply line of an elevated exchanger, whether it will be able to pull more water supply from network.
My premises are :
1. Let's imagine an elevated exchanger is normally supplied with cooling water flow of X m3/hr.
2. The original supply pipe runs on the same elevation with main header of H m , then turning up towards exchanger.
3. If I reconfigure the supply pipe to turning down of H m below main header, then turning up again H m before further going up to reach the exchanger, the pressure profile inside this reconfigured pipe at elevation of H m will still same with pressure profile of original pipe at elevation of H m.
4. Hence flow of water in supply pipe no. 2 and 3 will still same.
5. If I put a pump in lowest section of reconfigured supply pipe no. 3, then the amount of water flowing into pump suction will still same X m3/hr.
6. As centrifugal pump doesn't suck, but it only pushes, so the amount of water pumped will still same X m3/hr. The only different thing is water inlet pressure to exchanger increases hence water outlet pressure from exchanger also increases.
7. Thus operating the pump discharge above X m3/hr will cause transient inventory loss in the pump casing hence cavitation.
Do I miss something or make mistakes in my premises above ?
07/08/2012 Q: Our Desalter transformer has got three transformers supplying to individual grids. This step up transformers are facilitated with three outlet tappings with higher ratings. We always run the desalters with same outlet tappings for all three transformers. Is it advisable to run it with different outlet tappings in all three transformers in a desalter?
I would like to know electrical feasibility as well as process advantages?
23/06/2012 Q: 1. What is the purpose/function of Steam Ejector in Vacuum distillation column and how it works?
2. Why it is placed at the top of column and why not the bottom in refinery? please explain the barometric concept regarding this installation
04/02/2012 Q: In case of pressure gauge what is the specific use of Gauge Saver and Snubber? When do we select Gauge Saver and Snubber? Why is Monoflange with Block and Bleed required for pressure gauges? (1)
18/11/2011 Q: We are looking for information about cyclic catalytic reforming units and the conversion of semiregeneratives units into cyclic units. Would be useful to know what refineries in the world have revamped a SR UNIT to cyclic unit. Capital cost are prohibited? What would have to be the size of the new fourth reactor? (1)
11/11/2011 Q: We find the crude heater tubes started slightly bowing towards the burner inside the radiation zone. The investigation drives my mind over the below written questions...
1. What can be the maximum height of the Fired heater's radiation zone (or) the maximum tube height allowed inside the radiation zone (vertical coil type) as per standard?
2. What is the efficient ratio which can be achieved between the radiation:convectional zone heat transfer(in percentage)? Its a balanced type heater and we could heat the combustion air up to 275 C max?
3. We use P9 material tubes inside the furnace (cylindrical-twin zone). We are puzzled as to why the bowing is towards the burner side? Why not towards the side and backwards?
4. What is the maximum pressure drop across the burners allowed? As we go increasing the throughput in varying the Fuel oil and Fuel gas burning, the skin temperature response in all the section of the heater is not uniform. So the heat flux variance is also expected. I would like to know the methods available to find the heat flux variance inside the radiation zone.
5. The burners (Low NOx/SOx) used are stretching over the design sometimes due to the lower inlet temperatures. Flue gas recirculation is also included in the design. What can be the problem when a burner is running over the design limits? We have oxygen, CO, NOx/SOx analysers but they don't seem to be reliable most of the time.
21/07/2011 Q: In our Vacuum Distillation Unit we have a vacuum system consisting of overhead water coolers, two ejectors with condensers and a liquid ring vacuum pump. During the summer time when the cooling water to overhead coolers and ejector’s condensers increase above 23C we observe increased pressure on the top of the vacuum column to approx 5-6 Kpa (from 3 Kpa) which is of course logical. In this situation when we want to increase the temp to the vacuum column in order to maximize yields , the pressure will increase too and the result is quite opposite. The significant fluctuation of temp of cooling water (sometimes during the day it is about 5C) makes it also impossible to optimize yields from the vacuum column. Please advise what to do in this situation in respect to our plant, how we can keep pressure steady and low , how to improve yields in this circumstances from the vacuum column. Maybe you have similar problems and please write how you deal with that. Some recommended literature/web sites on this subject would be very helpful too. (4)
16/07/2011 Q: Currently the slop wax from the our vacuum distillation unit is directed outside the plant. Do you know some solutions regarding recycling this low-margin product back to the process? I have read about directing it to the feed of CDU or with the long residue to the vacuum furnace or directly from the vacuum column to the evaporation section of the vacuum column (is it safe and not coke the bed?) . Our plant is combined CDU and VDU , internals of the vacuum columns are structured packings Mellapack. I wonder what your recommendations are on this subject, maybe some advantages and disadvantages of specific solutions. (4)
22/06/2011 Q: This is my NHT unit:
1 reactor with 1 fixed bed, volum 27m3, catalyst S-120 from UOP.
3 stage compressor: 4bar--> 10.5 bar--> 25 bar--> 43 bar.
Splitter 52 trays
Stripper 25 sieves trays.
If I change the feed for NHT unit from the SR naphtha with 100ppm wtS to the SR naphtha with 1230 ppm wt S ( because I changed the crude oil for DAV), what should I do to maintain the specification product for Platforming CCR (0.5 ppm S, 0.5 ppm N). And if I would like to revamp this unit for a product with 0.1 ppm wt S, what should I do?
22/06/2011 Q: Recently it was observed that the some of the radiation tubes of our atmospheric distillation heater were deformed. The tubes have been in operation for almost 30 years. Some of the tubes (specially at the middle section) deformed to the center of the furnace. Some deformed laterally to the adjacent tube. I want to know the possible reasons behind the phenomenon. Also please advise me what is the standard of replacement of the tubes in this mentioned condition.

20/06/2011 Q: We need to revamp our NHT. Before revamp: 23500 bpd SR Naphtha 100ppm S, Naphtha product for CCR feed has 0.5 wt ppm. After revamp: 30 000 bpd (90% vol SR Naphtha, 10 % coker Naphtha) with 0.1 wt ppm in product for our new regulation. We have 1 reactor (R1) with 1 bed of catalyst (18m3 catalyst in 27m3 reactor). I think we should install one more reactor. But I don't know which case is better between: Case 1: Feed-R1-R2-Stripper-splitter and Case 2: Feed-R1-Stripper-Splitter-R2 (recycle bottom product from splitter to R2)-R1. May you have any advice for our revamp?

Additional info:
Of course that Case 1 is traditional process revamp. But I have just read an article from Chevron, about their process revamp as Case 2. It called SSRS Isocraking (single stage reverse sequencing), licensed by Chevron Lummus Global. In that article, they said that the revamped unit can run at 133% of original design capacity with the existing recycle gas compressor. I think in case 2, R2 is existent reactor and R1 is new one (because R1's volume needs to be bigger than R2) This article named "Hydroprocessing upgrades to meet changing fuels requirement", Jay Parekh and Harjeet Virdi. Unfortunately, It's not for NHT, It's Hydrocracking. Is it O.K if I use Case 2 for my NHT revamp?
30/05/2011 Q: Some steam Jet ejectors are designed with a nozzle extension. What is the role of this extension in the ejector performance? During the last shutdown of our VDU, we noticed that the first (and largest) ejector steam nozzle was mounted without such an extension.
How could this impact on the ejector performance?
21/05/2011 Q: Can someone guide me on how to carry out the sizing of Liquid separator (vessel size calculation when a coalescing media/screen/mesh pad is used) when there is a coalescing media present in the separator ?
23/03/2011 Q: We would like to go for absorber to remove water from methyl acetate.
Feed composition: Methyl Acetate: 99% and water 0.75 % and rest are methanol and acetic acid.
I would like to know which type of absorbent I have to choose to absorb water from methyl acetate.
It will be great help, if someone can throw light on this.
16/01/2011 Q: Pyrolysis gasoline from Ethylene unit is sent to a recovery unit to recover C7 minus components. These are recovered in two columns under vacuum. Maximum temperature is at the bottom of the second column which is ~ 145 deg C. Unrecovered stuff is sent to Utilities as liquid fuel.
Anti-oxidant injection is done in the Ethylene unit as Pygas contains precursors such as dienes which can lead to polymerisation.
Recovery unit was operating steady, without any problems, for 8 months. Now for some reason the frequency of choking of the strainer of bottoms pump of the last column has increased dramatically. Also, we are experiencing frequent choking of burner guns. Material found is coffee coloured granules which become powder when subjected to pressure.
Trying to understand root cause. Not much has changed in terms of operating conditions. Very few component analyses are done in the whole system and not much information is available.
Hope to get some inputs based on experience in similar units.
30/11/2010 Q: In one of our furnaces we are facing problems with fuel oil dripping from burner blocks.
Atomising steam vs fuel oil dp is 2.5 kg/cm2 and fuel oil temperature is 170 deg C. Is the problem mainly due to improper atomisation or some problem in burners assembly adjustments, or insufficiency in air?
18/11/2010 Q: There is continuous increase and decrease in our column delta pressure in water methanol column. At the same time we noted that our temperature profile of the bottom and middle bed is also fluctuating.
I feel that our column is having vapor cross channeling.
There is some variation in feed flow and steam flow, but column is somewhat running at 100 % load.
If anybody experienced such problem in your plant, please throw some light to understand what causes this fluctuation in delta pressure and temperature profile in the bed and what action to be taken.
Additional information:
Steam direct injection for stripping
There are three bed made of PP intolox saddels
Steam flow is controlled by mid bed temp
Reflux is controlled by feed flow

More information:
This is a packed distillation column to strip methanol from water. We are using steam stripping in our case because there are some traces of Acetic acid in the bottom. To prevent corrosion we have to strip at low temperature, so we are using steam stripping. There is huge variation in temperature profile of the middle bed, at 100 % load First indication of channeling is the change in delta pressure and disturbance in temperature profile. Disturbance in temperature profile is caused by improper distribution of vapor flow in the bed. So thinking this is because of vapor cross channeling.
If it is channeling or flooding how can we deal with it?

More information:
Thanks a lot for all your suggestions, we have opened our tower found that steam deflector plate was installed wrongly, so steam was injecting directly into the packing, which caused packing to expand and that caused channeling in our tower. After rectifying this, now we don't face this problem.
18/11/2010 Q: What happens if we do not use steam for streaping and neither the slop lateral cut draw from the tower in our Vacuum tower? I would like to know the consequences for this type or operation. (3)
25/07/2010 Q: Are variable speed drivers ever used in pumps?
If not, why not?
09/06/2010 Q: In our atmospheric distillation unit , reduced crude recovery was constantly coming 10-16% @ 360 deg C. We increased the bottom stripping steam but we are unable to decrease beyond 10%. Are there any other ways to improve the efficiency? (6)
25/05/2010 Q: Is it possible to use the waste gas, exhausted from Cold Box (Nitrogen process), for combustion purposes in, for instance, fire heaters? Now, the oxygen supply in fire heaters is the atmospheric air while the waste gas, as oxygen rich gas, can be used during the revamp procedure. (4)
09/04/2010 Q: We want to purchase some process equipment like distillation column, heat exchanger, pressure vessel, reactor etc. To make a budgetary proposal we need some information regarding costing of those equipment. Can anyone help me how the costings can be made? Is there any reference for this issue?  
10/03/2010 Q: We want to install the roof cover on our waste water tanks and off gas treating system to reduce the VOC emission and odours. The diameter of our waste water tanks are from 14 m to 32 m. Since the corrosion consideration and strength of existing steel tanks, vendor suggests us to choice the aluminium dome cover. Would you please advise. (1)
03/03/2010 Q: What are the implications of shell side fouling on the pulling of a VCFE/Texas Tower (Platformer) bundle for cleaning? Our client is looking to pull a VCFE which has been in-situ for 16 years and I would like to find out if others have carried out a similar exercise and any impacts fouling may have had on the activity. (2)
05/01/2010 Q: In our refinery we are going to change our crude reception line by 36" diameter pipe. The previous line is of 16". The flow rate will be three times higher than the present condition. Our tank has 69 m diameter and 12.5 m height. My question is: will it cause problem in the floating roof tank during reception? Is any modification required? Is there a standard procedure? (2)
07/12/2009 Q: What is the retiring thickness that leads to the replacement of the process pipes of various schedules? Is there any standard? Or it is based on experience? (1)
18/10/2009 Q: We are going to install anchors in our furnace. We get all the required spacing of anchors for cylindrical radiation shell, overhead arch, convection breeching (roof) and stack, but we have no proper data relating to anchor spacing of conical part of the furnace. Can anybody help me in this issue?  
09/09/2009 Q: Our refinery is an old one. It already spent almost 41 yrs in operation. In this time frame we have changed our distillation column after 30 yrs and revamped topping furnace after 40 yrs. We have changed our exchangers, pressure vessels, tanks and other equipments as per inspection record and suggestion. Is there any rule of thumb regarding how often different types of refinery equipment should be renewed, e.g. after a definite period or number of operating hours? (3)
01/09/2009 Q: We are facing the problem of higher crude column top pressure in one of the our crude distillers. The problem gets worsened during hot ambient conditions and when bundles are in fouled condition and the same results in flaring/th'put reduction. The crude tower O/H is equipped with 06 banks of fin-fan condensers with each bank having 04 bundles (Total 24 bundles). The condensing duty is ~ 50 MMKcal/hr at design throughput and crude blend. Now, we want to expand the fin-fan capacity by adding one more bank of 04 bundles to reduce the column top pressure from ~ 1.2 to 0.8 kg/cm2g. However, we doubt that, this may aggravate the process side fouling as the velocity for each bundle will reduce. Also, the piping for new bank will not be symmetric and it may cause new bank to run cold & dirty. The present fouling pattern or performance of banks support this with extreme end bundles (last 8 bundles) taking less load and running colder than other 16 bundles. At the current load the inlet velocity is in the range of 24 m/sec. What should be the min recommended velocity in crude column O/H condnesers? What is the best strategy for expanding the capacity of crude column overhead condensers? (3)
21/08/2009 Q: In recent days we have found that in our refinery the bottom/lowest course of the crude tank is severely corroded, especially the lowest one metre. We intend to replace the bottom course without replacing other courses. the course height is 1829 mm. the diameter of the tank is 69 m. the thickness of the bottom course is 20.0 mm and the immediate above course thickness is 17.0 mm. The height of the tank is 12 m. We will also replace the annular plate and bottom plate. Can anyone help me which will be the right procedure to replace the course? (2)
23/07/2009 Q: Where do hairpin (u-tube) heat exchangers go to die? We are looking for a scrap heat exchanger to use for trials in our workshop in Essex, UK. Can you suggest anyone in the UK who deals in redundant hairpin heat exchangers?  
23/07/2009 Q: How should we size a PSV outlet line when we are considering liquid relief as the determining factor?
Our understanding is that if vapor is relieved then for PSV inlet line size, pressure drop is the design criteria and for outlet line size sonic velocity is the design criteria.
16/07/2009 Q: How can one fix minimum circulation flow and scheme for a pump which is undergoing in revamp, specially when flow is going to reduce after revamp? (3)
11/06/2009 Q: What is the advantage of heavy atmospheric gas oil draw in a crude column? Is it possible to provide a new heavy atmospheric gas oil draw for our crude column operating with 24 trays, diesel draw is between 11th and 12th tray, flash zone between 6th and 7th tray? Column operating pressure is 1.6kg/cm2 top. diesel draw temp is 300 degC. (1)
19/03/2009 Q: With some experts projecting crude prices to creep back up to $75/bbl by mid-summer 2009, should we expect to see a higher level of refinery intermediates (e.g., heavy gas oil, "lifted" DAO, etc.) being exchanged among "networked" refining facilities?  
17/03/2009 Q: How will impending changes in marine diesel specifications affect bunker and residual fuels? Is there a long-term shift away from bunkers and residuals? Will this result in some niche opportunities for refiners? (1)
23/02/2009 Q: What are the methods to estimate cracked gas production in Vacuum Column (or Heater)?
Are there any correlations in the form of other process parameters?
Can anybody suggest the literature regarding this?
07/07/2008 Q: Under what circumstances is it cost effective to revamp the FCC main fractionator so that the amount of heavy FCC naphtha feed to ULSD hydrotreaters can be increased while still meeting finished ULSD product flash and distillation requirements? Are most ULSD hydrotreaters designed with a three-product stripper using a fired heater, or is a simple steam stripper adequate? (1)
22/06/2008 Q: We have a crude preflash column where crude after being heated is flashed.
the column has three streams. One is the top which is light naphtha which is taken from the reflux drum via reflux pump as one stream. The other is sent as reflux on temp control The column has a fired reboiler.
A side cut is Heavy Naphtha below Hnaphtha cut is a pump around. Bottom is kerosene plus which is separated in another tower.
We wanted to reduce the EP of lt naphtha. We carried simulation on hysis and were getting the desired EP using HEPT OF 2 FT for CMR 1 as there is packed bed of 10 ft between LT and H naphtha we were getting five theoretical trays
on the plant we adjusted all perimeter as per simulation but we could not get even close to it the ep remained high. Increasing reflux severalfold could not achieve the end point.
We took delta p across the bed. It is low and pct flood predicted by Hysis is 16pct far from flood.
We reduced capacity but no avail. Could it be low flood which is responsible? We want to check all angles before we open it up. There are no gamma scan facilities available so we can't do a scan.
Can someone suggest what angle to look for?
22/06/2008 Q: How do you determine the cracking temperature for unknown heavy crudes in Atmospheric heater and vacuum heater? For vacuum heater does this cracking temperature depends on the vacuum and coil steam? Are there any lab methods or correlation methods to determine this? (1)
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)
18/06/2008 Q: Our crude vacuum distillation column bottom pump suction strainer gets full of coke. How can we prevent this? (4)
28/05/2008 Q: We've been quoted a revamp time for our FCC unit of 120 days, which is prohibitive.
Has any refinery got experience of FCC revamp involving shutdown duration of 35-45 days?
28/05/2008 Q: Can someone provide guidelines on the design of a vacuum column for light waxy atmos bottoms? Will it be any different than designing a vacuum column for heavy crude oils with high metals etc> The atmos bottom that we are considering is waxy with no metals and very low sulphur but we have to limit wax in the lvgo so that it is used as diesel.  
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? (2)
22/01/2008 Q: Can anyone tell me the average time it takes to clean a flare line please? (4)
03/01/2008 Q: How can we redesign a crude preheater for better efficiency? What is the pinch point of the total crude preheater train using simulation package hysys? How can we do pinch analysis in hysys? (1)
07/12/2007 Q: Can someone tell me how a Millisecond Catalytic Cracker works? (1)
16/09/2007 Q: In the crude coluumn , I want to put one more side draw. To allow for draw tray, how much tray does one have to actually remove from the column to accommodate this modification? (1)
05/09/2007 Q: How can we improve fluidizing in a stand pipe regenerator FCC? (1)
04/09/2007 Q: What are the typical steps to follow for the revamp of a hydrocracking unit? What is the typical duration for each step?  
04/09/2007 Q: Is designing wash section critical in vacuum column if my objective is to get only asphalt from vac column bottoms? VGO we will be selling as fuel oil.
Now it is a dry vacuum column. Is it possible to convert this into a wet vac column?
I am able to match the Flash zone temperature with HTSD data for RCO without assuming entrainment as mentioned by Golden in Deep Cut Vacuum feed characterization article. So can I assume the actual entrainment would be zero?
08/08/2007 Q: What procedure should be employed to ensure that FCC-LPG is on-spec for sulphur and mecaptants (and to meet copper corrosion specs) immediately following startups from turnarounds or outages? Are there any additional best practices for treaters? (1)
02/08/2007 Q: What is the plant downtime requirement for the revamp of typical Hydrocracker (Once through or Two stage)/Hydrotreater units? How can it be estimated during revamp design finalisation/preparation and what are the ways to scale it down to minimum possible? (1)
31/07/2007 Q: Recycle gas compressor of CRU had ammonium chloride salt deposition in its impeller vanes during regeneration activities. Can we wash the rotor with DM water or steam condensate without opening the machine. If yes, can you suggest some guidelines?

23/07/2007 Q: How can the capacity and efficiency of an existing deisobutaniser be increased? (3)
23/07/2007 Q: What are the opportunities for pinch technology in crude distillation units? (2)