Q & A > Mass Transfer
Date  Replies
23/02/2021 Q: In a sponge absorber why is absorption of LPG by lean oil (naphtha) an exothermic reaction? (2)
04/02/2021 Q: I work in a UOP licensed DHDS unit. It has one HP amine absorber to absorb H2S from recycle gas. At thr top of the column, a water wash facility with level tray is installed to wash lean amine from recycle gas. We are experiencing foaming. The water tray level quickly fills and goes to the next recycle gas knockout drum. Delta pressure of the column is also increasing and the level increases suddenly in the water tray even after isolating fresh water. The delta temperature between amine and process gas is 12oC. Drained liquid is milky in colour. Please suggest a remedy.

 		(3)
14/12/2020 Q: Why is there a need to use an air cooler in the overhead circuit of a distillation column? What's so special about it that a water based condenser cannot do it standalone? (3)
09/09/2020 Q: We have a sour fuel gas amine absorber where sour fuel gas from the refinery is treated with amine from the amine unit to strip out H2S. Sweet FG from the outlet of the absorber passes through a cooler then a filter coalescer to separate carryover amine from fuel gas. We are continuously getting water from the filter coalescer instead of amine. We have checked the cooler for tube leakage but no leak is observed, also the pressure of the fuel gas side is 0.5 - 1kg/cm2 higher than the cooling water. After checking the strength of a coalescer boot sample, almost 99% water is found. Is this a normal outcome or what are the probable causes of water formation instead of carryover amine? (5)
10/08/2020 Q: For a crude distillation unit, what should be the top temperature of the column, draw off temperatures for naphtha, kerosene and diesel, and the bottom temperature of the column? (2)
21/07/2020 Q: What thing(s) indicate the need to increase CDU stripping steam? (2)
25/06/2020 Q: What is the difference between unimodal and bimodal polymer?  
04/03/2020 Q: Could any one tell me what is the cost of refining a barrel of crude oil or how can i predict it for typical refineries ,as well as the forecast ,thank you in advance (4)
18/02/2020 Q: A boiler to produce low pressure steam
• Boiler has a rudimentary design. • Total volume is 1 m3
. • Check valve, pressure and level indicators are present. The check valve opens when the required pressure is achieved. It
can also be manually operated. • Mode of operation of boiler is unchanged- Half of the boiler volume filled with water, then fired. Steam builds up to the
required pressure. When the required pressure is achieved, check valve opens letting out steam. Once steam generation
begins, level of the water in boiler is maintained and continuous operation is achieved. • A flow measuring device is installed upstream to measure steam flow rate. • The start-up requires 352 seconds. • Due to severe clogging, boiler is swapped with a temporary one. The new boiler is double the size of the previous one.
The heat input rate and the check valve characteristics remain unchanged. • 400 seconds after firing the new boiler, it is observed that the pressure indicator is faulty. The level in the tank has shown
little deviation and the check valve has not opened. • What would be the most safe and efficient course of action? The boiler has emergency PRV, and is functioning at one
fourth of the pressure it is built to handle, and the maintenance of the clogged boiler will take 6 hours. If the issue with
the pressure indicator was diagnosed 1200 seconds after firing, with the check valve still being closed, would your
course of action have deviated from the previous one? If so, how? 		(1)
18/02/2020 Q: A refinery column that operates at 1.5kg/cm2g pressure. • The management decided to reduce the column pressure to 0.5kg/cm2g slowly within 15 days – this saves a lot of
money and improves distillation efficiency. • Financial statement shows there will be substantial increment in profit due to this. • At first, 1 air fin exchanger leaked, the operators isolated it. • Within one day, one more leaked, again it was isolated. • All exchangers leaked within 2 days
explain what went wrong here, and to suggest a way to tackle this issue. 		(8)
20/01/2020 Q: Hi
We have a design of a Vacuum unit where a slop wax line is going to slop wax pump. This line has a vertical leg of 35 ft the line is 6 inch but this vertical leg is 8 inch; the vertical leg has a level control which controls the recyle of slop wax
is someone familiar with this scheme; what is the logic/theory behind this?
 		(4)
01/01/2020 Q: My question is related to an amine absorber used to strip out H2S from fuel gas or recycle gas. We know thatthe optimum temperature difference between gas and amine is to be maintained at 8 to 11 degrees Celsius.

1) Why does absorption decrease when delta T is below 8 & above 11? Please answer for individual case.
2) Moreover, does only delta T matter or do individual temperatures of gas and lean amine also matter for determining absorption efficiency ?
3) If individual temperatures do matter then what should be the optimum range of both? 		(4)
15/06/2019 Q: What is the suitable configuration of Deisohexanizer column to produce Pharma Grade hexane? We have existing DIH column which was designed to separate C5 & C6 isomers from overhead, unconverted n-hexane from side cut as recycle and Cyclohexane, methyl cyclohexane, c7+ components from bottom of the column. Now, we are planning to reconfigure DIH column to separate Pharma Grade hexane. New column should be able to separate PGH during PGH production and should separate isomerates properly during normal gasoline mode. In this context, how should column look like in terms of draw locations e.t.c  
28/12/2018 Q: We are operating a small refinery processing sweet crude (less than 0.4 wt % sulphur). The crude is heated in a heat exchanger network and sent to a preflash column. The overhead from preflash column are condensed as naphtha and sent for stabilization after removing free water in overhead reflux receiver boot followed by coalescer. The naphtha is reboiled in the column and refluxed by a overhead stab in condenser. Vapour from the column are sent as fuel.
Recently when the column was opened up after one year of service the overhead condenser was badly corroded. In fact all the tubes had holes (condenser uses cooling water in the tubes). The strange thing which was noted that elemental sulphur embedded in the corrosion product covering the outside of tubes.
We are wondering where this elemental sulphur was formed? The overhead operating temperature is 100°F.
We are using antifouling agent in our crude but the vendor says that there is no possibility of elemental sulphur from their product.

Additional:
1. Preflash overhead goes through a prefilter followed by a sand bed coalescer. We have observed no emulsion and water haze after these filters and coalescers. However, we are recycling boot water to overhead condenser in the preflash. There is no water wash in the stabilizer as it is a simpler stripper with no overhead condenser and drum.
2. No outside naphtha is being processed; however, demin water solution is prepared with neutralizer which is injected in preflash overhead. We are wondering about this Claus type reaction that take place under these mild conditions without catalyst.
 		(2)
08/12/2018 Q: Prior to the use of simulators or for preliminary calculations, how the draw off temperature for a specific cut like gasoil or kerosene is determined using TBP data. (1)
08/12/2018 Q: I need to compare the current residue cut of my atmospheric distillation unit to the TBP/ complete Assay of earlier used crude feed. My question is how can i correlate both of them, how does the operating conditions /temperature and yields be compared with the TBP Analysis? If a process simulator like HYSYS can be of help.  
06/12/2018 Q: Crude oil desalter problem:
It is observed that during normal running of Crude oil desalter(2 stage in series), the Amperage increased from 45 to 90Amp. It was also checked that there is no water shot with crude(i.e. < 500PPM H2O). Immediately wash water stopped, still current doesen't comes down. Hence, wash water resumed and observed current at higher side. Evev, the crude oil type processed is also the same as earlier. What could be the reason for high current and suggest solution to bring down current? 		(4)
31/05/2018 Q: In distillation columns, why are trays more widely used than packings for vapour-liquid contact? What are the advantages of using trays over packings? (5)
05/05/2018 Q: In our Propylene Recovery Unit (PRU) why is reflux drum mounted above the condenser? It means condenser on ground floor and reflux drum above the condenser, but other distillation column generally condenser on top and reflux drum below the condenser. (4)
08/04/2018 Q: I have difficulty in drawing product from my side stripper of the atmospheric distillation tower. Whenever I raise the Stripping steam rate, this problem will occur. My initial suspect is due to the hydraulic limitation when the stripping steam is above a certain value. The technical reasoning would be when there is high vapor rate rising up the stripper tower, the vapor load creates high pressure drop across the stripping trays. Liquid flowing from the top will ultimate be restricted from flowing down the stripper tower and creates hydraulic limitation. Do you all agree on this observation? (3)
17/03/2018 Q: I have a question on determining if the atmospheric residue is lighter from the atmospheric distillation unit. I know I can compare the T5 distillation of my residue to see this has been lower than historical values... I think if I were to check the delta across my stripping section has increased with a constant stripping stream ratio, that'll probably give some indication too.
Does anyone know what other methods can be used to check if I am actually dropping any HGO or light molecules down to the atmospheric resid layer?

Conclusion:
Yes, I have compared the T5 of my residue and also the T5 of the vacuum tower feed and they are lighter. My stripping steam, FZT were lower than usual during those period while my FZP was higher. I think in conclusion, those should have actually caused the drop of lighter molecules to bottoms due to insufficient uplift of molecules. 		(2)
16/03/2018 Q: For a reboiler furnace in NHDT, is better:
to have reboiling liquid 34 m3/hr and furnace COT at 208 C or to have reboiling liquid flow at 40 m3/hr and furnace COT at 203 C?
Note: Reboiler furnace is the limitation for maintaining max throughput. 		(7)
10/03/2018 Q: At Temperature above 370'C in a CDU? What cracks?
- Diesel? (Asked b/c FBP of Diesel is 370'c)
- Ends heavier than Diesel? 		 
03/03/2018 Q: Temperature of the CDU feed is always less than 370'C because temperature further than that will cause cracking. Cracking of what? Cracking of Diesel? Or cracking of heavier ends? I'm asking because FBP of Diesel is 370'C. (4)
22/12/2017 Q: Have anyone use platforming continuous catalyst circulation technology experience catalyst plugged in the bottom of Reforming reactor after turnaround? What may inhibit the catalyst flow to the regeneration section from bottom of reactor (catalyst collector)? (3)
04/11/2017 Q: How do you calculate overflash in a crude distillation column? (2)
21/04/2017 Q: How can I find the amount of flow passing through a control valve at a given output? (3)
20/04/2017 Q: What is the relation between the amount of overflash used in a vacuum distillation tower and the stripping steam injected at the bottom of this tower? (3)
20/04/2017 Q: For a cooling top pumparound for a vacuum tower, which is more useful: to use a larger flow rate (140 m3/h) at higher temperature (78C) or use smaller flow rate (100 m3/h) at lower temperature (70C) (2)
12/04/2017 Q: In my CDU unit, there are two type of feedstocks -- sour crude and sour condensate. I noticed both Units have same configurations -- except CDU have desalters and charge heater while Condensate Fractionation Unit does not have them. While crude feed is vaporized up to 60% before charged into CDU column (360degC), condensate feed is heat up only up to 140degC where it is still 100% liquid phase.
My question is,
1) Why in CFU configuration, it does not requires Charge Heater at upstream of Condensate Fractionation column?
2) What is the factor determining the vaporization rate of condensate/ crude feed into the fractionation column? 		(1)
11/03/2017 Q: Why truf type distributor are used over light LVGO tray?
 		 
21/02/2017 Q: I want to load about 14 ton of CMS (Carbon Molecular Sieve) into a PSA Nitrogen Producer tank.
The tank is 5 meter tall with 2 m in diameter.
What is the best, simplest and fastest method to load the pellet of CMS into that big tank?
I consider this mortar screw pump and connect it to a long / extended hose to reach the top of the tank.
http://www.penobet.ru/images/prod/sosna7pro.jpg
Within removing the agitator inside the hopper and used VFD/VSD to slow down the motor speed of Screw or Pump mechanism, will the screw still crunch or crush the CMS pellet?
Sorry for my English. 		(2)
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. 		(4)
22/12/2016 Q: We are operating CDU/VDU @ 110% throughput.
We have a Demister Pad installed at the top of the vacuum column.
The DP of the demister pad is increasing @ ~1mmHg/10 days. This is resulting into higher Flash zone pressure causing dropping of Vacuum gas oil into Vacuum residue. We operate the column at 23 mmHga top pressure.
Also we have noticed chlorides in our Vacuum diesel stream (First side cut of VDU) in the range of 10-20 ppm w.
What can be the cause of this fast increasing DP and what measures can be taken to arrest that?
(9)
12/12/2016 Q: In our Naphtha Stabilization unit, feed after preheating leaves the HE through a 10" dia pipe and then immediately split in to two vertical risers of 4" dia and again joins back to a 10" dia pipe before entering the stabilizer. What is the purpose of this risers with reduced dia? In P& ID it is mentioned as two phase flow. (2)
05/08/2016 Q: How can chimney tray pressure drop be estimated? (4)
06/06/2016 Q: Why is stripping steam used in crude distillation column? (5)
30/05/2016 Q: What is the molality in a solution containing 0.30 Kg mole of solute and 600 kg of solvent?  
11/05/2016 Q: LPG amine absorber is design for 15t/h sour LPG from crude unit and delayed coker unit and we are running it at 20t/h. Amine flow rate is 24t/h for absorption. Column operating conditions is 13.8kg/cm2 and 36degC. Delta T between lean amine and LPG is maintain between 5-8degC.
We are facing problem of continuous Hydrocarbon carry over in Rich Amine from absorber. What can be the possible reason? 		(5)
07/05/2016 Q: What is the definition of Overflash in a crude distillation column? What are its advantages and disadvantages? Does it ensure liquid flow between gas oil draw off tray and flash zone? (7)
28/01/2016 Q: What is the purpose of pre-heating the sour water feed (by exchange with the bottoms of the column) before entering the sour water stripper, if it will increase H2S content and water? (6)
11/12/2015 Q: The bottom part of our atmospheric distillation tower operates at 350oC, and we are giving the superheated steam to the column at around 420-430oC. Let's say, we want to decrease the temperature of superheated steam to 400oC but still it is superheated steam of course. Might it have any effect on the distillation of the products or the quality of the products to decrease the temperature in this manner? (7)
16/06/2015 Q: We are observing high CS2 content in our straight run naphtha. This is not on regular basis but frequent and sometime it goes up to more than 20-25 ppm also. Please advise what can be source of such high CS2 content in naphtha intermittently.
The sources may be narrowed down to:
1. Presence of CS2 in Crude itself- Please suggest the probability of the same and if any known crude with high CS2?
2. Since CS2 formation requires very high temp, can it be formed in crude heaters? or any other process?
3. Though probability is less, can it come from recycle hydrotreated naphtha? 		(2)
26/05/2015 Q: Usually for protecting trays/column internals from any upsets, an upthrust of 1 or 2 psi is considered. But if the vapor/liquid traffic inside the column is known, how to estimate the upthrust during normal operation? (2)
26/05/2015 Q: We have one solvent regneration column which has 4 baffle trays and below which there is a stub-in reboiler at the bottom. Also at the bottom, steam sparger is provided(we think same might have been provided to reduce the boiling point of the column bottoms liquid). Column operates at vacuum (-0.2 kg/cm2g). Column bottom temperature is 187 deg c.Fresh solvent is taken out from top and heavies are removed from bottom intermittantly.The stub in reboiler utilises MP steam(16.5 kg/cm2g) while sparger steam enters at 127 deg C & 1.5 kg/cm2g pressure. The problem is, tubes of this bottom stub in reboiler fail every year and many times, tube bundle is replaced. In recent inspection, the bottom two trays were also found to be fallen & accumulated at bottom.Wanted to know, whether is it a good practice to push steam through sparger in the liquid pool over the bundle of stub in reboiler? And, column bottoms liquid is at 187 deg C & steam enters at 127 deg C. Will that cause steam getting superheated and exert forces on tube bundle & trays above? what could be the possible reasons for both failures and what should be done to avoid them in future?Also, would appreciate any good material or information on mechanical stregthening of trays and various calculations involved. (5)
12/11/2014 Q: How to calculate N2 requirement (available at 7barg) to pump horizontal closed drain vessel liquid (located below ground with dimension ID 6000mm x S/S 6800mm) to atmospheric flare KOD at a elevation of 7.5 meter. (1)
15/10/2014 Q: Can you please advise some literature sources or design guidelines for Naphtha Stabiliser design. (1)
18/08/2014 Q: In an Reformer Stabilizer Debutanizer Column, we do regular water washing of the column to get rid of the ammonium salts. We do this procedure by reducing the throughput and pressure of the column and produce off-spec reformate during the process.
We do like to ask if any refiners have a practice of introducing steam into the column while the unit is online to clean the ammonium slats deposits in the column and condenser? If yes, what are the concerns and precautions to be observed?

Additional:
I would like to confirm that what you had mentioned. HIGH PH contributing to the severe corrosion. We have a similiar system upstream(the first column for the FRN Feed) and found severe corrosion in the overhead system of the distillation column and we found that the pH was very low and ammonium salts, in the range of 4.5. Hence,we are injecting a highly basic chemical to increase the pH and are currently maintaining 9 pH. But to our confusion , we are still finding a very high amount of corrosion. If what you mentioned is true, what we did in the system is not going to help us but rather worsen the condition?

Thanks Stephan, Could you please elucidate on the corrosion due to high pH? We have a Debutanizer Column , the first column in the Aromatics Complex which is severely corroded in the overhead due to ammonium salts. The feed is from the refinery , Full Range Naphtha. We had initially of an pH of less than 4. Then we injected an chemical to boost the pH and are currently mainly in the range of 9 pH. But the corrosion is still not under control. Could the high pH be one of the concerns to look at? 		(2)
20/01/2014 Q: I am currently working in diesel hydrotreater plant. The end products are naptha, kerosene and diesel.
According to the lab reports the sulphur content in naptha is 2.7ppm and that in kerosene is 0.5ppm. Kerosene being a higher molecular weight fraction should have higher sulphur content. What is the correct explanation for this? 		(7)
05/09/2013 Q: We operate our DCU main fractionator with Top Pr. 0.57 Kg/cm2g & Top Temp. 99 Deg C. We process VR with more than 5000 ppm normally. Recently column DP fluctuated a lot and we suspected salt deposition in trays. Steam was increased and DP become normal. Queries are:
1. How to calculate salt sublimation temp? What parameters I need to look into?
2. How to estimate salt quantity?
3. What are reasons for salt generation in system?
4. What kind of salts are expected - organic or inorganic?
5. Is it possible that if salt sublimes once and again it becomes vapour once temp increase ie. is phase reversal possible?
6. What are industry best practices to remove salts deposited?
7. Is there any way to avoid salts formation in system or avoiding ingress?
8. Any crudes responsible for high salts or its caustic dosing at crude desalters?
 		 
08/07/2013 Q: What is typical vacuum column off gas composition? We operate our Vacuum column at 410 deg C and 55mm Hg top pressure, recently we are getting high concentration of CO (about 40-50 ppm) in seal pot area where off gas condensate is washed.  
05/07/2013 Q: We have a liquid product named HCGO; ideally it's 280-430 cut material. We are analyzing its distillation by D86 method. same liquid sample when tested with D1160 recovery results were different. Since there is huge difference between 350+ recovery points we are confused as to which method to follow.
1. How to compare D86 & D1160 values - which are more accurate?
2. What is the range of D86 & D1160 test methods wrt. recovery points?
Below is table for reference. Both the results are reported up to atmospheric values and in DegC. (OOR = Out of Range)

S. No Distillation D-86 D-1160
1 IBP 287 280
2 5% 339 337
3 10% 347 354
4 30% 363 385
5 50% 374 403
6 70% 384 420
7 85% 396 437
8 90% OOR 446
9 95% OOR 461
10 FBP OOR 497 		(3)
11/02/2013 Q: In one of our FCCUs we have an automatic pneumatic fresh catalyst injector to load the catalyst from the catalyst tank to the regenerator. Some weeks ago we start having problems with the fresh cat injection. After inspection of the pneumatic injector, we could see a very hard deposit on catalyst in the injector valve. We found some other catalyst agglomerates in the tank. We believe it could be formed due to a leak in an steam line in the fresh catalyst vessel.
After several weeks and trials we have not been able to run again with the pneumatic injector and we must load the catalyst manually, straight from the tank, through the by-pass line of the pneumatic injector. After a very exhaustive inspection, everything seems to be OK mechanically in the all the system (vessels, piepes, etc). The catalysts deposits in the tank have disappeared. We are also having several fluidization problems in the loading pipe to the regenerator, both using the pneumatic or the manual loading.
Have anyone experienced similar problems? Could the properties of the fresh catalyst be related to the problem (losses on ignition, humidity, atrition, PSD)? 		(1)
10/12/2012 Q: What is the experimental relationship between 20% Diethanol Amine and 45% MDEA for H2S Absorbtion? (2)
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.
(3)
17/09/2012 Q: What is the expected life of fin tube of overhead air cooler of Atmospheric distillation unit? (1)
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.
 		(1)
22/01/2011 Q: To what extent can we blend fuel oil into gas oil without affecting the viscosity characteristics and maintaining the flash point specifications for gas oil or to keep them within the allowed limits?

Additional info:
First of all we don't have neither FCC, Hydrocracker nor VDU...we only run a conventional CDU
the objective here is to maximize the yield of gas oil...(we call it solar in our national markets) by extra stripping out from fuel oil or residue...the question is; Is there any equations or experimental methods to calculate or estimate the resulting viscosity and flash point of either the gas oil or fuel oil?
Thanks a lot. 		(4)
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. 		(2)
06/12/2010 Q: We have a methanol-Water stripping column, which uses direct injection of LP steam for stripping.
I want to know if it is better to use reboiler instead of steam injection.
Is there is any advantage in using direct injection of steam in methanol-Water stripping column? 		(3)
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. 		(5)
07/10/2010 Q: Our Sour water stripper unit is a two stage operation. The first tower operates at 7 KSCg pressure and second tower operates at 0.8 KSCg pressure. Recently we have encountered a strange problem. The color of the stripped water is milky white and also looks hazy. The overhead temperature of the second tower is running high, 100 C (Normal is 90C). Please suggest some solution. (2)
02/09/2010 Q: I have a query regarding distillation. How is it decided whether steam should be used or a re-boiler should be used in a distillation column. I am in DHDS unit. The finished diesel stripper uses direct steam injection as stripping media where as the stripper in Pre de-sulfurisation unit of Hydrogen generation unit (steam reforming) contains a reboiler. Both columns intention is to strip out light ends and also some amount of H2S. (3)
15/08/2010 Q: we have an induced draft double-flow, cross flow cooling tower...using air to cool condensate water.
the tower fans has two speeds; low & high...In winter, usually low speed is used as the air temperature is low enough (Egypt), so that it reduces the water temperature by an acceptable manner. However; the water is found to exit from where the air enters -the louvers- while, through high speed operations in summer, this doesn't occur. 		 
08/07/2010 Q: We have a very strange problem, it's that the desalter outlet crude has greater salt content than that of the inlet... the lab examinations proved that more than once...this always happens when the injection water is cut off-while switching from a tank to another. What could explain this?

Additional info/response:
1. We cut off water while switching between tanks because of the existing water accompanied with the crude from the new tank; I mean the first 30 minutes after switching to a tank, the crude has too much water to inject more.
2. How could the NaOH type could affect this situation? 		(10)
05/07/2010 Q: What makes outside shapes of distillation columns differ from one another? i.e. shape of pre-flash differs from CDU, CDU differs from VDU? (3)
01/07/2010 Q: What is the maximum allowable figure of own use fuel and losses (OUL) in terms of percentage (vol%) of crude charge processed for a hydro skimming refinery? (4)
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)
18/04/2010 Q: We are using 20% DEA for removing H2S from gases in our refinery. How much 1% DEA will remove H2S if Rich amine loading is kept 0.33 mole H2S/Mole DEA for total circulation rate of 220 m3/hr as want to increase DEA Concentration. How can a relationship between Rich Amine Loading & Concentration be established? (1)
19/02/2010 Q: I am working in DHDS. I would like to know the purpose of Carbon filter in Amine Recovery Unit. We use stripped water from Sour water stripping unit as wash water in DHDS over head coolers for dissolving ammonium salts. My query is if there are little amounts of ammonia and H2S in stripped water, and if we use the same stripped water in DHDS, will there be any problem in amine quality or will there be any effect in the quality of acid gas generated from ARU? We are facing the problem of increase in differential pressure across Carbon filter when we take stripped water in DHDS. (6)
06/02/2010 Q: Recently we are facing topping unit furnace inlet becomes lower than expected. The normal temperature is 215-220 degree centigrade. But now we are getting only 200-205 degree centigrade. What are the probable reasons behind this? And what measures should be taken to overcome the problem? (6)
06/02/2010 Q: When calculating heat exchanger shell thickness according to pressure vessel formula it is found that the required thickness always much less than the original existing exchanger. I want to know the reason behind it. (2)
06/02/2010 Q: In our Topping unit generally each heat exchanger has one shell inlet and one shell outlet except reboiler exchanger. We have two such exchangers. My question is why those reboilers have two shell inlets and two shell outlets? (2)
29/01/2010 Q: I am engineer in a CDU. The lube vacuum column used stripping steam of 25 psig to 750F, the superheater will go to maintenance. Is it possible during the maintenance to use stripping steam of 50 psig to 750°C in this tower? This tower produce distillates for lube naphthenic and paraffinic. (3)
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)
24/12/2009 Q: Does the top naphtha section of the crude column perform distillation as the other sections do?
The Del.P across this section does not seem to be a normal one to me. Top three trays functions at nearly 200mmH2O.
I see this section as a condensing/absorption section more than a distiller.
Am I correct? 		(2)
19/12/2009 Q: What is meant by vapor and liquid loading? What is its significance? (2)
14/12/2009 Q: Our furnace has 4 pass flow. Crude enters the furnace by 4" tube in the convection section. Then it changes its size by 5" X 4" reducer in the radiation section. It again changes its size outside the furnace and now this time by 8" X 5" reducer to a common header of 12" pipe line. This pipe line by a 16" X 12" reducer connected to the 16" pipe line that goes to column. My question is why we are using so many reducers in the process line? (3)
23/10/2009 Q: We have 4 hydrogen gas cigars (reservoirs). On the inlet and delivery line there are valves which stock is limited. Now we want to buy some new valves that match the following service:
operating pressure: 70 to 80 bar
design pressure: 130 bar
operating temperature: 41 degree Celsius
design temperature: 80 degree Celsius
The valve will be used for both sides operation. Can anyone help me by informing what kind of valve should be used in this service and preferably the name of valve manufacturer? 		 
31/05/2009 Q: what is the purpose of a chimney tray in a hydroskimming refinery's crude distillation column operating at atmospheric pressure? (1)
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)
16/10/2008 Q: Why is the non return valve fitted on the horizontal pipe line rather than the vertical one? (2)
23/09/2008 Q: I am working a project where I am trying detect phase changes. The project consist of detecting phase changes from water to butane by using flow meter density detectors. This idea is only for ideal case, but the reality is that, caustic may be present. Here is where the issue comes.
The question that I have is this: what method should I use to detect different phases. For example, mixed water and caustic? mixed Butane and Caustic? Again, the point is to detect phase density changes from water to butane. 		 
01/08/2008 Q: How can I design sizing of a jet mixer? what are the factors that determine its efficiency? Can a jet mixer also operate with Nitrogen? And how to calculate the consumption of Nitrogen? Is it better than conventional mechanical agitators for highly viscous fluids with congealing nature? (1)
11/07/2008 Q: How effective are the latest automation & control systems for ULSD hydrotreaters? Are they making a significant contribution in producing on-specification distillate product (< 8-10 ppm sulphur)? What is the feasibility of "extending" these control systems to upstream feed-stream distillation systems (i.e., tighter control of hard-to-remove refractory compounds entering hydrotreater)?  
07/07/2008 Q: In general, where has the influence of good fractionation allowed for significant improvements in meeting stringent petrochemical product specifications (e.g., propylene, styrene, etc.) at higher charge rates? Besides the recent improvements to fractionation column internals, what is the extent to which automation & control systems can be leveraged to deliver higher efficiency, run-lengths and resistance to corrosion in product recovery trains?  
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)
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)
20/03/2008 Q: dP across Gasoline merox reactor is shooting up.
Considering the financial year targets, Outage of the reactor in the near future is of remote chance.
Is there any chemical which can be used online for washing of Gasoline Merox reactors? 		(1)
21/01/2008 Q: How can I predict HETP for Sulzer's structured packings (BX, Mellapak 250.Y or EX) when reflux is not total, i.e., when some distillate is taken off (e.g., 10, 20, 50 or 75 %)? Does it depend on the mixture to distill or is it an inherent characteristic of the packing? (2)
06/09/2007 Q: In the off gases from our vacuum distillation column hydrogen % has been up to 30-35% by volume.This vacuum unit is mild severity dry distillation with designed VGO end point of 510 deg C.
The overhead boot water PH also remains on the lower side (~5) even though the neutraliser is added in large quantities (more than 100 ppm). The same neutraliser has used earlier for the same type of crudes.
Has anyone had this type of experience? What may be the reason for the same? 		(1)
22/07/2007 Q: Are there any recent alkylation projects that you can comment on where mass transfer efficiency improvements showed significant reductions in required acid consumption? Also, what recent improvements have resulted in reduced water wash or caustic wash requirements? (5)
22/07/2007 Q: Can you comment on advances in tray and packing design software for modelling mass transfer and heat transfer effects in a fractionation tower? Can you briefly site any recent refinery or petrochemical product-recovery optimisation projects where actual separations were accurately simulated? (2)