Q & A > Heat Exchangers
Date  Replies
24/03/2021 Q: We have a UOP semi reg. reforming unit, working since 1975. There are no caustic solution injection points or circulation during regeneration procedures, so we want to install a caustic injection point in the upstream air cooler (inlet temp. about 200 degC and outlet temp. about 55 degC ) .
Is there any reason to install an injection point 1st in the upstream air cooler and a 2nd downstream, or do we just inject caustic solution upstream only? 		 
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)
13/12/2020 Q: In our DHDS plant (Axens licensor, revamped in January 2018 ) with both a hot high pressure separator and cold high pressure separator, we are facing several tube leaks(A179-CS tubes ) in our stripper feed/stripper bottom exchangers (life three years).Corrosion is mainly on the stripper feed side and corrosion is due to localised under-deposit corrosion on the OD side of tubes near the floating head tubesheet, probably due to carry over of water and salts from upstream separators. Our hot separator is operating at 40 ksc and 90 degC operating temperature against the design 100 degC. In the same plant we are facing severe choking issues in our stripper overhead fin fan coolers where a complete header box was found choked with deposits. Around 76 % of the foulant collected is iron, and ammonia is also present. Has anyone faced such issues? Is operating the hot seperator at lower temperature the cause ? Has anyone used Alloy 825 tubes for stripper feed /stripper bottom exchangers?

 		(7)
31/10/2020 Q: Is there a practical solution for converting HPS to BFW? for some reason, we can only access HPS while we need BFW for temperature control in the steam reformer. (1)
19/09/2020 Q: We are operating an aromatic recovery unit producing benzene and toluene. The extraction section uses Sulfolane as solvent. The extract is stored in a charge day tank and is used for charging the benzene column. To remove olefins from the feed, there is a clay tower prior to the benzene column that operates at at inlet temp of 170 deg C and a pressure of 13 kg/cm2. There is an exchanger for heating the clay tower feed (tube side). We are observing a frequent issue of plugging in this exchanger. This leads us to shut down the fractionation section for almost a day every five months for cleaning/replacing the tube bundle. The olefin content in the light reformate feed varies between 5% and 7%. Is there any way this issue can be resolved? Is the olefinic content in the feed too high? The plugging material seems black in colour. Is there any method that can be used for identifying the fouling type? Is is it due to polymerisation of olefins? Any solution to avoid such frequent plugging in this exchanger? (10)
08/09/2020 Q: We have a reboiler whose shell was uninsulated. After insulation, I want to calculate the energy saved (heat saved). Temperature on the reboiler shell surface is ~155oC; on the insulation it is 40oC. Glass wool insulation is installed. (1)
30/07/2020 Q: In our hydrogen generation unit, a waste heat boiler functions to recover reformer O/L heat to produce HP steam. Boiler is single pass shell and tube exchanger with fixed tube. Since last year the boiler is not able to recover heat upto expectation as indicated by the raised process gas O/L temperature. The process gas O/L temperature is now around 288oC instead of 265 oC earlier. In the last 2 shutdowns the tubes have been cleaned thoroughly from inside but no benefit observed. Now it is suspected that there is fouling (maybe of silica) on the shell side. There is no provision to open and clean the shell side assembly. Is there is any technology available for online removal of such fouling (maybe some kind of chemical cleaning)? (1)
25/06/2020 Q: What is the basis for choosing a pressure controller instead of a temperature controller for steam heating? (1)
19/02/2020 Q: In our refinery we have 2 atmospheric crude distillation units:
Unit 1
Fired heater stack reads 550C

Unit 2
Fired heater stack reads 440C
Can I know what is the accepted range ?
 		(4)
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)
15/02/2020 Q: Why are most coker furnaces box type with horizontal tubes? Coker furnace heat duty is comparatively lower than a crude heater's, still they are horizontal ones. We have 9 heaters in our refinery for a coker with all of them as horizontal types. Any ideas on selection criteria ? (3)
05/01/2020 Q: The last time we opened the fired heaters of the Platformer units, we noticed lots of dust accumulating on the tubes. We are looking for ways to externally clean the coils online.

Is there a way to do it with our internal resources?

If not, what are the companies that offer this service?

(3)
17/12/2019 Q: In Hydroprocessing units, in case of a Leak in the Breech Lock Exchangers, can maintenance be done without reducing System Pressure and without stopping Feed to the Unit? (3)
08/11/2019 Q: We are operating cooling tower with circulation rate of about 10,000 m3/hr. Recently a case of oil ingress occurred through one of the coolers in a process unit. This oil ingress resulted in increasing the cooling water supply temperature from 29 degC to about 36 degC. Although oil content in the cooling tower has been reduced to below 10 ppm by appropriate chemical dosing the problem of high CWS temperature still persists. Cooling tower fans and CW distribution through fills have been checked and found to be working fine. Can anyone suggest some measures for reducing this CW supply temperature back to normal? (2)
08/11/2019 Q: We are operating cooling tower with circulation rate of about 10,000 m3/hr. Recently a case of oil ingress occurred through one of the coolers in a process unit. This oil ingress resulted in increasing the cooling water supply temperature from 29 degC to about 36 degC. Although oil content in the cooling tower has been reduced to below 10 ppm by appropriate chemical dosing the problem of high CWS temperature still persists. Cooling tower fans and CW distribution through fills have been checked and found to be working fine. Any measures for reducing this CW supply temperature back to normal?  
19/10/2019 Q: This is with reference to High pressure exchanger overhauling job being carried out at DHT unit during ongoing Turnaround Shutdown. During Shell side combined hydro testing of Effluent-Feed Hot Exchangers bank (90E03A,B,C,D) to attend suspected leaks, cracks found in one of the exchanger (90E03D) tube sheet near Pass partition plate weld joint. Please refer attached photographs for location of cracks observed and also attached exchanger drawings. Thickness of Tube sheet is 372 mm and metallurgy is SS 321. Presently, grinding of T/s Crack location was done up to 15 mm and still crack exists.

Prior to finding cracks, profuse leaks from some tubes (67 nos in 90E03C, 6 no in 90E03D where T/S cracks found) were observed during hydro testing @ 127 Kg/cm2 (HT Pressures: Shell-127 Kg/cm2. Tube-227 Kg/cm2). These leaky tubes were plugged with SS 321 plugs using TIG filler wise ER347 and subsequently hydro test was done during which one crack in T/S observed.

In this regard, we require urgent guidance to understand repair methodology/testing etc.

(Photos & video i want to share but unable to do)
 		(1)
07/10/2019 Q: What are the alternatives to hydrojetting to clean heat exchangers in a refinery?

Are there any chemical cleaning solutions available to clean after bypassing the exchanger?

Thank you 		(4)
01/10/2019 Q: Hello,

In our refinery we have an alkylation unit with HF and in recent dates we have had many problems with the acid vaporizer of the HF regeneration column (acid leaks from the tubes). The tube bundle is monel 400 and the heating medium is tempered medium pressure steam. Do any of you have similar experiences and could you help us find the failure mechanism?

Thank you.
 		(2)
23/08/2019 Q: What is permissible limit for bending of arbor/wicket coil in CCR box type fire heaters.
 
16/02/2019 Q: When our VDU column products, vacuum slop and vacuum residue were tested for H2S it showed H2S presence >10 ppm.What could be the possible reasons for high H2S?
We are maintaining VDU bottom level and temperature low to avoid cracking still H2S reported is high.Coil steam and Velocity steam were increased and kept 120% of the PFD values. Chances of exchanger leak was also checked and observed no leak. 		(4)
16/02/2019 Q: In our refinery Crude heater when open it we see moisture on whole pipe. Can you explain the possible cause for that? (1)
18/01/2019 Q: I have a problem with time consumed in purification through distillation. My distillation column consists of 27 feet 12" column with paul rings as packing components.
I have a reflux at 17 feet in column, that comes from the two condensers of 17 meter square and 10 meter square. I do distillation by two stage water ring vacuum pump with booster attached. I get the vacuum of 735mm/Hg.
What should be the reflux temperature that goes back in column? Or in reverse, what should be the temperature difference that goes back in column and at the bottom? 		 
25/09/2018 Q: Our naphtha sample from crude distillation unit went off on chloride content with result showing 1.3 ppm.So we checked organic chloride in our crude tank. The result showed presence of organic chloride in that particular crude tank. So that tank is kept blocked and we resumed to our normal operation.
We did many brain-stroming and looked for solution.
Can the experts in this forum please suggest how to process this crude having high organic chloride. Is there any chemical treatment available. How can this problem be solved? 		(6)
28/07/2018 Q: We are using a fuel gas fired heater with 8 burners and an fd fan.
How do we increase the heat transfer of radiant zone?
it is currently 60% and we wish to take it to 75%. 		(4)
21/07/2018 Q: What back flush procedures are available for cleaning a heat exchanger?
Feed is Meta and ortho xylene on cold side and eulibrium conc of xylene on others.
What are the suggested ways for packinox online cleaning procedures? 		 
19/07/2018 Q: Can there be internal mechanical damage in pakcinox heat exchanger?
if so under what conditions and how to check it?
the temp range is 380 to 120 and 105 to 335.
(1)
19/07/2018 Q: We are having some fouling in our packinox plate welded heat exchanger. Are there ways to do the cleaning without taking any shutdown?
Also what could be the fouling materials ?
The Heat exchanger plates are stainless steel s321 adn the feed is mainly c8 aromatics with some c7 and c9
gas is also used in the exchanger mainly containing hydrogen and ethane
The temps are 105 and 334 for cold fluid and 120 and 384 for hot side
 		(6)
16/07/2018 Q: We have two Similar alfalevel packinox plate welded heat exchangers in our unit.
One has a hot end approach of 38 while the other has 52 degrees
what could possibly be the reasons of this difference?
The process are similar in both with same streams and similar feed rate
 		(5)
16/07/2018 Q: What are the factors affecting the efficiency of an Alfalaval Packinox plate welded heat exchanger?
How can the efficiency be improved
 		(2)
27/06/2018 Q: How do we calculate the pressure drop of the inlet and outlet line of the reboiler? (2)
31/05/2018 Q: What is the approx. percent efficiciency/effectiveness of a shell and tube heat exchanger, double pipe heat exchanger, plate heat exchanger, cooling tower and regenerative heat exchanger?  
22/05/2018 Q: We're experiencing an increasing loss of heat transfer efficiency in our shell and tube heat exchangers. Has anyone found any technologies for cleaning exchangers online that does not require a shutdown of the distillation unit at all? Something for both sticky/polymeric as well as water scaling would be most desirable. (8)
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)
03/01/2018 Q: I am currently working in a project which includes a decrease in the operating pressure of the stripper in the hydrobon unit (hydrotreatment of naphthas).
Due to this decrease the temperature on top of the column will decrease too and the area of the aereocondenser at the top of the column won't be enough to achieve the desired temperature.
For this reason I am designing a new trim cooler that will use cooling water to achieve the current temperature before the liquid/gas separator. To avoid revaporization downstream the trim cooler will have to cool down both the vapour and the liquid stream.
The inlet current is 7.300 kg/h with liquid phase stream being 6.000 kg/h.
I have simulated it with Aspen EDR and the resultant heat exchanger will have to operate 40% flooded in order to cool the liquid phase stream.
To achieve and control the level of flooding in the trim-cooler two ideas come to my mind: Level control and dam baffles.
This is the first time that I design a trim-cooler but I have checked out the designs of other trimcooler and I have NOT seen any level control instrumentation or dam baffles.
Can anyone familiar with the design of trim coolers comment please? 		(1)
28/12/2017 Q: We want to increase the capacity of the stripper in our hydrocarbon unit. There is an aerocondeser for the stream leaving the top of the column. We want to increase condensing capacity by means of a trim cooler that would be placed next to the condensers.
It will receive a total of 7,3 tones/h, 1,3 t/h vapour and 6 ton/h liquid.
I have simulated with ASPEN EDR the new trim-cooler that will operate with cooling water (tubeside).
To avoid revaporization downstream of the trim-cooler the liquid needs to be cooled down as well as the condensing vapour.
The software indicates that the required area for cooling the liquid is 45% of the total number of tubes.
I am specifying 30% cut baffles but doing a quick number tells me that liquid will just pass and there won't be any flooding.
Has anyone ever designed a trim-cooler? How do you accomplish the flooding of the heat exchanger?
There are several options, I find that the most suitables ones are:
1)A dam baffle that will flood the shell until the desired level.
2) A level control loop (level transmitter control valve)
We have other trim-cooler installed in other units, hydrocracker for example, but I have reviewed the trim-coolers drawings but there is not dam baffle or any level controlling loop.


 		(4)
26/12/2017 Q: We have SS321 tubes for one of the furnaces. After welding of the SS321 tubes, what is the recommended PWHT cycle? I understand that to avoid Knife line attack in SS 321 and so to dissolve Chromium carbide and precipitate Titanium carbide, PWHT is done within 850 DegC to 1250 DegC. Some procedures recommend for 2 heat treatment cycles (1050 DegC 1 hr soaking with water quenching and then 900 DegC 4 hrs soaking with water quenching) whereas some procedures ask to do one heat treatment (1050 Degc 1 hr soaking with water quenching). I also saw a procedure asking for 900 DegC with slow cooling (air cooling) and not fast cooling (water quenching). So, I request you to provide clarity in number of heat treatment cycles, soaking temperature, soaking time and quenching medium (air/water) and its metallurgical consequences ?  
15/05/2017 Q: Our CDU overhead air cooled heeat exchanger is designed with 156 tubes and 3 passes. we have recently shutdown the unit to plug 32 leaked tubes:
- 20/52 tubes plugged in pass 1
- 12/52 tubes plugged in pass 2 .
We would like to estimate the effect of tubes plugging on the overhead ACHE performance by simulation (example wtih PRO II ).
How could we do that ?
(2)
15/03/2017 Q: In our NHT unit, tube material of stripper Column Overhead air cooler is SA-179 which is low carbon steel. So, if we use type SS 321 instead of SA-179 then will it be more sustainable in the wet H2S and wet HCl environment? (3)
22/02/2017 Q: Does anyone know about the economic feasibility of Organic Rankine Cycle in Crude Distillation Unit? We are having sub-cooled condenser duty of 20-24 GKcal/hr with overhead temperature in range of 120-130°C. (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. 		(4)
12/01/2017 Q: We are currently designing a new grassroots unit for diesel hydrotreater (DHT). There are 2 different opinion when it come to hydrogen mixing point: either it is mixed before or after combined feed exchanger (CFE) .
The view for the mixing point to be after CFE have concern about polymerization or faster fouling inside the CFE while the view with mixing point before CFE saying the impact will be totally the opposite.
What is the basis/philosophy for DHT design on where to put the mix point? 		(8)
25/12/2016 Q: In steam generator why the CBD line take out from high point than IBD? (4)
24/09/2016 Q: We are using Superheated HP steam (P-38 kg/cm2 g, T- 380 oC) to preheat our stripper feed. I want to replace this Superheated Steam with depressurized saturated HP steam (P- 25 kg/cm2 g, T-250 oC). But I am finding it difficult to calculate how much steam I will save. Can anyone help me in finding out the amount of steam for the same rate of heat transfer of 2 MMKcal/Hr. Also I need to know the heat transfer coefficient for both type of steams.
Note: The steam at above given saturated steam parameters is not actually saturated but we need these parameters.

Thank you all for your replies....We are not going to apply this change right now...currently it is just in study phase.
Actually what I believe is:
1. superheated steam should never be used for heating purpose as it has very low heat transfer coefficient (similar to air) as compared to that of saturated steam.
2. so the heat transfer in the convective film formed by superheated steam over the tubes will be very slow.
3.therefore to make use of the heat available in the degree of superheat, we have to increase the area for heat transfer.
4.Also the latent is higher in case of saturated steam (which is the main heat available for heat transfer in case of steams).
5.Also the latent heat increases as pressure of steam decreases.
That is why we thought of this change.
But acc to your answers, I think my knowledge about steam heating is not accurate and I am missing out something somewhere. Kindly help me in this issue and kindly correct me if I am wrong somewhere. 		(4)
29/06/2016 Q: We have Shell and tube heat exchanger named E-201-11. This E-201-11 is exchanger just before pass heater of furnace of CDU. The service fluid is desalted crude (shell) and vacuum residue (tube) from bottom column.
Shell operating pressure is 19.7 kg/cm2 and tube operating pressere is 25.8 kg/cm2.
Pressure desain shell 30 kg/cm2 and pressure desain tube 36 kg/cm2.
Hydrotest pressure shell 43.5 and tube 37.5 kg/cm2.

What the main consideration of installing TSV at outlet of desalted crude?
Does it because of thermal expansion?

Now we are installing spare exchanger for E-201-11 but the type is plate and frame HE.
The operation mode will be one HE operated and one HE spare/standby.

My questions are :
Do we need to install relief valve at desalted crude outlet of new HE? Can we use 1 TSV for 2 HEs?
What may cause thermal expansion since reduced crude being pumped by bottom CDU? 		(6)
12/06/2016 Q: Can someone please tell what global delta T minimum is, in pinch analysis? (2)
17/05/2016 Q: In our CCR we are facing with the feed side plugging of the Packinox CFE heat exchanger. Could you tell me the reasons of this phenomenon? Have anybody experienced the same? What about the solutions? Till when is it worth cleaning? (7)
15/05/2016 Q: Crude heater is twin cabin type which is operated at 367degC for heating crude from preheat-2 to crude distillation column. There are total 8 passes, 4 passes in each cabin.Pass 1-4 in one cabin and rest 5-8 in another cabin.From past 8 months, To minimize the deviation in all passes coil outlet temperature,when flow is increased in pass 5 & 8,its coil outlet temperature increased rather than decreasing and pass 6 & 7 coil outlet temperature reduced when its flow reduced.Also, this effect is observed in skin temperature.
However, it is confirmed by checking temperature of radiation outlet with temperature gun and ensured the deviation.
When flow in passes 5-8 is made equal, deviation in its coil outlet temperature reduced for the same heater box temperature.
However no such issue is found in rest passes i.e. pass 1-4. What can be the possible reason? 		(2)
17/04/2016 Q: When do we use helical baffles in heat exchangers? In my plant there is a heat exchanger having helical baffles. When I checked its data sheet it says its helix angle is 20 degrees. What does that mean? (2)
16/04/2016 Q: Currently we are using service water as wash water to our desalter in CDU. Heat exchanger has LP steam on tube side and wash water on shell side where the wash water gets heated to 120 deg C before going to desalter. When we are trying to use a mix of service water and stripped water as wash water, our exchanger is getting fouled (Scales of salts are being formed on tubes within 2 days). The metallurgy of tubes in CS. IN other CDUs we are able to use stripped water along with service water and no fouling of exchanger is observed. How to proceed to identify the cause of fouling?
 		(7)
16/04/2016 Q: In one of our CDUs, the wash water to desalter is being heated in a heat exchanger with LP steam on tube side and wash water on shell side. Normally we use service water as wash water. Provision is there to use stripped water also. But whenever we are using stripped water the exchanger is getting fouled with salt scales on tubes and pressure drop across exchanger is increasing within 2 days. We are not using complete stripped water also, while using stripped water, service water is also going as wash water through exchanger. The metallurgy of tubes is CS SA179. How to proceed for analysing the root cause of fouling. It is not observed in other CDU desalters where same type of facility is there.  
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)
26/11/2015 Q: Recently, because of some difficulties, we have substituted demineralised water injection system with HP boiler feed water branched from HP BFW header. So, HP boiler feed water is being injected upstream of air cooler while it contains oxygen scavenger, amunium, and phosphate materials. In addition, the temperature of HP BFW is 80 degree centigrade higher than demineralised water's. By focusing on this, are there any consequences about this substitution for a long time of operation? (1)
20/08/2015 Q: We are operating a kettle reboiler connected to a distillation column. Heating is in a 3 metre long U-tube steam heat exchanger. Steam is at 10 kg/cm2 pressure. In the shell side dilute alcohol is evaporated at temperature of 100 deg C.U-tubes are welded in the tube sheet. we are facing the problem of frequent leakage from welding. Tubes and tube sheet are SS316 material. The tube bundle is adequately supported.
Does condensing steam create vibration in the u-tube? Welding leakage from top few rows are predominant.Would appreciate for suggestion to avoid such problem. 		(2)
13/08/2015 Q: In a vacuum column overhead ejector condenser, Cooling water supply pressure and cooling water return pressure (Both at ground level battery limit) to condenser (as provided to vendor) is 3.5 Kg/cm2(g) and 2.5 Kg/cm2 (g) respectively. As per the elevation drawing and layout, cooling water supply pressure at inlet of first stage condensers appears to be around 0.34 Kg/cm2g considering static head and frictional loss. At the outlet of condenser pressure becomes -0.16 Kg/cm2g considering differential pressure across first stage condenser in cooling water side as 0.5 Kg/cm2.
With this condition cooling water flow will be established across condenser or not? If not, will placing the isolation valves of return line at ground level help in water circulation across condenser? 		(1)
29/07/2015 Q: In our VDU furnace there are 4 cells & 1 coil/cell. In last few days suddenly few coils in cell 1,2 & 4 from the bottom started lifting up from the support inside radiation zone. Even few coils are floating continuously. While RCO entering the furnace pass4 comes first then 3,2 &1. Coils are horizontal. What could be the reason? (1)
23/07/2015 Q: In our VDU furnace there are 4 cells & 1 coil/cell. In last few days suddenly few coils in cell 1,2 & 4 from the bottom started lifting up from the support inside radiation zone. Even few coils are floating continuously. While RCO entering the furnace pass4 comes first then 3,2 &1. What could be the reason? (2)
02/07/2015 Q: Currently we have issues in our naptha cracker plant where our production is limited due to cooling water temperature. Since it is monsoon season, the cooling tower is not able to cool the water effectively. What are the alternative solutions or modifications that can be done to increase efficiency of cooling tower? (1)
29/06/2015 Q: Currently my plant is experiencing overhead vacuum fluctuation from 20 mmhg to 40 mmhg.
The design overhead vacuum is 20mmhg and maximum throughput is 20MB.
The ejector system consist of 3 stage ejector.
The first stage ejector consist of 2/3 ejector and 1/3 ejector load.
The second stage ejector consist of 3 ejector, and normally 2 out of 3 online.
The third stage ejector also consist of 3 ejector, and normally 2 out of 3 online.
We had perform field survey and found that the second stage ejector temperature is relatively low compared to the other ejector (26degC vs 70 degC)
Earlier, we suspect air ingress in to the ejector and we had perform online inspection. and indeed, we found 1 coin size leak at one of the first stage ejector and the leak had been repaired. however, the vacuum fluctuation is still there.
We had also verified all the other ejectors for leaks but unfortunately no leak was found.
We are also having issue with the ejector condenser. the third stage ejector outlet temp is relatively high compared to the other condenser (65degC vs 40 degC). This problem was there since a few years which had eliminate the condenser as the root cause of the fluctuation.
Currently we are trying to search of other weak point which can cause air ingress into the ejector/vacuum system.
Appreciate your feedback on the matter.


(4)
22/05/2015 Q: We are designing a direct contact heat exchange system wherein there is a packed bed, hot water enters top of bed at 68 deg C and leaves the bed at 51 degC. Gas which is rich in methane & ethylene enters the bottom of the bed at 33 deg C and leaves the bed at 65 deg C. The intent is gas should get heated to 65 deg C. We are concerned about low approach temperature at the top of bed (68-65=3 deg C). Wanted to know anyone has any experienece with such system? Will that low approach is achievable? Please suggest any other similar system where we can check. (1)
21/05/2015 Q: Would like to get expert advice on crude preheat train. We are not able to get the design preheat temp. In the preheat train the last two exchangers are in series. As per design tube side outlet of last exch. should enter at 323 temp. in the shell side of upstream exchanger with both exchangers operating at MTD of approx. 23-25 degC. However as per current operating conditions there is max. heat recovery in last exchangers with very high MTD and the outlet temp. is reduced to very low 290 degC. Due to which the upstream exchanger is operating at very low MTD 8 degC.
Based on this finding will it be advisable to partially bypass the last exchanger to achieve the tube side outlet design operating temperature or there is some other issue?

Additional Information:
Thank you for the replies. I have gone through detailed preheat train analysis and found that in one of the analysis where we were getting the desired preheat temp. there was no cross pinch in the same exchanger as the inlet temp. had sufficiently increased. And this was possible since the flow was meeting the design data. Thus we might have to increase the outlet temp. (keeping in mind the flowrate) from last exchanger but that again has to be analysed since there is one more exchanger in the upstream of train which is in series to these exchangers. 		(6)
20/05/2015 Q: We use immersion type Electrical Heaters in our Refinery. What experience do others have with reference to their cleaning and any replacement of parts?  
06/05/2015 Q: How do I check whether the water cooler tubes have punctured heat exchanger? Cooling tower is tapped with various units like GSU, DPD, SRU etc. Gas is coming in cooling water return line. The unit in-charge says our units are ok. Can we check at heat exchanger? How?
 		(4)
02/05/2015 Q: We have refrigeration package of NH3 as refrigerant, from the last 6 month we facing the problem of oil carry over to Chiller and KOD. we have to continuous drain out oil from the chiller and KOD while receiver level is constant in LT and LG both. NH3 package super feed currently isolated as it is suspected that might be there is a leak in super feed coils since its pressure equivalent to receiver pressure. but the LT of super feed is very erratic,a DP type LT which has been attended many times but problem still as it is. please suggest me what type of LT to be provided for the super feed level and what can be the reason of oil carry over to chiller and KOD.  
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)
27/02/2015 Q: We are planning for revamp in naphtha hydrotreater feed / effluent exchanger system. Could anyone guide us on the minimum hot end approach can be taken to design the system. At present we are having hot end approach at 60 degC. Can we add another shell to decrease the hot end approach as we are facing severe constraints in the hydrotreater furnace? (6)
14/01/2015 Q: What should be the design pressure for wash water system in air cooled exchanger in atmospheric distillation unit? Is it mandatory to apply wash water in spray form? It will be helpful to if anyone provide reference about the spray nozzle for this application. (4)
07/01/2015 Q: What are box, skin and arc temperature? What is the sequence in magnitude of all these i.e. which one is higher than another in a furnace? (1)
04/01/2015 Q: What is refiners experience with reference to reformer packinox exchanger effective cleaning ? How can this exchanger be best cleaned? (3)
21/11/2014 Q: What are the Pros and cons of Steam stripping and Reboiler? When designing a column, what are the factors that decide to go with each of this? (2)
11/11/2014 Q: On what criteria the selection of brass tube bundle is made over Carbon steel?
In a corrosive environment can Brass tube bundle be used in place of SS tube bundle? 		 
22/10/2014 Q: Any industrial experience with TEMA "F-type" shells with condensing service on shell side? What are the disadvantages? For a service with wide boiling/condensing range and temperature cross, can it be used? (4)
18/09/2014 Q: At our unit we have observed polymer on the tubes of reboiler, the reboiler being stab in, requires shutdown and tube bundle removal and cleaning. Looking for any online chemical injection continuous that could avoid the scaling or polymer formation. (6)
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)
24/07/2014 Q: I am working in Hydrogen generation unit. I want to know whether if naphtha preheater tubes got a leak and super heated HP steam went to naphtha side then would superheated HP steam go to hydrogenerator (Co-Mo catalyst)? What is the effect of steam on Co-Mo catalyst life? (4)
15/06/2014 Q: We use a hot oil system. We are facing frequent failure of gaskets in it. The operating temperature is 330 dec C and pressure around 15 bar. we are currently using metallic spiral wound gasket. These leaks are resulting into unit shutdown or online sealing.
1. Do others have the same issue of gasket leaks in hot oil system?
2. What kind of gasket will resolve above issue?
3. Any special make of gasket?
4. Might changes in operating condition help? 		(2)
31/05/2014 Q: We are facing rapid chocking problem of our feed bottom exchangers of sour water feed/stripped water. In last maintenance, tube side of these exchagers (Sour Water) there were found amonium salts deposited in form of lumps, that ultimately traveld through tower and back in the shell of these exchangers. These have cuased serious flow restrictions at stripped water pump due to insufficent suction. To examine this phenomena suction straniner of feed pump were opened but found almost clean. That shows nothing is coming from the feed tank. Please guide upon possible cause of this salt built up in shell and tube type feed bottom exhangers. (4)
21/04/2014 Q: What are the uses of shell and tube exchange in Bapco?
What are the differences in application between the co-current and counter current in Bapco? and how is it used in oil refineries? Any figures for them? Locations? 		 
29/03/2014 Q: What is the difference between the Antifoulants that are used in Refinery Preheat Train to avoid fouling and CDU Heater to avoid coking in the coils?
 		 
18/02/2014 Q: We have a kettle type ammonia vaporiser. Shell side is ammonia and tube side is steam to vaporise the ammonia. We have observed that tube side (steam side ) remains filled with condensate almost 80% due to its low load operation against the design. Is this operation is correct to run the vaporiser with filled tube condensate? (5)
08/01/2014 Q: Lately, have been experienced tube leak in DHDS stripper feed-effluent exchanger, Tubes were plugged and hydro-tested.
Four months later, again leak developed and found tubes in bad condition, and was recommended for full bundle re-tubing.
I would like to know what could be root cause for this tube failure in short time? Any specific improvement need to be done on internals of exchanger?
(5)
21/09/2013 Q: Some deposits were found on the fuel oil heat exchanger. It was observed that at temperature below 100 C no such deposition occcur, but at temperature >=100 C some deposits were found. Please clarify what type of deposits are these and the reason for such deposition.
 		(1)
18/09/2013 Q: How can I calculate the optimal velocity in furnace tubing? At our gasoil/kero hydrotreater we operate usually at low throughput, but we keep the recycle gas at a higher value than needed for the reaction, to prevent the coking of furnace tubes. I guess that the optimal recycle gas amount could be calculated, but I don't know how to do it.

Some additional info: It's the unit manager's explanation that he doesn't want to decrease recycle gas to prevent heater coking. We are usually running on low throughput with 4-500 Nm3/m3 H2/CH ratio. In the last cycle we had pressure drop problems on our reactor, we found solid deposit on top of the bed. We performed a furnace coke burning process during the last turnaround, and found that there was some significant coking in the furnace. Our licensors suggestion is, that H2/CH ratio should be approx. 5 times the H2 consumption. Based on this, 100-200 Nm3/m3 would be enough, but we are running often at 400-500 ratio, which is way higher than suggested. 		(3)
27/06/2013 Q: Our termosiphon reboilers in SWS unit are corroded after only two years. Column works fine, but the tubes in reboilers are leaking, lids are corroded, full of deposits etc. Pipe from bottom of stripper column to reboiler is plugged, almost 90%. Results are poor quality stripped water (with high H2S and NH3). Tubesheet material is SA 266 Gr.2, tubes SA 179 and shell SA 516 Gr.60.
Shell side (LP steam): 180C deg.
Tube side (stripped water): 130C deg.
What could be the problem? 		(2)
14/06/2013 Q: We have in our plant diesel hydrotreater unit Packinox Exchangers high dP increment. The dP of Packinox feed gradually increased from 10~12 psi and reached the low limit alarms which is 22 psi in last one month duration. Preliminary observation is showing that the raise in pressure occurred after the increasing of SC#6 from 11 MBD to 15 MBD
What is causing this problem, and what is the solution? 		(1)
18/04/2013 Q: Why does COT of a furnace go down when fuel gas supply pressure goes down (at constant fuel gas composition, though fuel gas main control valve opening increases to maintain COT and fuel gas flow to furnace also increases) and constant furnace throughput? (2)
04/04/2013 Q: I am looking to increase reboiling capacity for a column which already has four parallel thermosyphone reboilers. However, there is a space constraint for a new reboiler and also, since there are four reboilers, replacing each with high capacity could be a costly affair. Hence, i am looking for some alternative. Is it feasible to operate a column with four existing thermosyphoe reboilers plus a new forced circulation reboiler in parallel to existing thermosyphone which can be located at some distance from column and hence, there won't be issue of space constraint? could there be any operating difficulties because i have never seen this type of arrangement? (3)
22/03/2013 Q: We have cooling water contermination. Few drops of oil observed on the water surface. The water is dark and some particles observed on filter paper. Water turbidity becomes high. How can we identify the exchanger leaking? (1)
12/03/2013 Q: In one of our FCCUs we have problems closing heat balance due to the processing of a very hydrotreated feedstock. We have to use torch oil (LCO or fresh feed) to maintain regenerator at its minimum temperature.
We are evaluating the possibility of using other feedstock as torch oil. Has anyone experience in using fuel gas or natural gas as torch oil in the regenerator? What major modifications in hardware are required?
(2)
03/03/2013 Q: We are facing intermixing of shell side medium into tube side in Breech lock heat exchanger in DHDT unit. During maintenance of the exchanger, the shell to tube sheet gasket (sprial wound gasket) was found damaged. The gasket was replaced and hydotested as per procedure. We understood that this type of problem is being encountered in most Refineries. I would like to know whether any specific improvement needs to be done on internals of Breechlock heat exchangers. Has anyone used Camprofile gasket instead of spiral wound gasket for shell to tube sheet gasket?  
26/01/2013 Q: In our Haldor Topsoe plant burners mounting plates get red hot at high throughput say 90-100%. What may be the possible reason? (2)
23/01/2013 Q: I am looking for any tips for hydrocarbon clearing and cleaning heavy hydrocarbon exchangers using only a hot DF2 wash and then 150# steam. Any suggestions will be appreciated. (1)
09/01/2013 Q: In a Ammonia storage tank (at atmospheric condition and -33 deg C) when will more boil-off happen:
a) If the Ammonia is filled till half of the level , or
b) If Ammonia is filled up to full height
Tank construction is with Double wall, with perlite concrete at bottom, foam glass at bottom and Mineral wool at suspended deck.

 		(1)
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)
17/09/2012 Q: What is the expected life of fin tube of overhead air cooler of Atmospheric distillation unit? (1)
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.

Additional:
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 ? 		(5)
25/07/2012 Q: Please give us any suggestions for the online cleaning of Vacuum column overhead condensers. The Condensers are suspected to be fouled. What can be the fouling material in the condensers? (5)
20/07/2012 Q: Since a turnaround, we are observing temperature crosses on BES heat exchangers (1 shell pass and 2, 4, 6 or 8 tube passes) of our crude distillation prehat train. This translates in correction factors (F) below 0.75.
How can this be possible? I thought temperature crosses was possible on pure counter-current heat exchangers only... 		(1)
17/07/2012 Q: In our refinery the tubes of aero-condenser (air-cooled heat exchanger) suffers a remarkable thickness reduction. In January, 2009 we have replaced all the tubes with 2.77 mm thickness. During routine shutdown in October, 2011 we had found that thickness reduced dramatically. We had recorded the lowest thickness of 1.4 mm. At that time we had replaced the bottom layer of one bank which contains that tube.
After that one tube of adjacent bank was plugged due to pinhole type leak. A few months later expansion groove of one tube of this bank found corroded. We had taken few sample thickness in June, 2012 and got minimum thickness of 0.9 mm.
We found that only rear end tubes are facing significant thickness reduction. Again there is no vent or drain nozzle/plug in the rear header so it is not possible to clean the header properly during shutdown. After investigating we also found that the dosing of corrosion inhibitor and caustic soda suspended for several times due to unavoidable circumstances.
My question is what are the main reasons (including dosing interruption) behind the thickness reduction and what is the expected service life of tubes and header of aero-condenser? 		(2)
14/06/2012 Q: We are having plan to do heater online cleaning on one of our cylindrical type heater...our problem are that we have only 3 small observation hole that really not enough to do the online cleaning. We have idea to open the accessing door (man way) at the bottom of the heater and do the online cleaning through this way. Is there any person here that ever open their manway while heater is in operation?I think it is still save enough because the draft inside the heater is negative so there will be no fire will go out through that way. (2)
24/05/2012 Q: Is it possible to recover heat from the discharge of reciprocating compressor pushing hydrogen from 20 bar to 120 bar? Is there any safety concerns if we use it to preheat DM water for further processing as BFW?
Conditions are like this:
3 stage reciprocating compressor,
Hydrogen flow : 3.5 tph,
Discharge temperature: approximately 130 deg C in each stage,
1stage suction pressure: 20 bar, suction temp: 30 deg C
2nd stage suction pressure: 40 bar, suction temp: 30 deg C
3rd stage suction pressure: 70 bar, suction temp: 30 deg C 		(2)
12/04/2012 Q: Please explain to me what the MCC (metal catalyzed coking) in a high temperature equipment of a Naphtha Platforming unit is, and how to prevent it? (5)
08/03/2012 Q: What is 'HSS mode' on a heater? (2)
15/01/2012 Q: My question relaters to the maximum temperature that can be reached in the feed preheater furnace in FCC unit. We operate one of our FCC units in maximum distillates mode and we want to decrease cat/oil to minimum. Currently, we have the following design limits in the feed preheater furnace: 360C (680 F) in the process size and 419C (786F) in the skin points of the furnace tubes. According to a study by our engineering department, temperature in the skin points could be increased to 467C (873F). But our main concern is that an increase in temperature in furnace tubes could cause coking of the feed. Although the feed to the unit is Mild Hydrocracker residue, that has low tendency to coking.
Has anyone experience running FCC units at feed preheat temperatures higher that 360C (680F) in process / 419C (786F) in skin point? 		(2)
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. 		(3)
09/08/2011 Q: What are current views on twisted tube heat exchanger configurations in refineries, particularly in comparison with conventional shell and tube configurations? (7)
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)
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? 		(1)
29/05/2011 Q: We are facing frequent fouling in our falling film evaporators because of tar content in our feed. Currently we down our plant once in 3 months for cleaning these evaporators. Can anyone suggest the best method in reducing this fouling?? how about tube inserts ?? or do we have any advance technology in heat transfer for reducing fouling??
I know twisted tubes can reduce fouling but can we use for falling film evaporator??
 		(4)
01/03/2011 Q: Next week , we will shutdown some of our units (in crude refinery) due to economic matters. This shutdown will last more than 3-5 months. We are now thinking about how to keep furnaces during this long period. Our furnaces have combined-fuel burners.
I would like to have some guidelines about this task. 		(3)
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)
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? 		(4)
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)
27/08/2010 Q: I would like to know in a plant that has different coolers that run off one cooling tower is it OK to pinch on cooling water when the cooling needs vary in different parts of the plant? I have worked in several different plants and this is usually an accepted practice but now I'm in a new plant and operators oppose pinching on the cooling water valves. Currently we are running cooling water at 90 degrees which in are second stage chiller I think is too hot and overloads the refrigeration unit but if we pinched cooling water at inlet discharge coolers and used compressors discharge temp to maintain our front in temp it would be a much better way to run the plant. (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. 		 
03/08/2010 Q: When we had turn around in amine treating unit, sulfur recovery plant, we found almost outer tube side covered completely by hard scale. We suspected that it came from degraded solvent (amine compound) during regeneration. We had already been cleaning with chemical agent, but it showed unsatisfied result. Does anyone have similar experience? What recommended cleaning technique should be done? (2)
03/07/2010 Q: What are the benefits of adding process steam in pre reformer inlet and reformer inlet separately? In some hydrogen plant it is mixed only in reformer inlet. What is the advantage of that? (2)
24/06/2010 Q: Is a pressure instrument really required at inlet cone of transfer line exchanger? if yes, then what is the best arrangement? Will the nozzle for pr instrument pierce through the refractory lining?  
26/05/2010 Q: In our Once Through Hydrocracker, the Fractionator Feed Furnace has options for both Fuel Oil and Fuel Gas Firing. Currently due to some problem in the electrical heater in the Fuel Oil Circuit we are using only fuel gas. Some days back inspection department reported a much higher skin temperature in the radiation section of the Furnace. The same report was also upheld during various cross-checks by other departments. Could this be due to the reason as we are not using Fuel Oil? If so, then could somebody explain? Another thing to consider, we are running at 70% T'Put and design conversion so in general the burners are supposed to operate at the given Heat Duty. (4)
21/05/2010 Q: We are planning to procure a new airpreheater for furnace with two cells K1 and K2 cell one for prefractionator reboiler and the other crude heater for fractionator.
I am just filling the process data sheet. On what basis should I fix the pressure drop across the air side and flue gas side? 		(2)
13/05/2010 Q: What are the benefits of a top fired reformer versus a sided fired one? (5)
11/05/2010 Q: We have a thermosyphon reboiler for our stripper column. Before shutdown we were circulating more hot oil in this reboiler, but after shutdown we cannot increase the hot oil at the same feed rate.
How can we rectify? 		(2)
04/05/2010 Q: My question is regarding Heat Ex. When I was simulating an Exchanger in HTRI which was of BHU type, I came to know that it is not providing any TUBE pass arrangement for 6 Tube pass and 10 Tube pass. The same thing is happening when I use the U-Tube combination with H or G type shells.
Can anyone explain me what is the reason it is not accepting (providing Tube pass arrangements) 6, 10, 14 Tube passes with H-U (shell-Rear end) and G-U (shell-Rear end) combination? 		 
02/04/2010 Q: Sometimes it is seen that the leaky tube of heat exchanger is used by plugging both sides. I want to know the percentage of tubes that can be used in plugged condition in running condition and also the standard for this plugging. (5)
06/03/2010 Q: Can we pinch cooling water return valve in trim cooler? If not, why not? (5)
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)
23/02/2010 Q: What is the use of heat release curve of any heat exchanger? (1)
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)
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)
01/11/2009 Q: What is main purpose of putting sealing steam in a turbine? (1)
01/11/2009 Q: In our DHDT recycle gas compressor primary seal vent flow at non driver end side has reduced to zero while it was previously 5 Nm3/hour. Driver end side flow is running between 30 Nm3/hour. What is the possible reason behind flow reduction? (1)
31/10/2009 Q: Is there a heat transfer fluid that can withstand a temperature of up to 600 deg C plus? (2)
23/09/2009 Q: There are a lots of air finned coolers and condensers in our refinery. The size of air finned H/X is around 10M*12M, 5-7 layers.
We had tried water jet cleaning, chemical foam cleaning, liquid nitrogen cleaning method to clean the air fins, but not satisfied to operation teams.
Could you please advise? 		(2)
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)
15/08/2009 Q: In Our Recycle Gas compressor turbine seal steam pressure having too much fluctuation. Some time its pressure increase and some time decreases. What are the possible causes? (1)
12/08/2009 Q: In DHDT unit suppose benzene converted to cyclohexane and then cyclohexane converted to normal hexane. What is the mechanism of this reaction? How is aromatic converted to cyclohexane then how cyclohexane ring broken and converted to n-hexane? (3)
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?  
21/07/2009 Q: For Euro-III diesel why must we maintain density 820 to 845 Kg/cube metre? How will performance be affected if this value is not maintained? (2)
21/07/2009 Q: Why must we maintain distillation of diesel 95% at 360 degrees centigrade for Euro-III ? If less or more what is the effect on engine performance? (2)
18/07/2009 Q: What is the basic difference between a thermal and pressure safety valve? (5)
05/05/2009 Q: The context is the following:
- The system is: inlet pipe + control valve + outlet pipe.
- The fluid is natural gas
- The outlet pipeline is buried.
- No outlet pipe insulation.
- The minimum allowable temperature in the outlet pipe is -20°C.
- The minimum temperature at the control valve outlet flange is about -15°C (worst scenario)
The problem is that I need to calculate the length of outlet pipe so that the fluid temperature increase to 0°C.
My data are:
- Outlet pipe material: carbon steel (L360)
- Outlet pipe internal diameter: 570 mm
- Outlet pipe thickness: 20 mm
- Outlet pipe is buried 1 m deep.
- Average air temperature: 11°C
- Wind velocity: 10 m/s
My questions are:
1. Do you know where can find thermal conductivity data for ground? I know it strongly depends on the ground composition but I don't have anything...
2. Could you please share any Excel spreadsheet to perform that calculations? 		 
28/03/2009 Q: What is lube oil supply temperature for any pump or compressor? Like feed pump, makeup gas and recycle gas compressor. (2)
25/03/2009 Q: Why do we need to maintain gas oil ratio in our diesel hydrotreater? (5)
12/03/2009 Q: In one of our new projects, we have a shell and tube heat exchanger for crude heating from about 15 C to some 70 C using hot water as heating medium. This crude exchanger is located downstream of 1st stage production separator in the stabilization train. The crude is specified to be on shell side, whilst the hot water to be on tube side. (Please note we also have an existing installation where crude is on the shell side and water on tube side, operating for last 15 years without any issues).
However, EPC contractor is now proposing to swap the fluid i.e. crude in tubes and water on shell side.
Any feedback on the subject will be useful, so as to make a right selection of design with respect to both engineering and operating /maintenance considerations. 		(6)
15/02/2009 Q: Why is the cetane index of diesel higher for high sulfur than low sulfur crude? (6)
15/02/2009 Q: What is the mechanism of aromatic saturation reaction in diesel hydrotreater reactor (i.e. step by step conversion from aromatic to paraffins)? (2)
07/02/2009 Q: What is the standard value of SOX & NOX in furnace stack outlet? Are the Values different in case of fuel oil firing and fuel gas firing? (3)
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)
06/12/2008 Q: Why do we have only exchangers with even number of tube passes? Can we use exchangers with odd tube passes like 1-3/1-5/1-7 exchangers?  
17/11/2008 Q: What is the procedure to be followed for plate heat exchanger (packinox) pressure test in Continuous catalytic reforming unit.
 		(1)
16/10/2008 Q: Why is the non return valve fitted on the horizontal pipe line rather than the vertical one? (2)
05/06/2008 Q: What is the amount to which oxygen enrichment in a fired furnace helps to improve capacity and efficiency of a plant?  
13/02/2008 Q: I am looking for a heat exchanger specialist or a manufacturing company who would be able to help with tube bundle failures which are very regularly occurring on a horizontal thermosyphon reboiler on a sour water stripper.
We are suspecting a mechanical problem like vibration or something else. The tubes are failing in six month to a year even if they are upgraded to stainless steel.
The problem does not seem to be related to corrosion from the process fluid. 		(2)
22/01/2008 Q: Can anyone tell me the average time it takes to clean a flare line please? (4)
22/01/2008 Q: How much does it cost a refinery and/or petrochemical plant to produce 1 (one) tonne of CO2? I have worked out how much CO2 is produced per barrel of oil, for example, but now want to put a monetary value (or indeed an energy value) on to that tonnage of CO2. Thanks.  
06/01/2008 Q: Can semi conductor based heating and cooling systems be used to save energy in the refining of crude oil and gas condensates?
What are the limitations? 		 
24/11/2007 Q: Can anyone tell me about the possibilities for the online cleaning of heat exchangers? (5)
24/10/2007 Q: Do you believe that specialist cleaning of equipment e.g. WHRU, heat exhangers etc can have an impact on the carbon emissions of your plant?  
06/09/2007 Q: We are experiencing an increasing loss of heat exchangers efficiency. Therefore, we would be interested to know if there is any "on-line cleaning technology" that does not require to shutdown the distillation unit. (4)
06/09/2007 Q: We have experienced frequent leaks and failures of Plate Heat Exchangers in our Sour Gas Treating Units. We have tried varying gasket materials and operating procedures but the maximum MTBF is 6 months. Specs are as follows:
Service:Rich/Lean Amine Solvent
Heat Exchanged: 24.07 Gcal/h
Operating Temp: 86.6/111.3 - 130.8/98.6 (cold - hot side)
Operating Pressure: 8.9/8.3 - 1.8/1.2 (cold - hot side)
Gasket: EPDM
No. Plates: 254
Can anybody suggest alternative approaches or provide advice on type, materials, procedure etc ? 		(1)
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)
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?

 		(6)