Q & A > Maintenance
Date  Replies
17/04/2021 Q: We are having a problem with the product fractionator bottoms pump (multistage centrifugal Pump turbine driven/standby motor driven)(inlet ~330 deg C) of a MHC unit; whenever the pump is taken in service and made ready after maintenance and primed (previously used to prime from the suction valve, now try to prime with a warm-up line) the downstream fired heater (thermal cracker) trips due to low flow as soon as the suction valve is crack opened to take it in service.
Any suggestions on how to rectify this issue?
 		 
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? 		 
04/02/2021 Q: What is the mechanism for mercury desorption from crude oil pipelines during emergency shutdowns upstream? Does it effect the normal mercury concentration after resuming t operations?  
25/12/2020 Q: What should be the maintenance and inspection schedule for underground storage tanks for petroleum. (1)
05/07/2020 Q: Our crude fired heater is having trouble with positive draft. The heater is the balanced type. Our initial suspicion was fouling/leaks inside the air preheater. But when the ID fan was stopped, the draft inside the furnace increased even further. Chemical cleaning of the heater radiation zone was performed. The convection bank manway was opened and inspected. No significant clogging was observed during the inspection. Any clues as to what could be the possible reason for this? (4)
15/05/2020 Q: We are experiencing seal failures in a heavy naphtha pump (topmost side draw product of the atmospheric crude column) due to blackish muck-like material. the pump suction strainer has been found to be damaged as well. Heavy naphtha draw-off is from the 9th tray from the top. Could it be due to formation of iron sulphides and corrosion of the top tray elements? Anyone else faced similar issues? (4)
31/03/2020 Q: We plan to dismantle a tetraethyl lead additive station and removal of tetraethyl lead is necessary prior to dismantling. Could you advise how this should be undertaken?
 		(2)
21/03/2020 Q:
Our secondary water consumption in our petrochemical plant is higher than design so is there any technology that can help us to reduce secondary water consumption for the centrifugal pump without revamping our secondary water system?
 		 
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)
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)
07/12/2019 Q: For part of a project, I am dealing with SR naphtha reforming reactors. The process is four reactors in series that use Pt-Alumina catalysts. Due to the high-temperature generation in the regeneration step, one of the reactors can not be in the service anymore.
I want to know does anyone have the same experience?
Is it possible to work with three reactors?
Could you please inform me to find some useful resources to find a similar study and situation?
 		(3)
07/12/2019 Q: In a case study for safety improvement and process analysis for SR naphtha reforming, I want to know If one of four reactors can not be in service is it possible to work with three?
Is it safe to work with three reactors?
Does anyone have such experience?
Could anyone please inform me to find some useful resources to find a similar study and situation? 		(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)
14/08/2019 Q: In our delayed coker unit, we have observed severe corrosion in Stripper Reboiler (Tubes were found heavily corroded) which is leaving heating media as Debutanizer bottom. During its 20 Years of life we have never observed corrosion in these reboilers.

What are the possible causes for this? For preventing cyanide corrosion in Gas Concentration unit we are adding Ammonium Sulphate however we have never observed cyanide level greater than 0.1 ppm in sour water anywhere in plant. Is there any chances that this Ammonium Sulphate is causing this corrosion as there is no cyanide present in the system. 		(1)
07/08/2019 Q: Why are some reciprocating compressors using glycol for their cooling system in the recycle gas compressor while other don't have such as net gas booster compressor? (3)
01/08/2019 Q: We have a reciprocating compressor (motor driven) at UOP CCR-Platforming unit. Service of this compressor is Hydrogen. Recently we have noticed that its lube oil temperatures are rising. We have checked the cooling water flow of the lube oil cooler and found it adequate. Please provide expert opinion regarding causes and remedies of rise in lube oil temperatures.We are using Shell Rimula R2 Multi 10W-30 (CF4) for lubrication. (2)
17/07/2019 Q: Why does cavitation not occur in a reciprocating pump? (1)
15/02/2019 Q: I understand that increase in wheel chamber pressure is associated to fouling. But does increase in wheel chamber pressure always equate to axial displacement of rotor and increase in thrust bearing temperature? Reduction of process demand feed will result to reduction of wheel chamber pressure, however, we observed that once we return the feed rate to values prior reduction, (ex. 35mbsd to 25mbsd then return to 35mbsd) there will be an increase of WCP? what are your thoughts on this observed trend?  
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)
25/10/2018 Q: At a compressor's steam turbine, frequent vibrations are faced at Journal bearings. The vibrations go from normal 13microns to about 45 microns. Steam temp and pressure are normal We previously faced oil charring issue at the bearings and the problem was rectified by applying nitrogen in the seal. We suspect that the same problem has reappeared. Can anyone suggest how can we confirm if this is oil charring and how the issue can be resolved? (3)
25/07/2018 Q: What can be the reason of higher CCR catalyst dusting rate (elutriation and dust removal is working properly)? Which part of the reactor can be failed if only catalyst dust was found in reformate? (2)
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)
29/05/2018 Q: I am into esterification of benzyl group. We manufacture Benzyl Acetate. The problem we face is chocking of column. The salty material gets trapped into paul rings (packing for column), resulting into colouration of end product. Is there any chemical way out of it? (1)
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)
16/05/2018 Q: What will be the approach or methodology to work when serving a rotary atomising burner burner of a steam boiler?
 		 
10/05/2018 Q: I have read somewhere that; "Steam is injected in the furnace to prevent premature coking".
How is that possible? 		(2)
07/02/2018 Q: I am doing some research for a paper on gas treatment and would like to know an estimate of the cost of a planned shutdown in a gas treatment plants. I don't need precise number but some "rule of thumb" estimates would be very helpful.
Taking an average size plant of around 150 MMSCF/Day that has de-sulpherization, de-humidification, mercury removal and condensate removal.

1/How often does a planned shutdown occur?
2/On average how long is the plant out of action including shutdown down and start-up?
3/What are the normal activities performed at a shutdown?
4/How many man days are involved including:
a/ planning,
b/ hazops,
c/ scope of work,
d/ method statements,
e/ risk assessments,
f/ permits
g/ anything i forgot?
h/ performance of tasks for shutdown maintenance and startup

 		 
20/09/2017 Q: Is there any way to clean 80 inch submerged intake seawater in water-free situation? In other words, is it possible to plug both side of 2 km pipe and discharge the encapsulated water? (1)
29/04/2017 Q: In most of the flare KOD's within a process unit, there is one inlet line at the middle of the horizontal KOD vessel and two outlets (from the two ends of the horizontal KOD) which joins and then goes as a single line. Why is this so ? (1)
20/03/2017 Q: We are using Compressor Type WS2/180-A1 for our Naphtha HydroTreating recycle gas compressor. During Wash water injection at the up stream of NHT reactor effluent separator, water is carrying over to the suction of Compressor. As a result of that compressor discharge, flow becomes low and load current also becomes low which suggests one of the load valve is not functioning due to dirt in water may have choked the load valve. After cleaning the load valve, flow and current becomes normal again. This problem is being faced recently when some salt has formed at the downstream of NHT reactor effluent which is dissolving with the wash water and carrying over to the suction of compressor. In addition, we are facing this problem after 3.5 years of plant life cycle. My question is whether it is happening only for dirt in water or load valve's diaphragm and O ring get old or spring has lost its tensile strength. Whether the Compressor type WS2/180-A1 is designed to handle some liquid or water as it is designed for recycle gas of NHT unit? FYI- 1. Wash water injection has been continuing in a regular interval of 15 days since the inception of plant start-up 2. Salt formation at the suction strainer is experiencing currently.


 		(3)
27/02/2017 Q: We have a peculiar case where the Coke Drum has twisted. Any suggestions on the repair procedure? (1)
16/02/2017 Q: We observed that our crude unit naphtha stabilizer column overhead water has become decolourized since few days. The colour is yellowish to brown. However, the main column overhead water is clear in colour as previously. Can anyone help me in identifying the possible causes for this? Some forming also has been observed while draining this water. Can overdosing of corrosion inhibitor (filming amine type) cause this issue?

Further info:
Thanks for valuable answers. The colour was observed while draining of the vessel boot. So, there is no much time to react with atmospheric oxygen. Is it any dissolved oxygen that react to give the colour? Also, I found some evidence of overdosing (almost double ) of the corrosion inhibitor for a short period of time. Once it was corrected the colour was improved. But, not sure whether it is due to that or due to anything else. 		(3)
15/01/2017 Q: What is the best technique in terms of cost and time for online sealing of valve body leakage in which high pressure boiler feed water is streaming?  
05/01/2017 Q: Recently we encountered a failure in one of the Boiler feed water pump. Observations were as below.
1. Pump tripped after running for 30 sec when it reached its full disch pressure of 100kg/cm2G.
2. Trip was due to high bearing vibration on NDE side.
3. Rotor was moved towards DE by about 2mm.
4. Rotor was seized( could not rotate with hand).
5. NDE oil decolorised slightly.
6. upon dismantling we found that NDE bearing inner race was seized to shaft. NDE bearing was totally damaged.
7. DE bearing was fine and no change in oil color too.
8. While operation, discharge valve was fully closed( according to operations min circulation as well as balancing lines were fully open).
Online probes not able to provide required spectrum.
Now we are struggling to analyze the cause. Pls suggest the way forward and also if you have link to similar failures. 		(4)
27/12/2016 Q: We have found black solid deposits upon cleaning of our CCRU Net Gas Compressor First Stage Strainer. Upon analysis of composition, we have found that the sample contains hydrocarbon plus a significant amount of Chloride and Iron and with traces of Aluminium, Magnesium, Silicon, Phosphorous and Sulfur. What could be the source of these black solid deposits? (6)
10/05/2016 Q: Our crude vacuum distillation column overflash pump suction strainer gets fequently full of coke.
Overflash pump suction temperature is 374℃~385℃, flash zone pressure 21mmhg, top pressure 5mmhg.
Metal contents of overflash are 154.7ppmw(Ni 36ppm, vanadium 118.7ppm) and Metal contents of Vacuum Residue are 223.8ppmw(Ni 49.2ppm, Vanadium 174.6ppm). How can we prevent this? 		(7)
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 CDU’s recently we had a leak on the joint between the ¾” overhead neutralizer injection line and 24” overhead vapor line of atmos column. Internal corrosion was observed on the leak area. The pipes thickness was measured at different parts around the leak area and found to be OK. It indicates localized corrosion. We are using neutralizing amine as neutralizer. We are unable to find the root cause of the failure. Are there any instances like this in other refineries? If so, what might be the probable reasons? (2)
14/04/2016 Q: I have seen some designs in reciprocating compressors which give machine tripping on low low pressure of forced feed lubricator pressure on 2 out of 3 voting logic where as some manufacturers give only alarm and no tripping on low lubricator pressure. Why so?  
13/04/2016 Q: We are facing severe choking problem in jacket cooling system of reciprocating compressors. Currently we are using service water for closed loop circulation but the effect is such that after two or three months of cleaning, the flow area available reduces by more than 60% on an average. Is anyone facing similar problems..? What may be remedial action. ? We flush the system during every available shutdown. During flushing a think slurry like liquid sometimes black in colour is discharged.
Service water we are using has similar parameter that of industrial drinking water with slight high Cl content.

Additional:
The iron content of service water used in the closed loop system is 0.4ppm. We don't suspect any tube leakage in exchanger as well. But surely there should be a problem with the quality of water we are using.
The type of deposit we observed is muddy type hardened along the inner wall as lumps. Breaks down if we hammer the outer surface of pipe during flow inside.
http://sailinchemicals.com/wp-content/uploads/2015/05/02_Corroded_potable_pipe_-_Credit_-_Nu_Flow_America.jpg
The appearance is similar to above image except that the colour is slight orange in nature and more like globular lumps.

Additional:
It's the reciprocating compressor handling Hydrocarbon and hydrogen. There is no pinhole leak in any lines. After starting of condensate top up, we have found it much better. Only problem with BFW/ condensate is the working temperature. We have managed to change in one of the compressors. however , the other one needs to be done 		(8)
05/04/2016 Q: In our crude distillation unit, Main Fractionator bottom pump (Service RCO) is having frequent primary seal leak, period varying from 8 hours to around 2 weeks. The crude processed is North Gujarat Crude which is a high TAN crude having RCO potential of about 65%. Suction specific speed was checked which is well above its rated value.
How this problem can be solved ? 		(1)
12/09/2015 Q: What is the most cost effective method of removing sludge from a crude tank bottom? (1)
04/09/2015 Q: We have two trains of Sulfur Recovery Units having capacity of 35 MTPD. It is planned to carry out Turn Around Maintenance (TAM) of these units shortly.
I request sulfur experts to share their experience in emptying the molten storage pit and steps to be taken to handing over the pit to carryout inspection of steam coils, storage pit walls and floor. 		 
31/07/2015 Q: In our wet Gas compressor we experience frequent seal oil migration/leak into lube oil. Wet seals exhibit low MTBF. How can we eliminate seal leak and enhance sealing performance? Is dry gas seal a reliable solution in wet gas compressor? (4)
13/07/2015 Q: What are the methods available to maintain the electrically traced liquid sulphur pipe (OSBL pipe) when the elbow leaks?  
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)
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?  
08/05/2015 Q: We have storage tanks for all products and lines connected to Getty for tankers loading/off loading and the distance about 7 km all lines 14/16 inches and ended in terminal by movs (motor operating valves only). My question is can we install gate valves upstream of movs for maintenanc ? ( the terminal still under construction) (2)
30/04/2015 Q: we are facing problem of high skin temeprature in one of the pass of CDU charge heater (106,000BBl) refinery. After thermography, it shows even more. we have done following actions:
1. PUT manual the FC for that pass and manually maximized the flow through this pass only.
2. shut off the burner adjacent to this burner.
3. can not do the decoking for the crude heater. Furnace's Pigging is planned next year (2016).
But now, we are going to inject the LP steam online into one of the pass. LP steam is used only in case of:
- Furnace tripped due to pass flow low low.
- Furnace tube fire case.
What possible outcomes we can expect with this activity? will it benefit? is there any other technique to remove spalling?

Outcome:
Thanks for valuable comments.
In recent shutdown (planned turnedaround of the plant), we have managed to perform pigging of crude heater and after that, results are much better. no more skin temp issues. We have done pigging for pass more time, tube conditions are normal now. 		(4)
20/02/2015 Q: Is there any mercury limit in crude oil to avoid Alloy 400 LME corrosion?
What is the best metallurgy solution for HCl overhead corrosion and LME by mercury corrosion on the same CDU unit? 		 
13/02/2015 Q: Any refinery experience with mercury contaminated crude oil processing from corrosion point of view? (3)
30/08/2014 Q: Dead legs/purging point, vent point of the pipelines, pressure vessels, heat exchangers are generally consist of a valve and threaded cap at the end. During turnaround is it mandatory to check the thread of the nipple whether it is thinned or thread damaged especially when it is found the thickness of the pipe is satisfactory. (2)
13/08/2014 Q: What is the welding procedure of T-joints in 8 mm bottom plate of tank? Can T-joints be welded before completing short and long joints?  
18/05/2014 Q: In our vacuum column the column top pressure 75 mmHga and the flash zone pressure is showing 50 mmHga. The gauge near the ejector system is showing 40 mmHga. The PD of flash zone and the ejector system matches with the design value.
We have tried changing the gauge and the transmitter on overhead vapor also. The impulse line to the transmitter is clear.
what can be the reasons for this erratic reading in the vapor line. 		(3)
06/05/2014 Q: I would like your comments on use of Coriolis meter vs Positive Displacement meter from accuracy, proving, maintenance, operation point of view for custody transfer of petroleum products to be loaded in tank trucks  
15/04/2014 Q: In our CCRU plant we have two net gas compressors which are discharging 38000 Nm3/ hr H2 gas (95 % H2 purity). Net gas compressors are two stage reciprocating compressors with recontacting section. We have 4500 Nm3/hr (87% H2 purity) of semi regenerative CRU off gas joining the circuit after the first stage discharge. We are facing problems with very high second stage suction strainer PDIs in our compressors (which is probably due to CRU off gas joining the circuit interstage). Recently we had conducted analysis of the muck we found on second stage suction valve plates.
The analysis is :
Sr.NO / Parameter / Unit
1 Moisture (@105ºC) % 5.4
2 Loss of Ignition at 800⁰C % 83.14
3 Ash at 800⁰C % 11.46
4 Solubility in water % 13
5 Oil Content % 16.96
6 Iron (Fe) as Fe2O3 % 8.716
7 Acid Insoluble ( ~ Silica etc) % 0.8
Can anyone provide further insights looking at these results? 		(1)
26/02/2014 Q: Can any one explain me for online and onsite repairing and maintenance of electromechanical devices installed at 240 MW CPP of refinery sector.  
13/01/2014 Q: We have steam methane reformer. The outer surface of the tube is having deposits and leading to high fuel consumption as well as high temperature in flue gas side in waste heat section. During turn around we want to clean the outer surface of reformer catalyst tube so that we can reduce the fuel consumption and reduction in waste heat section temperatures. Is there any standard method available to clean the outer surface of the tubes? (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)
08/11/2013 Q: What is the most practical way to deplug LVGO nozzle of a vacuum tomer, whitout opening the tower? (1)
25/10/2013 Q: What is the basis for Designing the LPG service pipe line ?
1) Operating pressure of the LPG (or)
2) Vapour pressure of Propylene in the LPG ? 		(2)
17/10/2013 Q: We have heard in many technical forums about ‘Unit Quench Factor’.
We would like to know more on this term, monitoring experiences, correct technical formula & accuracy of this term in predicting stress build-up in coke drums.
What are other ways for monitoring stress on coke drums? Are there any standard references/values for water quenching, steam quenching & vapour heating - rates and Deg C/Min? 		(1)
12/03/2013 Q: Some weeks ago we saw some cracks in the FCC expander blades in one of our FCC units. The cracks appeared suddenly, from one month to another.
The fresh catalyst addition rate are very low, so catalyst turnover is slow. It has provoked the ageing of our e-cat inventory. We have measured the attrition of the e-cat, with Jet Cup method (Davison Index), and there is a decrease from 2-3 to 1-2. My question is could this decrease in DI of the e-cat (harder catalyst) be responsible for the mechanical problem in the expander?
 		(2)
17/02/2013 Q: Please advice about the operation practice of the reciprocating compressor in order to increase life time of discharge valves in the compressor cylinders.
We're operating a Hydrogen plant using water electolyser cells - using alkaline which is KOH, operating temp 70C and production rate 170 nm3/hr where reciprocating machines are used to suck hydrogen from a gas holder directly after the cells and discharge it to the high pressure line to the customer (200 bar).
The Gas Compressor comprises of 5 stages, where first stage is consits of 2 plate valves.
The problem always happens to first stage Gas Compressor. Just 15~30 days after starting, the discharge valves in the cylinder always develops a leak and fails. Upon dismantling, we used to find some debris and gum particle (deposits) in between valve plate and valves top. The problem occurs over and over again.
The deposits particle is KOH which comes with the hydrogen gas vapor passing through the suction filter and rest on the valve.
(2)
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)
25/01/2013 Q: In case of non-contact temperature measurement of the skin temperature of furnace tube, which instrument is better: infrared thermometer or laser pyrometer? What is the allowable temperature difference between thermocouple or thermowell temperature measurement to non-contact temperature measurement?  
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)
26/10/2012 Q: We have hydrogen reciprocating four cylinder compressor. Every time after over hauling we take No Load trial for 2 hrs with discharge valve removed condition. Then we purge with nitrogen, then twice with Hydrogen. Now During Load trial Motor trip on Over load, (0% capacity), after barring compressor around 2 rotation, the compressor started Normal.
Why compressor started smoothly after free rotation? We already taken No load trial one day before. 		(2)
10/10/2012 Q: During a recent turnaround, it was found that the vacuum unit heater tubes are badly coked (1/2" to 1"thick coke layer as per the inspection Engr). Due to shortage of time we could only manage steam spalling. The heater tubes are plug head tubes ( we do not have any drawing of the plug head tubes).
Can we do Pig Cleaning of the tube? Wil the plug make any hinderance to the movement of the pig? 		(2)
04/10/2012 Q: As per section 11.1.3 of API 574:
"In low-pressure and low-temperature applications, the required pipe thicknesses determined by the Barlow formula can be so small that the pipe would have insufficient structural strength. For this reason, an absolute minimum thickness to prevent sag, buckling, and collapse at supports should be determined by the user for each size of pipe."
Table 6 of the same code provides some data for Carbon and Low-alloy Steel Pipe at less than 205 degree centigrade condition.
My question is how this strength is measured and in case of temperature higher than 205 degree centigrade what are the values? 		 
27/09/2012 Q: We run a bitumen blowing tower producing off-gases (toxic gases) which we exhaust to an incinerator. What is the recommended material for the valves used in this service?  
26/09/2012 Q: While cutting a replaceable tube inside furnace, a cut mark by gas cutting tool is found on adjacent good tube. A cut mark of 3 mm depth and 6 mm diameter is created on a 3 inch (originally 5.49 mm thickness) A335 Gr. P5 tube. Should I replace the tube or locally repair the mark by welding? I should add that overall thickness of the tube is satisfactory. (1)
17/09/2012 Q: If caustic dosing suspended due to some unavoidable reasons is it possible to reduce overhead corrosion (caused by hydrochloric acid) by increasing amount of neutralizer like ammonia or amine at overhead of the Atmospheric distillation unit?
 		(3)
17/09/2012 Q: What is the expected life of fin tube of overhead air cooler of Atmospheric distillation unit? (1)
17/09/2012 Q: What is the expected life of polyurethane seal of floating roof storage tank?  
18/08/2012 Q: Forum is requested to share its opinion about Gasket Failure events, due to sudden unit shut down, of Column bottom pumps (Operating@400°C) of thermal cracking Units. Is there any requirement that Gasket be replaced after 2 shut downs? How can sudden Gasket failures be prevented. Pls suggest some recommended practice. (2)
07/08/2012 Q: Our Desalter transformer has got three transformers supplying to individual grids. This step up transformers are facilitated with three outlet tappings with higher ratings. We always run the desalters with same outlet tappings for all three transformers. Is it advisable to run it with different outlet tappings in all three transformers in a desalter?
I would like to know electrical feasibility as well as process advantages? 		(2)
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)
17/07/2012 Q: Can you tell me how can cleaning the convection tubes of asphalt heater without change the tubes by chemical or any method because we face several problem and bad condition for convection zone & finned tubes which their fins choked with ashes to improve the convection coil heating duty also access for replacing the deteriorated convection zone refractory? (4)
13/07/2012 Q: Currently our client makes all jet A-1 fuel from a conventional Merox treating process. There is a project under consideration where hydro-treated jet will be produced through a Hydro-desulphurization Unit. The hydro-treated jet with have anti-oxidant injected into the rundown to storage and will co-mingle with straight run Merox treated jet before entering the same storage tank.
Quality assurance/control team has indicated that the jet product needs to be within 0.5 API of each other in the top/middle and bottom sections of the tank. To achieve this tank mixers or a re-circulation system is being considered. Based on API 2003, section 4.5.5 indicates that conventional low-speed propeller mixing has been in use for many years without evidence of problems from static generation.
Other important considerations are the co-mingled jet will be stored in fixed roof style tanks. Secondly there is no anti-static additive injected in the tank at this point as it gets added at the truck rack and marine terminal.
My questions are:
1) Do other refineries typically use mixers or a recirculation system on jet tanks when co-mingling different types of jet?
2) Do they use a nitrogen blanket system as a safeguard to protect against static buildup in the tank when mixers are applied?
3) Is it true that as long as the jet liquid level in the tank does not drop below the mixer elevation in the tank that there should be no concerns with static buildup in the tank? (With all product tanks on-site the low pump out level is always above the mixer elevation and a low alarm ring in when approaching low pump out.)
4) Is the only concern on start-up or shutdown when a tank is being de-inventoried for maintenance or initially filled? 		(1)
20/04/2012 Q: We are facing a great problem with our pipelines near cooling tower. The water vapor/mist from cooling tower causing corrosion of these pipelines. We are using enamel paints but did not help us much. Please help me to find out a solution to protect the pipelines from the corrosion.

 		(3)
19/04/2012 Q: MEG regeneration system. In our plant we have 2 rich MEG tanks that receive MEG/Condensate/Water solution from condensate flash vessel. Last time during pigging activities we receive many sludge from offshore, and now all this sludge is settled down inside Rich MEG tanks. MEG Regeneration package performance rapidly reduced, pumps could not deliver Rich MEG to regen, strainers getting clogged very fast, HC compartment of MEG flash vessel in MEG Regen package filling rapidly. Any ideas how to improve situation with Rich MEG tanks? Maybe clean Rich MEG using hydro-cyclones, or any other equipment? Any links to useful equipment to be installed, or to similar problem anywhere? TQVM in advance.  
14/03/2012 Q: After commissioning of distillation unit we found that one of the passes of atmospheric furnace has encountered coke formation problem at the end of radiation zone. Is there any solution to continue the distillation process without doing shut down.
 		(3)
04/02/2012 Q: In case of pressure gauge what is the specific use of Gauge Saver and Snubber? When do we select Gauge Saver and Snubber? Why is Monoflange with Block and Bleed required for pressure gauges? (1)
28/01/2012 Q: In one of our FCC units (Kellog Orthoflow model), we are suffering severe problems of fouling (fines deposition) in the turboexpander. The scheme of the flue gas circuit is: two stage cyclones in the regenerator + Shell Third Stage Separator before turboexpander + 4th Stage Separator (cyclon) to recover flue gas from fines coming from TSS.
We have also observed high level of moisture in the fines from 4th Stage Separator (10-15%wt). So we suspect that the fouling of the expander is due a cold point in the flue gas circuit (where flue gas humidity is condensed) or an uncontrolled inlet of water / steam.
Has anyone experienced this kind of problems in an FCCU? What could be the potential causes of the severe fouling of the expander?
 		(2)
20/01/2012 Q: I am currently managing a high pressure water injection triplex pump in a hydro cracking unit. I am plumbed into the unit with my diesel powered pump that has taken place of two electric drive pumps that have failed for undisclosed reasons to me at this time. This particular job was given to my company on short notice and the only information i have received is that this was critical that the unit still perform at at least 50% production and in the event of a failure of the pump I'm operating the best thing I can do is run. If anyone has any experiences with these pumps could you enlighten me to the hazards involved, the use in process, and any down stream side effects on a refinery when they are out of service? Also I was told that within twenty minutes of shut down on their pumps that their unit would cease to function due to salt build up. (3)
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)
12/01/2012 Q: This is regarding selection of tank external floating roof to the fixed roof tank for LGO service.
Following criteria has been considered for the selection.
1. Capital cost 2. Maintenance cost 3. vapor loss 4. maximum aggregate capacity with in bund 5. Potential risk of loss of life.
Now as per above maintenance cost is coming higher in fixed roof tank than floating roof tank for painting.
How the painting cost for the fixed roof tank higher compare to floating roof tank? Since both tank will be similar size & capacity. FEED consultant has considered 2.1 million USD higher in fixed roof per 5 year considering 30 year operating life.
I want to know general practice for painting of petroleum storage tank. 		(1)
26/12/2011 Q: My question is related to the potential problems that could appear when the feedrate in a FCCU is reduced to the technical minimum (turn-down) or below.
- According to your experience, what is the minimum feedrate that can be processed in a FCCU? 60% of nominal feedrate or does anyone operated below this point?
- Which are the most likely limitations that could appear in this point?
1. Insufficient gas flow rate to the wet gas compressor?
2. Insufficient pressure or delta P in feed nozzles? Problems to obtain a suitable vaporization?
3. Insufficient coke production to close heat balance?
4. Insufficient liquid-vapour traffic in the main fractionation?
5. Any other limitation? 		(2)
26/12/2011 Q: I'm processing hydrocraker and my question is about steam turbine vibration hunting.
This is Recycle gas compressor turbine and its driving force is HP Steam.
I've noticed that HP steam Temp. & Press. was little changed after discovered the problem and controlled them.
But vibration hunting has still been occurring and I'm looking for another source of hunting.
Could you please advise about this if anything you have a similar experience or knowledge? 		(1)
12/12/2011 Q: We use two block valves with one blind for isolation at boundary limit of each process unit in our refinery. Gate valve is selected for block valve mainly. For hydrogen system, we select one ball valve (Orbit Valve) installed at main header side, and one gate valve at process side for block valve service. Would you please advice if Rising Stem Ball Valve is better for hydrogen system, and what condition should be used? (1)
25/11/2011 Q: Swivel joints are used in the roof drain line of the floating roof tank. In our refinery we usually replace these during repair work on the tank. In that case the life of the joints is about 10-15 years. But I want to use these joints again. There is no testing facility for these joints. There are 20 swivel joints in each tank so a good amount of money is required to replace them. My questions are:
1. Is it a good decision to replace the joints after 10-15 years?
2. How should we test the joints if we wish to use them again? 		(1)
08/09/2011 Q: A bitumen tank that has not been cleaned in 20 years required cleaning, our concern is Phosphoric/fire hazard. How can we control that?
Will degreasing, organic salt (removal of rust) then KmNo4 final rinse help?
During fe removal, it will have h2s; will that be a concern?
KmNo4 at 1% solution; is that sufficient to remove all the phosphoric? 		(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)
25/07/2011 Q: Lately we have been experienced frequent trip of Furnace in DHDS, we get positive draft and zero oxygen where this causes furnace to trip. Root cause? (3)
26/06/2011 Q: While working as an inspection engineer I faced some questions which answers are not clear to me. Please help me in this regard:
1. We are taking thickness record as per previous locations. I want to know how the locations are selected to record thickness on the pipe lines.
2. Sometimes we found higher thickness from the previous record. In this condition we recheck the thickness. Is there any alternative or tolerance limit?
3. How the retiring thickness of the pipe line is calculated?
4. Is there any suggestion while inspection of pipe line commenced?


 		(3)
22/06/2011 Q: Recently it was observed that the some of the radiation tubes of our atmospheric distillation heater were deformed. The tubes have been in operation for almost 30 years. Some of the tubes (specially at the middle section) deformed to the center of the furnace. Some deformed laterally to the adjacent tube. I want to know the possible reasons behind the phenomenon. Also please advise me what is the standard of replacement of the tubes in this mentioned condition.

 		(3)
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)
14/05/2011 Q: Does anyone have experiences of leakage of sea cooling water exchangers? What is best metallurgy for sea cooling water exchangers in a refinery? What are the important quality parameters of sea cooling water? How does one prevent corrosion of sea water exchangers? (3)
24/04/2011 Q: We are using 100% Visbreaker bottom as Refinery Fuel Oil in our heaters. Hard scale is observed externally on Heater Tubes. What is the usual normal receipe of fuel oil for Refinery Heaters. Is there any limit on fuel oil sulfur content to minimize fouling by adding diesel. Is there any treatment , by adding additives, to reduce external fouling of heater tubes? (3)
22/04/2011 Q: There is a chilling water package that chilled water by use of propane refrigerant cycle. unfortunately propane cycle is polluted by caustic and we decided to wash the lines and equipment. I want to know, is washing with water or low pressure steam is harmful for this? (5)
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)
18/02/2011 Q: Our HP sour gas header battery limit B/V is passing and leads to shut down other supplying unit to replace passing valve. To face this problem in future, maintenance is going to install 2nd block valve after removing originally installed NRV.
Q-1 Will it be successful?
Q-2 Why there are NRVs installed in battery limits for incoming lines? 		(2)
03/02/2011 Q: When should we be using a bypass line for a valve? Is there any rule for this? (2)
29/12/2010 Q: I have heard that Acoustic Meter could be used for testing the healthiness of the PSVs and control Valves. I would like to have some reference of vendors or manufacturers for this tool.  
04/12/2010 Q: We are facing problems with one of our reforming unit furnaces. There is a common duct in the three furnaces. The damper of the middle furnace is causing the problem. This damper falls several times after burning. The skin temperature of the tubes remain good but the stack temperature is higher than safe value by almost 150 degree Celsius (around 900 degree Celsius) . The furnace outlet temperature is operated below the design temperature by almost 25 degree Celsius. Our design temperature is 525 degree Celsius. The shaft, plate of damper used of stainless steel grade. We had changed burner tips several times but the problem was not solved. Please suggest me the cause and remedy of this problem. (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)
05/11/2010 Q: Lately we had a problem on one of our old (33 years) but reliable Desalter Transformers. The Transformer is NWL 150KVA 4.16KV/23KV (3each) on top of our crude oil desalter trap. Two of these transformers experienced failure and we found the high voltage cable was burned and cut. The oil in the entrance housing was discolored (black) and the oil in the third transformer was clear. Later on we found the secondary on the third transformer was disconnected. the floating switch and the grid were OK.
What are the possible causes for such failure?
We replaced the entrance bushings with the high their high voltage power cables for the damaged bushings.
We performed Megger test and Polarization Index (PI) test on the transformers. The PI was 1.4, 1.6 and 1.5 for these transformers. Are these PI readings acceptable to put back the system in service? What are other tests shall we perform on these transformers? 		 
04/10/2010 Q: Is there any simple tool for detecting passing among a valve (PSV,PCV,...)? I heard something about some pen type simple detectors for operators. Has anybody more information about this kind of tools? (3)
07/09/2010 Q: Our benzene product tank is internal floating roof tank with N2 blanketing which follow US EPA regulation. However measuring the VOC content at breath out shows as high at 15000 ppm. The internal roof rim seal was replaced and produced only minor improvement.
Is there any plant try to install vapor recovery unit to reduce these emissions? Is there any regulation which requires the benzene tank to be equipment with close system? 		(1)
25/07/2010 Q: Are variable speed drivers ever used in pumps?
If not, why not? 		(4)
18/07/2010 Q: Recently we found that the valves in the off gas (that comes from Vacuum distillation tower) separator unit line did not last long. After 6-7 months valve seat or body sprung leaks due to off gas. Please help me by suggesting the appropriate valve for this service. (1)
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)
30/04/2010 Q: I know butt welding is much stronger than lap welding. But I found that the bottom and roof of storage tanks are welded as lap welding. What is the reason behind this? (1)
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)
13/03/2010 Q: Please highlight procedures for removal of iron deposited on Zeolite Resin of conventional water softeners. Any vendor who could suggest chemical for this purpose?  
08/03/2010 Q: In our Once Through Hydrocracker Unit, the Recycle Gas Compressor is surging from 100% opening of the anti-surge valve to 0% without any change in process parameters. It was also observed that just prior to surging the total flow at the inlet of the RGC was also increasing. We have got an amine column at the inlet of RGC suction after HP separator to reduce sulphur loading. But now due to some constraints the amine flow had to be reduced. Can anybody explain the phenomenon? (3)
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)
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)
17/01/2010 Q: We store the Light Hydrocarbon and LPG in ECTs (Earth Covered Tank). These ECTs are pressure vessels, and storage capacity range from 500 to 4,000 cubic meters. We vent and purge the materials in these tanks to flare before turnaround operation or equipment repair. Is there any package can recover the valued materials? Please advise.  
08/01/2010 Q: I want to know the temperature profile of post weld heat treatment for alloy steel like P5, P9. We have some procedures that was used from a long time. I want to know the source or reference of the temperature range. Please suggest the maximum temperature, holding time, temperature raising rate, cooling rate. (1)
05/01/2010 Q: In our refinery we are going to change our crude reception line by 36" diameter pipe. The previous line is of 16". The flow rate will be three times higher than the present condition. Our tank has 69 m diameter and 12.5 m height. My question is: will it cause problem in the floating roof tank during reception? Is any modification required? Is there a standard procedure? (2)
07/12/2009 Q: What is the retiring thickness that leads to the replacement of the process pipes of various schedules? Is there any standard? Or it is based on experience? (1)
29/11/2009 Q: I am a Shift supeintendent of the CDU unit.
We could not stabilize the Brine treatment package - Hydrocyclones to separate the oil and sludge from the Brine of the Desalter outlet.
If anybody have the experience regarding the operations of Hydrocyclones (Brine treatment package) in the Brine system, please share with me.
If I can get the optimum dela pressure across, it will be helpful; I could not follow the vendor operational guidelines as it is not performing good. 		(3)
16/11/2009 Q: What are the reasons that are responsible for back fire or reverse flow of flame in the furnace? What measures should be taken to prevent these incidents? (4)
31/10/2009 Q: Please advise Heaters Convection Zone finned Coils cleaning techniques or recommend cleaning tools especially for Heaters without soot blowers during turnaround. Which contractors have successfully carried out Heaters convection zone finned oils repair & cleaning? What is the experience/requirement with reference to convection zone coils cleaning for Heaters with soot blowers? When should a refiner plan to clean Heaters convection zone finned coils cleaning? (1)
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? 		 
18/10/2009 Q: We are going to install anchors in our furnace. We get all the required spacing of anchors for cylindrical radiation shell, overhead arch, convection breeching (roof) and stack, but we have no proper data relating to anchor spacing of conical part of the furnace. Can anybody help me in this issue?  
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)
18/09/2009 Q: As a load bearing member which one is better: H beam or I beam? Is there any design criteria to select the appropriate beam?  
09/09/2009 Q: Our refinery is an old one. It already spent almost 41 yrs in operation. In this time frame we have changed our distillation column after 30 yrs and revamped topping furnace after 40 yrs. We have changed our exchangers, pressure vessels, tanks and other equipments as per inspection record and suggestion. Is there any rule of thumb regarding how often different types of refinery equipment should be renewed, e.g. after a definite period or number of operating hours? (3)
21/08/2009 Q: Before maintenance of crude tank it is necessary to remove the sludge inside tank. We do it by opening the clean out door and facilitate it by water jet, but it takes huge time to clean. is there any easy/quick method to perform the cleaning? (3)
21/08/2009 Q: In recent days we have found that in our refinery the bottom/lowest course of the crude tank is severely corroded, especially the lowest one metre. We intend to replace the bottom course without replacing other courses. the course height is 1829 mm. the diameter of the tank is 69 m. the thickness of the bottom course is 20.0 mm and the immediate above course thickness is 17.0 mm. The height of the tank is 12 m. We will also replace the annular plate and bottom plate. Can anyone help me which will be the right procedure to replace the course? (2)
23/07/2009 Q: Where do hairpin (u-tube) heat exchangers go to die? We are looking for a scrap heat exchanger to use for trials in our workshop in Essex, UK. Can you suggest anyone in the UK who deals in redundant hairpin heat exchangers?  
10/03/2009 Q: Is it possible to efficiently clean asphalt tank cars without excessive tank entry? (3)
20/05/2008 Q: Does anyone have experience of, or know how to set up a repair testing point for transportation of LPG by rail within the CIS?  
25/04/2008 Q: Is there any non-manual method for cleaning tanks used for asphalt storage? We dilute as much as possible with recirculating hot HVGO, but we have to finish the job removing a several inches layer of sticky asphalt. (4)
24/04/2008 Q: We have a sour water stripper which is used for stripping produced water coming with crude. There is a filter ahead of the stripper. Both the stripper and filter suffer from sticky asphaltene creating operating problems. We are talking to chemical vendors who claim they can inhibit asphaltenes from depositing on the filters and the packing. The filter is actually a strainer with .0.99 mm mesh to keep out particles greater than about 1mm. Are there any other methods which can solve this problem? (2)
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)
07/02/2008 Q: What are some of the most successful turbomachinery management systems in use today? What documentation is available to show where turbomachinery/compressor expected life has been extended?  
22/01/2008 Q: Can anyone tell me the average time it takes to clean a flare line please? (4)
24/11/2007 Q: Can anyone tell me about the possibilities for the online cleaning of heat exchangers? (5)