Q & A > Safety, Health, Environment and Quality (SHEQ)
Date  Replies
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?  
29/09/2020 Q: What are good practices to hand over sour water feed storage tanks in refineries?
 		 
09/09/2020 Q: During precommissioning of our DHDT unit we want to pressurise the system with nitrogen by makeup gas compressor up to 50kg/cm2g. Can we increase pressure without achieving the minimum pressurisation temperature?
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06/07/2020 Q: Our catalytic reforming unit is running at 500°C . A short length flame and smoke was seen at the heater outlet flange; we have a steam ring which we have used to extinguish the fire. Now my query about hot bolting: is it safe to tighten the bolt at 500°C to stop the leak? If not then what should be the maximum temperature and safe procedure for hot bolting? (3)
16/06/2020 Q: 1) What are the standard procedures to dispose of the catalyst dust (from regenerated and spent catalyst) from a CCR Platforming unit ?
2)Are there any adverse effects on the environment due to random disposal of the catalyst dust?
3) Is there any process to extract precious metal from the catalyst waste?



 		(3)
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)
19/02/2020 Q: Hi, We are going to install a Kerosene Hydrotreater Unit. Is it required to fit connection strips in the Aviation Turbine Fuel lines flanges starting from downstream of reactor? (2)
05/02/2020 Q: Hello,

In a CDU/VDU unit a Desalter is provided downstream of the crude charge pump. What should be the design pressure of this vessel?
Should it be crude charge pump-shutoff pressure or should it have a maximum operating pressure of vessel + 2 kg/cm2g, similar to the design pressure of the other pressure vessel?

It may be noted that this vessel is protected with a PSV. The conservative approach is to design this vessel for pump shut-off however this will lead downstream piping and equipment to be higher class which has cost impact.

Please suggest what is the practical approach and why?


 		(2)
30/01/2020 Q: What is Process Safety Time?
At what stage is it is decided? 		 
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)
13/09/2019 Q: What will I get if I apply a heating process to gas which contains hydrogen sulfide? (1)
23/08/2019 Q: What is permissible limit for bending of arbor/wicket coil in CCR box type fire heaters.
 
13/08/2019 Q: Is it possible for Arbor / wicket coils of CCR box heater to get tilted over a service of 5-6 years.  
18/04/2019 Q: We use DMDS for catalyse activation of hydrocraking, hydrotreatment unit and sometime for plaforming unit. DMDS is procured packed in metal drums. Our main issue is the treatment of waste dmds and also their containers. We have a quite subsequent amount of waste drums and chemicals. What are typical process or best practices about waste dmds management? (3)
19/01/2019 Q: Emergency Depressurization (EDP) System design
Our Hydrocraker unit has two emergency depressurization systems : 7 bar/min (100 psi/min) and 21 bar/min (300psi/min).
Unit design pressure is 160 barg and feedrate is 86 m3/h
Licensor assumes that EDP system (RO + Valve) is designed to decraease pressure unit by 7 bar or alternatively 21 bar in first minute .
Today unit is operated at higher flowrate (128 m3/h) and lower pressure (145 barg)
A depressuring test done in the new conditions showed that the depressuring rate decreased at 18 bar/min instead of 21 b/min in first minute.
Is this new depressusing rate still acceptable or should EDP valves and Restriction Orifice be resized to target 21 bar/min?

Additional info:
Refinery situated in the Ivory Coast



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12/12/2018 Q: What is best practice for design of dewatering systems on pressurised LPG storage spheres and how is this affected (if at all) if the installation is located in an extreme cold climate? Is manual or automatic draining recommended? Automatic drain systems are likely to be a more complex design.
For example, a new-build design might be fully automated and comprise a 2" nozzle with a remote-operated, accessible fire safe primary isolation valve at minimum distance followed by a dewatering pot with an interface level sensor. The interface level sensor would throttle a control valve with bypass on the dewatering pot drain line and an independent lo lo interface level sensor would trip closed the primary isolation valve and de-energise the solenoid on the downstream interface level control valve to force it closed. The trip system would also impose an output high limit of 0% on the interface level controller forcing its output to zero to avoid the valve bumping open when the trip is reset. The dewatering pot would have a hard-piped connection to flare and a hard-piped connection to a closed drain. The interface level sensor would have a local repeater indicator visible from the bypass valve. The drain line would reduce to 3/4" diameter downstream of the control valve (this serves as a restriction orifice on the drain system). It would be designed to be self-draining with no pockets and would be well-braced to minimise vibration while in operation. The number of flanges in the system would be minimised and the majority of joints would be socket-welded (screwed fittings not allowed except perhaps for instruments). Cold climate considerations (also mitigating Joule-Thomson expansion effects) might include electrical tracing on the dewatering pot drain line with a common alarm to DCS on tracing circuit failure and provision for methanol (anti-freeze) injection into the dewatering pot flare connection. 		(1)
26/10/2018 Q: Kindly advise that if a leakage arises from LPG tank lorry during filling operation, how should the leakage be handled? Are there any code and standards that outline what exact steps we need to take in case of a leakage?  
07/08/2018 Q: What are the safety precautions that must always be taken before entering the Confined Space Work in order to install the floating suction inside the tank? (1)
17/07/2018 Q: Is their any long term health hazard of nucleonic gauges having Cobalt 66 as an radioactive element, used for level measurement in granular solid catalyst? (2)
18/10/2017 Q: Standard Operating Practices/Procedures for Hydrocarbon Draining is Draining the Hydrocarbon in Close Drains.
Is there any Mobile/Portable Facilities/Skids available for doing the Hydrocarbon Draining and Collecting? 		(2)
12/08/2017 Q: Decoking of the fired heater of VDU
During recent years , the skin temperature of one of the 4 coils developed a slightly higher skin temperature than the other 3 coils , the skin temperature is nearly 500 C , it is still in the safe range but we are now considering decoking to to remove any present coke during shutdown . Anyways , I am comparing SAD ( Steam Air Decoking ) to Pigging , There seem to be many hazards and incidents during SAD , i wonder if any of you witnessed any incidents with SAD ? ... Can anyone clarify the potential hazards and their severity ? do you recommend it or you recommend pigging ? ...... Thanks for your comments and replies in advance .... 		(5)
21/04/2017 Q: What is the relationship between the top temperature of a vacuum tower in a vacuum distillation unit and the rate of corrosion in the overhead condensers?

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21/04/2017 Q: In an atmospheric CCR reforming unit how can measure the chloride content (HCl) of the regeneration vent gas?
If you have a Chlorsorb system how can you measure its efficiency? 		(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: Why is the RV of surface condenser sealing with condensate from surface condenser pump in hydrocraker unit? (1)
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)
28/11/2016 Q: Does anyone have any experience with catalyst fluidization in oxychlorination zone of Regeneration tower in continuous catalyst regeneration unit? We have experienced high catalyst dumping recently after this unit shutdown. This catalyst dumping contains high catalyst dust. Is there any parameter to check whether is the catalyst fluidized or broken inside the Regeneration tower?
Thank you very much. 		(3)
24/10/2016 Q: What is the difference between process shutdown (PSD) and emergency shutdown ( ESD). (5)
03/05/2016 Q: What are the advantages of using a chemical injection quill for dosing chemicals on crude column overhead system? What are the process parameters need to be specified for a quill? (4)
25/04/2016 Q: We are looking at alternative option(s) that could expedite the unloading of residue desulfurization unit catalyst (from reactors) other than typical vacuum-out/jack hammering approach.
We have heard about the CO2 explosive technique - and just wondering if anyone has any success stories with that?
Any other feasible approach to be explored?
 		(4)
13/04/2016 Q: In our CDU , recently we faced an leak between the joint of 3/4"neutralizer line and 24" overhead vapor line. On observing the leak, it was found to be corroded only near that joining location. The thgickness of the overhead line and neutralizer injection line were measured and found OK. The neutralizer line is joined to overhead line through a half coupling. The leak was on the halfcoupling also. Thickness of overhead line is 9 mm, halfcoupling is 6 mm and 3/4" neutralizer line is 5.56 mm. We are using neutralizing amine as neutralizer. pH is being maintained betweeen 5.5-6.5 and chlorides and Fe in atmos boot water is also under control. We are unable to find the reason for the leak. Are there any instances like this in other refineries? Please help. (2)
13/04/2016 Q: As per HAZOP recommendations in one of our CDUs, the recommendation was to provide TAHH with 2oo3 logic to trip the furnace on High COT. Are there any such trips in any heaters? Is it really necessary to have such a trip ? In case, the trip is provided, what should be my temperature on which the furnace should trip? (3)
13/02/2016 Q: What are the conditions of auto-ignition of hydrogen rich gas, when leaking through any point of hydrogen recycle system to atmosphere? Is there any differences between hydrogen rich gas and hydrogen make-up gas regarding this issue? (1)
22/11/2015 Q: We have some LPG Merox units with amine absorber before the Merox unit. We use MDEA in the amine absorber and we have experienced some problems of amine carryover in the LPG.
Can anyone comment on the impact of the amine contamination in the Merox units? Besides the possible formation of emulsions, could there be any other problem? 		(6)
13/11/2015 Q: We are suffering from water carryover with tail gases form quench top in tail gas treater unit of Sulphur Recovery Block.
In case of absorber bypass due to S/D of Common Regeneration Unit; tail gases are routed from quench tower top to incinerator which results in water accumulation inside incinerator which is a major problem.
To tackle this it has been planned not to bypass absorber and flow tail gases from absorber without any amine flow.
I wish to know what could be possible ill effect or problems with the same? 		(1)
23/09/2015 Q: What are the reasons for variation in JP-8 fuel conductivity and how can they be minimised? (2)
25/08/2015 Q: We have safety valves on LNG discharges tank discharging to atmosphere through a tail pipe approx. 25m long.To prevent ignition of the release in the event of a lightning strike, would it be acceptable to provide a flame arrestor on the vent? (4)
15/08/2015 Q: What's the safest way to clean a Acetic Acid Pipe line of 100 meters of longitud, to cut with fire and repair?
Currently we clean the pipe lines getting them full with water, 30 tons/hr flowing to an a storage tank truck, around 30 minutes, after we use nitrogen to blow (7 bars) the acid and water to a tank truck.
We do this three times, to make sure the pipe line its very clean.
After that, we dry the line with air, 8 hours, then we seek LEL % whit a SIRIUS MSA device, if there is a 0.0 % LEL, we inject a inert chamber (using nitrogen very low pressure).
Then we make the first cut using fire.
We use nitrogen because its a inert gas and it displaces the air and so we prevent the formation of an explosive atmosphere.
If you have another practices or examples I'll be glad to learn. 		 
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?  
23/04/2015 Q: I was asked for evaluation of doing the leak test and pressurization step in the Hydrocracking unit start up with Nitrogen instead using Hydrogen. We have 1 reciprocant compressor for make up and one centrifugal compressor for recycle gas, I would like to know what do I have to consider to make this evaluation, what I know by now is that my recycle gas molecular weight is 4 and N2 is 28, so my centrifugal compresor could not be able to increase the pressure more than 250 psi (aprox). what should I take in account?. Is there any gain doing this? (4)
31/03/2015 Q: Kindly advise the emergency procedures if a LPG road tanker is toppled on the road. What is the procedure for salvage if it does not leak? What is to be done if it leaks and catch or does not catch fire? What is to be done if it forms a vapour cloud? (2)
21/02/2015 Q: We are proposing the idea of installing Auto drain valves in our product tanks viz HSD/MS/SKO. Can you all share your experience if any regarding its performance? Will it lead to reduction of HC loss during tank draining/preparation for product despatch? (1)
13/02/2015 Q: Any refinery experience with mercury contaminated crude oil processing from corrosion point of view? (3)
23/01/2015 Q: What is the effect of sending LPG (pressure about 9 kg/cm2G and temperature 50 degC) into a floating roof storage tank (atmospheric pressure design) contains heavy hydrocarbon component (C8+)?
LPG flow will be only 4 ton/hour where the tank capacity is 60000 m3. If the heavy hydrocarbon quantity in the tank is high enough, will it eliminate LPG tendency to vaporize? Also the solubility of LPG in hydrocarbon, will it reduce or eliminate LPG vaporize? 		 
21/01/2015 Q: What are criteria for providing the bypass line in the control valve? In NG fuel line from 32 ksc to 5 ksc pressure drop at 70 deg C, can we provide the control valve bypass? (2)
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)
11/12/2014 Q: In order to decrease storage costs and to get rid of some imposed restrictions for intermediate products as feed for downstream units, is it possible to connect output of upstream unit (e.g. distillation unit) to downstream unit (e.g. Hydrocracker) directly? Because of sequential changes in crude feed characteristics, we have encountered some surge and instability in straight run products of distillation unit. (2)
14/10/2014 Q: I am working in Hydrogen generation unit. In hydrogen export line one Low point drain flange caught fire due to minor leakage of hydrogen but no source of ignition was there. We could not find reason why auto ignition happens without source. If anybody know give some reason. (5)
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)
16/08/2014 Q: In our hydrotreater units SWS reboiler we are having SS 316L tubes while shell is of carbon steel. Reboiler is kettle type, tube side is MP steam(Pr-10 bar and Temp-220 degC) and condensate(Temp-170 degC). During our shutdown we have opened reboiler and found 60-70 percent tube thickness loss from OD side(By ECT method) that is part of tubes which is in contact with shell side fluid and thinning is only on upper portion of tubes i.e. portion where steam is present while bottom tube portion where condensate is in tubes is not having thinning. We want to know following-
1) Reasons for such heavy metal loss/tube thinning from OD side and only on upper portion of tubes
2) Path forward to avoid such heavy loss of metal /tube thinning
3) Any up-gradation required in tube bundle metallurgy of Reboiler.
(1)
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)
29/03/2014 Q: We are having Feed Surge Drum in Diesel Hydrotreating Unit, for maintaining pressure of FSD we provided Blanketing Hydrogen and relief to LP Flare. Fail safe positions for the Control Valves in Hydrogen is Fail Open, LP Flare is Fail Close (Where as it was reverse in previous company where I worked last). If in case of Air failure Hydrogen to FSD CV gets open and may get pressurise as there will be no any relief
What may be the basis of selecting the fail safe position of both CVs? 		(6)
28/02/2014 Q: Please share refiners experience of Crude Oil Floating Roof Tanks Roof seal & Secondary seals of synthetic rubber material design life & replacement frequency. At our Refinery Complex there is no leak detection system installed.  
21/12/2013 Q: Does any regulation / Code of practice calls for 300 lb rating Piping around AMMONIA storage tanks (liquid piping and Vapor piping)? Although the operating pressure in the vapor lines is around 500 mm WC , piping used is 300 pound rating
Is it mandatory to size the PSVs of ammonia storage tank for fire case? Ammonia shows little affinity towards fire due to very narrow range of LFL and UFL.
 		(1)
06/12/2013 Q: What is the suitable Gas detector (for leak detection) in the higher elevations of around 50 meters. The service used were Crude at 75C and Crude column overhead vapour at 117C.  
27/11/2013 Q: When a pump feeding a crude column through the heater stops, should the evaporation of the residual liquid in the heater due to the residial heat in the heater refractory be considered for the relief case (e.g. total power failure case)? Or is it normally ignored due to limited inventory of liquid in the heater? (2)
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)
24/08/2013 Q: Which Refinery Process Units Heater tubes are most often replaced and after how many years of operation?  
24/08/2013 Q: There are two different types of Pilot PSVs used in our refinery
1. Self Pilot (for which Pilot tapping is taken from PSV's body) and 2. External pilot (for which Pilot tapping is taken from PSV's u/s piping can be far from PSV)
What is the criteria of selecting 1 or 2? 		 
30/07/2013 Q: We are currently experiencing continued plugging of our refinery fuel gas control valves, strainers and burners. We went through a re-org 3 years ago where one of reformers was brought down. Since then, we have seen an increase of chloride salt contaminants to our fuel system from our other reformer. We currently run 2 molecular sieves in series on or hydrogen header. I proposed to increase heater reliability and reduce chloride salt contaminants to take second mole sieve and pipe the fuel gas header to it. This would of course be after testing hydrogen chloride content with only one sieve in service and projecting those results on compressor reliability from our maintenance group. If no real future damage can be projected and current single phase mole sieve can handle hydrogen system, would a mole sieve for the fuel gas be an adequate route since the vessel is already there and would only require a piping mod?  
04/07/2013 Q: I want to design a Jockey pump for our Refinery Fire Water Network.
Which NFPA code is applicable?
What would be design basis and criteria for sizing the Jockey Pump?
I also want to design Overpressure protection system for Fire Water Network.
Which NFPA code is applicable?
Some Designers do not recommend to install PCV or Spill Back line to control Overpressure. Why? 		 
03/07/2013 Q: Fire Water Network normally have both Motor Driven and Diesel Engine Driven Pumps for emergency use in case Fire Water Network pressure drops below certain set point.
My question is, normally motor driven pumps are designed to kick-in on Auto start. Is it possible to design the operating philosophy so that Diesel Engine Driven pump kicks in first and then the Motor driven pumps? What are the pros & cons ? Is there any relevant NFPA code which is applicable?
 		 
27/06/2013 Q: What are the allowable limits of lighter material (Flash point etc) in Process Units Feed like Visbreaker/Thermal Cracker.. ?

 
08/06/2013 Q: We are operating a balanced draft heater in DHDS units. What should be the action on Forced Draft fan in case of tube rupture of the heater and why...? (1)
03/06/2013 Q: What is the Wheel Chamber in a Centrifugal Compressor and what is its purpose?
 		 
30/04/2013 Q: What is best refinery practice for the location of TSVs in offsite area and TSVs discharge outlet?
 		 
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)
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)
01/03/2013 Q: I have below doubts regarding Gas Chromatograph (GC)which is installed in the laboratory. GC in the present case is off line (sample is injected not continuous)
GC uses Hydrogen as a fuel or carrier gas.
a) Is there any chance of leakage of hydrogen from inside GC to outside?
b) In the GC room does HAZARDOUS classification applied due to use of Hydrogen and Process samples (hydrocarbons)?
c) Does electrical items - switches ,lighting fixtures needs to taken as flame proof, explosion proof or intrinsic safe?
d) Can GC be classified as flame proof? If so, what components of GC will be qualified as flame proof?
e) Are there any case studies available about explosion in GC room due to hydrogen leakage? 		(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?  
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)
25/11/2012 Q: What is the Best Practice for time switchover between standby rotating equipment? (1)
24/11/2012 Q: In many molten sulphur pits where solid sulphur is melted with LP steam coils, fires keep occurring.
What could be the reasons? 		(1)
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?  
03/09/2012 Q: Emergency Depressurization (EDP) System of Hydrocracker Reactors:
Our Hydrocraker unit has two emergency depressurization systems : 7 bar/min (100 psi/min) and 21 bar/min (300psi/min). Assuming a pressure of 157 barg when 21bar/min EDP is activated, how long should pressure decrease at a rate 21bar/min? how does depressurization rate vary ? 		(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)
17/07/2012 Q: What is the main difference between Accumulation and Over pressure for a relief valve? could anyone explain their importance while sizing a relief valve. (1)
17/07/2012 Q: What is the significance of PSV's discharge coefficient? how it will impact on relief valve sizing?  
17/07/2012 Q: Could anyone explain the significance of PSV's %blowdown value that we need to mention when sizing a Pressure Relief Valve.  
11/07/2012 Q: How long we can operate a Refinery Heater above its design duty keeping all other Heater parameters within design limits? How can a Refinery Heater design duty be reduced without reducing a Refinery Process Unit throughput?





 		(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)
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)
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)
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)
23/01/2012 Q: My question relates to the minimum MAT activity that can be reached in an FCC unit. The main objective in one of our FCC units is maximum middles distillates, and we run this unit at very low severity. The MAT activity of the e-cat is 54-55%wt, with some punctual values of 52-53%wt.
We would like to decrease e-cat activity even further, but we have some concerns and doubts about potential problems that could arise, like definitive loss of cracking activity, significant increase in bottoms production, etc.
Has anyone experience running and FCC unit at MAT activity below 52-53%wt? What problems could appear with so low MAT activity? 		(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)
06/01/2012 Q: We use air to regenerate caustic in our LPG sweetening units. And we send the off gas to heater chamber to decompose hydrocarbon content and bad odor materials in it. We install frame arresters and skin temperature elements in the piping system of these off gas lines for safety consideration.
Fuel gas supply to heater burners, we use typical design (i.e. two blocks and one bleed design initiate by ESD of heater), we do not install flame arresters in these lines.
We found one plant outside our refinery, they installed flame arresters in fuel gas lines. Since the oxygen content in fuel gas is trace and well controlled and monitored, we do not think flame arrester is necessary. Please advise. 		(2)
28/12/2011 Q: We monitor the VOC emission comes from our VR, Asphalt and MCB(Main Column Bottoms from RFCC) tanks regularly, and found the VOC emission range from several hundreds to several thousands ppmv.
These tanks are fixed roof design followed API code.
The VOC contains C1, C2 and C3 compounds mainly, and trace sulfur compounds with bad smell.
Since we have successful experience of caustic scrubber installed downstream of tanks to remove trace sulfur compound (i.e. H2S). We plan to install a downstream scrubber to improve this situation. Would you please advice which solvent is suitable for this application (for light hydrocarbon removal from vent), or other system can be used? 		(2)
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)
23/11/2011 Q: What is the safe spill control procedure of the 98% sulphuric acid inside the plant for environment management and safety management?
Maximum quantity stored is 200Lit with dyke, but no secondary disposal means from dyke. 		(1)
17/11/2011 Q: On distillation unit, we have crude surge drum at the beginning of the unit. This surge drum has PZV open to the crude column flash zone. What is the effect if the PZV open for releasing high pressure to the flash zone? And how about transfer this PZV to open on the manifold of the crude tanks? (2)
21/10/2011 Q: Remote Isolation Valve (RIV) Fire-Protection Requirement
We use pneumatic RIVs in our system for shut-off operation during emergency condition (for example, fire). Two valve types selected used in these services, one is Ball valve, and the other is Triple Eccentric Butterfly valve. All air failure to close (AFC) design.
Since AFC design, we didn’t make specific fire protection requirement for actuators of RIVs.
There is a revamp project, licenser request actuators and instruments of RIVs shall be protected by thermal insulated boxes. According to information from vendors, the box is heavy and difficult to maintain.
Do we need fire-proof actuator even AFC design? 		(1)
21/10/2011 Q: Valve Type Selected Used in Emergency Depressurization (EDP) System
We use ball type valves for EDP system in our existing hydro-treating and hydro-cracking units. And they work well.
Now, we want to select Triple Eccentric Butterfly valve for EDP system in our new project. Please advise.
 		(2)
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)
24/05/2011 Q: In the double wall refrigerated storage tank (both tanks are steel tanks)
a) Does Fire case of liquid boling is applicable due to process vapor acts as insulation (in the annulus)?
b) Is it required to protect the outer tank by water curtain since its integrity will be lost due to fire?
 		 
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)
04/04/2011 Q: Our overhead wash water which is demineralised water addition is not continuous at CDU plant. Water is added to 2 bundles in 4 hrs. Then water is added to the next 2 bundles and so on. This implies that the 1st bundle in which water is added receives wash water after a gap of about 1.5 days. We use neutralising amine and keep ph between 5.5-6.5 while having almost no corrosion on overhead lines (monel cladded). Caustic is also added at the downstream of the desalter. The contractor who provides services and chemicals is claiming that addition of more wash water to have continuous wash will decrease the consumption of neutralising amine. In our opinion this will not work since the amount of wash water will have no impact on the mass of chlorides available in overhead stream. Would you please comment. (4)
25/02/2011 Q: Is there any chances of formation of pyrophoric substances inside naphtha /crude oil tank after long time? if yes, then how to remove from tank? (4)
20/02/2011 Q: Normally Flare KOD bottom is drained to closed blowdown (CBD) which is floating with flare even though flare KOD level is maintained. Why so? (1)
17/02/2011 Q: We have Power Recovery turbine (PRT) to recover the power from Flue gas coming from regenerator. Because of seal gas failure Flue gas about 600°C coming outside from PRT. We don't have any back-up seal gas on site. How can we tackle the leakaged flue gas from PRT? (1)
03/01/2011 Q: What is the difference between PRV and PSV? What will be governing case for sizing a PRV for boiler's de-aerator? Also how to calculate relieving temperature? (3)
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.  
19/12/2010 Q: Our project has an amine FCCU and amine sweetening and SRU, but sulfur recovery will be in service 1 year after FCCu start up. There is a problem with feedstock of SRU that must be sent to acid flare (with 32 m length). What can we do with this stream with 80%wt h2s witout sending it to flare? (4)
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)
08/11/2010 Q: I am working on a flare gas recovery project. We understand purging of flare header is recommended to maintain positive pressure and air ingress. My query is, if I have liquid seal or any other device between knock out drum and flare stack to divert gases from K.O. Drum to flare gas recovey unit (FGRU), and maintain a positive pressure upstream of seal, do I still need to purge flare header, or only flare stack needs to be purged to provide air ingress?
If at all purging is required then what is correct reason for purging?
Although, as liquid seal/or any device (fast opening valve placed) will result in positive pressure upstream of seal and K.O. Drum and I feel that purging of flare header is not required and only flare stack needs to be purged. 		(3)
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)
29/07/2010 Q: We have one PSV Set pr.:-16.5Kg/cm2, Cold Set Pr:-17Kg/cm2 & back pressure:-1.7 Kg/cm2. However, after dismantling it was observed the bellow is in cracked condition. We have withdrawn the bellow against the psv code but it doesn’t match with original bellow. We have also looked for other matching probability but we have failed to find any matching bellow. we have to install PSV without bellow. What will be new pressure set for the PSV without bellow?

Further question:
Do we need to raise the CDSP (cold set pressure) of PSV? if not, then why install bellow type PSV? 		(2)
29/07/2010 Q: In one of exchange PSV was set at 16.5 kg/cm2g. Now its rupture disc got damaged. what will be the new set pressure for PSV without rupture disc considering its flare back pressure of 1.7 kg/cm2g? (2)
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)
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)
20/04/2010 Q: We want to install a Diesel generator near an already operational Gas generator located inside a gas installation for emergency power supply. As per OISD standards or other regulations is there any minimum inter-distance required?  
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)
30/03/2010 Q: In flare header line, we keep positive pressure by water seal in water seal drum upstream of flare stack. During steam out operation in turn-around period, we plan to steam out the hydrocarbon in the process system to the flare system for reduced VOC emission to atmosphere. Since the condensation of steam may cause negative pressure in flare header line, this operation is safety concerned. Please advise. (4)
18/03/2010 Q: We are about to install 2 PSVs on a new vessel designated for hydrogen storage. The vessel is horizontal and is placed on ground level in close proximity of hydrogen production unit. In case of pressure buildup the PSVs will vent excessive pressure to atmosphere. I want to know what should be the optimum/safe height of the PSV vent? (2)
06/03/2010 Q: Can you tell me about the application of pilot operated PSVs? Where or why are these type of PSVs used? (2)
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)
10/02/2010 Q: We have a Sour Water drum (Operating Pressure = 46 kg/cm2(g)). We have installed an angle control valve to kill the pressure from 46 kg/cm2(g) to 6 kg/cm2(g) and because of some slurry particles.
System upstream of the Angle valve is designed for 50 kg/cm2(g) and downstream of the valve is designed for 20.5 kg/cm2(g).
In case there is an auto control failure of this Angle control valve, what is pressure can be seen by the system downstream of the valve?
Is it recommended to increase the Design pressure of the downstream system or provide any protection ( safety valve) downstream of this Angle control valve? 		(2)
08/01/2010 Q: In our refinery we are going to replace our Vacuum Distillation Column. Please suggest some designer/manufacturers' names who work in this field. (1)
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)
24/12/2009 Q: What is the general magnitude of pressure drop across the diffusion type molecular seal in flare stack? How do you calculate the pressure drop across the same?  
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)
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)
23/11/2009 Q: Cumene is known as isopropylbenzene, it is a flammable, colorless liquid that serves as a component to high octane fuels. Can any body tell me the best practices followed for storing?
In the hydrogenation section, if the isopropylbenzene had to be routed to storage what additional safeguards need to be required other than the coolers and N2 blanketed tank? 		(1)
21/11/2009 Q: In our refinery we want to introduce an inspection software for data and history keeping purpose. Can anyone give me suggestion which software will be useful to serve the requirement?  
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)
16/11/2009 Q: Is there any safety procedure for damper operation in the furnace? Specially in case of failure of damper wire. Is it necessary to keep provision 100% opening in case of damper wire failure? (2)
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? 		 
21/10/2009 Q: Is it safe to consider back pressure of 50-70 kg/cm2g when my PSV set pressure is at 229 kg/cm2g? Why are we limited to 3-5 kg/cm2g back pressure maximum when we are designing the HP flare? API 520 part 1 says that I can consider up to 50% of set pressure of balanced PSV, so can I consider up to 100 kg/cm2 g when my PSV is set at 220 kg/cm2g? If not, then what is the reason? (4)
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?  
15/10/2009 Q: I have a PSV with a set pressure of 229kg/cm2g. What could be the back pressure I consider while designing the flare header so that it would be cost effective as well as safe? (4)
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?  
10/05/2009 Q: In India layout of terminals are guided by OISD-118. Please suggest if Storage tanks for petroleum products class A and B can be kept in the same dyke area. Capacity of tankage is 22,000KL. (1)
18/04/2009 Q: What special earthing is normally provided in the LPG sphere for the elimination of electrostatic charges? (1)
17/03/2009 Q: Are the declining costs of metallurgy providing an incentive for construction of 2000+ ton heavy-walled hydrocracking reactors? Is the application of advanced manufacturing techniques, such as Cr-Mo vanadium welding, becoming the 'norm' for fabrication of heavy walled hydrocracking reactors? What other developments coincide with new hydrocrackers designed to operate in a highly corrosive environment? (1)
13/03/2009 Q: In a particular complex onshore gas plant, flare network purge is via continuous flow of N2 controlled through flow orifices, purge points being located at the ends of all major headers. There are also a few fuel gas purge connections but these are located close to the flare stack. Under normal operation fuel gas purge points are closed, ie no flow.
I would like to know what would be the risk of stopping all N2 purge gas and starting fuel gas purge. This would lead to the flare network being purged only close to the flare stack. Rest of the network will have to depend on control valves / other vents for a positive gas flow towards the stack.
We can assume for the sake of this discussion that the fuel gas rate is sufficient to safeguard the seal function of preventing air ingress through stack. 		(3)
12/02/2009 Q: A coalescer is required to be installed in straight run kero line of the CDU. What are the requirements under OISD (Oil Industry Safety Directive ) for this? Are there any other safety directive norms that need to be considered? (1)
16/12/2008 Q: What reliability issues can the use of high pressure unit charge pumps (multistage centrifugal pumps) in parallel pose to distillate hydrocracking processing ? (1)
02/11/2008 Q: Sample Probes: How are the vibration calculations done (vibration calculations to ensure that the probe cannot fail to resonance effects / harsh process conditions)? Are there any software packages available to check that the sample probe selected can withstand the process parameters (pressure, temperature, flow, fluid density, etc.)?  
16/10/2008 Q: On the LPG (Liquefied Petroleum Gas) outlet line from the bottom of the storage vessel (Horton sphere or mounded bullet), remote operated isolation valve (ROV) is provided for isolation of the facility in the case of emergency. This remote operated valve shall be fire-safe type conforming to API 607 or equivalent in order to protect the valve from external fire situation. In case of pneumatic operated ROVs, we would like to know whether the actuator system comprising of diaphragm & spring requires fire protection? If it is required, how the protection can be given? Is there any mechanical design requirement for the diaphragm/spring to protect the actuator from external fire case? What is the standard practice?  
08/09/2008 Q: Modernization, expansion or product quality improvement projects in refinery or petrochemical Industry may require additional secondary processing plants and facilities. In such cases, the existing size of main Flare header and also main Flare stack along with the stack height may be limiting requiring revamp of both of them. Based on acceptable radiation levels from the Flare stack, it is required to have a minimum separating distance from Refinery Flare to other facilities (like process units or tankage etc) at refinery & petrochemicals. Is it, from safety point of view, possible to locate the new Flare stack closer to the old flare stack? If so, what should be minimum separation distance between the two stacks? What are the criteria for such case? (3)
14/07/2008 Q: In a vacuum system for drying HSD, how safe is using a top pump around to reduce the size of barometric legs and hot well? Considering pyrophoric iron fires since no steam is being used in the process.  
11/07/2008 Q: How safe is giving a top pumparound in case of a vacuum column considering pyrophoric iron fires etc.
The vacuum maintained is approximately 5 kg/cm2 (g). Is there any particular temperature limit for pyrophoric fires as the top temperature of the system is around 80 deg C? 		 
03/07/2008 Q: This question is related with capacity estimation for safety relief valve for external fire case for heavy oil services. Typical VDU bottoms stream which is sent to delayed coker plant as feed stream is received in a surge drum inside coker plant. Being a heavy stream, the boiling point is high say 550 Deg.C plus. For external fire case, the heavy oil will start cracking and will release the lighter gases. Being a carbon steel vessel, the vessel will start approaching to rupture conditions after temp reaches 400 Deg.C but the material has still not started boiling or not started cracking. How do we protect such equipment from external fire and can anyone guide on arriving/estimating cracked gas quantity? How does one estimate cracking temperature? Please help on sizing PSV for such cases. (2)
02/06/2008 Q: For certain standards pertaining to control valves used in hydrogen services, why is it recommended that installation of a bypass (and blockvalve) be avoided? (1)
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?  
19/05/2008 Q: What happens if a steam reformer heater (hydrogen unit) is only fed by steam for a long time in stand by mode? Is this action harmful for catalysts?  
19/05/2008 Q: Is it possible to run a terrace wall reformer heater only with one cell? (Heater has two separate cells in west side and east side and feed, steam and fuel gas is split for both cells)  
19/05/2008 Q: We need some info about drying of hydrocracker catalyst by long period recycle gas circulation in case of start up and shut down of hydrocracker unit and problems caused by this phenomenon. Can anybody help us? Is it very harmful for catalysts? (1)
17/05/2008 Q: We have two TIC in reformer heater outlet manifolds for temperature control which act on fuel gas of heater. Low limit of these TIC,s are 700°C, but in some cases (i.e start up) we need to control temp. lower than 700°C. One of our operators suggested we change the lower limit of TICs to less than 700°C. Is this possible without any safety and design problems? (1)
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)
11/04/2008 Q: What is the governing case for dispersion whether it is high flow and low wind velocity or less flow and low wind velocity? (2)
11/04/2008 Q: As per OISD-STD-118, petroleum storage tank shall be located in dyked enclosure with roads all around the enclosure. Now our products are Class C i.e. excluded petroleum products and some of them are stored in atmospheric tank and some of them in Vessels, so do we need dyked enclosure for products stored in "VESSELS" ? or any other sort of protection is required in event of spill over scenario.
Thanks in advance. 		(2)
01/04/2008 Q: In what type of situations can we use 2 solenoid valves in series and when do we use 2 solenoid valves in parallel ? (2)
01/04/2008 Q: What is the problem in providing PSVs only on the feed line in a distillation column and not providing any PSV on the overhead line, given the fact that the PSVs on the feed line have been designed for reflux failure case? (1)
24/03/2008 Q: We are experiencing falling of coke particles from the refinery hydrocarbon flare stack of late during sudden increase of gas flow subsequent to operation of dump valve of hydrocracker. We would like to know whether such incidents have occurred elsewhere ? If yes, what are the probable reasons and how can they be mitigated ? It may be noted that flare gas velocity during dump valve operation is well below 0.5 Mach. (1)
11/03/2008 Q: We don't have any clear procedure in our operating manual about degassing procedure for hydrocracker reactors. Can anyone help us?  
04/03/2008 Q: We have a problem with our Hydrocracker VGO feed filters resulting in frequent backwash operations due to high Del P. Can you please ascertain the reason for the same as we do not get any FeS or suspended solids in the backwash stream analysis. Is it because of the asphaltenes as we process deep cut VGO (360-580+ degC) along with Heavy gas oil? (8)
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?  
06/02/2008 Q: In a cross country gas pipeline, is any passive fire protection system like fire water storage / pumps / hydrant network or fire water spray system etc are required to be installed at compressors stations and delivery stations? If, so what cooling rate should be considered for fire fighting system?  
05/02/2008 Q: Shutdown Control valves are required to isolate the process in case of emergency. What are the testing parameters and acceptance values of such control valves testing? Details of time of closures, time of openings, tightness criteria, fire rating etc would be helpful.  
05/02/2008 Q: As one of the layer of protection, we find that in normal Hydrocarbon process furnaces, explosion doors are provided to minimise the effect of furnace pressurisation from explosion inside specially during startups. But the same are not considered in Gas/Naptha cracker furnaces. Why?  
05/02/2008 Q: In Sulphur Recovery Unit, provision for Nitrogen purging exists in the Reactors to prevent temperature runway. In certain cases it has been found that manually operated isolation valves are provided on Nitrogen injection line instead of remote operated isolation valve. This makes it difficult to take immediate action and control the temperature excursion. What is the design practice by process licensors?  
04/02/2008 Q: Thermal safety valves (TSVs) are used in hydrocarbon lines and are supposed to take care of pressure generated from increase in line temperature. However, problems like passing and also joint leaks creates problems. Any experience to improve reliability of TSVs would be useful.  
22/01/2008 Q: Can anyone tell me the average time it takes to clean a flare line please? (4)
29/11/2007 Q: While designing a railway wagon gantry for POL unloading with LPG, how much distance should be kept from POL pipelines with respect to LPG unloading? Any special precautions to be taken ?  
22/11/2007 Q: We want to install block valves on subheaders of pilot line in a big terrace wall reformer heater (8 block valves for 8 subheaders) for maintenance. According to safety rules, is this action is safe? Is there any standard or design note for this action? (1)
01/11/2007 Q: What are the pre-requisites and requirements for a petrochemical plant start-up (e.g., naphtha-based steam cracker complex)? Does the facility’s effluent treatment plant need to be operational before actually feeding hydrocarbon into the complex? (2)
24/10/2007 Q: How do you measure the CO2 emissions from your plant and can you specify the CO2 emissions from individual pieces of equipment? (2)
26/09/2007 Q: On a crude unit we have a fired heater with thermocouples on each pass exit.
We have experienced thermowell fractures twice in the past three years. When the thermowell breaks, crude oil starts leaking. It is very unpleasant situation because of the high crude oil temperature and possibility of fire.
The possible cause of the fracture is pass vibrations on heater outlet.
I find in the literature that if there is the possibility of a thermocouple fracture it is necessary to install a valve on the thermowell end and in case of fracture it is possible to close valve, cut wires and stop leaking.
Does anybody know of a manufacturer or solution for this problem? 		(2)
19/09/2007 Q: Please advise on reduction of ammonia emissions from a fertiliser plant.
Our emissions from a urea plant stack is about 150 ppm, and we need to reduce them to 50 pp to comply with EPA regulations. I know some plants are provided with an acid washing system.
I would be grateful for advice from anyone with experience in this field. 		(1)
06/09/2007 Q: We have a fractionator overhead receiver in the hydrocracker unit without any PSV on it. We want to know why the designer didn't put any PSV on the receiver. Please introduce a good and practical refrence for this matter, if it is possible. (2)
05/09/2007 Q: How can we improve fluidizing in a stand pipe regenerator FCC? (1)
05/09/2007 Q: I am working in a Butadien Extraction Unit. Can you tell me the major safety aspects to be considered in a Butadien Plant? (2)
06/08/2007 Q: In certain gas processing installations, we find that the Pressure Safety Valves (PSVs) on demethaniser, deethaniser and ethylene towers vent directly to the atmosphere. Is this acceptable practice or should PSVs always be connected to flare systems? What is best practice for routing of safety valve discharges of such columns handling lighter hydrocarbons? (6)
06/08/2007 Q: In certain gas processing installations, we find that the Pressure Safety Valves (PSVs) on demethaniser, deethaniser and ethylene towers vent directly to the atmosphere. Is this acceptable practice or should PSVs always be connected to flare systems? What is best practice for routing of safety valve discharges of such columns handling lighter hydrocarbons? (6)
31/07/2007 Q: We are currently reviewing our position regarding the bulk loading and unloading of LPG (Liquefied Petroleum Gas) at tank wagon gantries (rail) in the oil terminal. Our existing provisions specify that LPG rail loading/unloading gantry shall be located on a separate rail spur and shall not be grouped with other petroleum products. In this context, we like to know the following:
1) What are your guidelines for loading/unloading of LPG at a tank wagon gantry ?
2) Can LPG be loaded/unloaded with other petroleum products e.g. Motor Spirit (MS), High Speed Diesel (HSD), Naphtha at the same gantry?
3) Whether loading/unloading of both the products is permitted in the same Gantry with only one product loading/unloading at the same time, i.e When LPG is being loaded other products are not loaded, and vice versa
We would appreciate your views on loading/unloading of LPG and POL products in the same rail spur. 		 
31/07/2007 Q: Due to processing different types of crude oils at a petroleum refinery, the density of ATF (Aviation Turbine Fuel) produced varies wildly resulting in layering in storage tanks. This is not acceptable and there is apprehension that if a jet nozzle is used in the storage tank and is subjected to circulation, the electrostatic charge will accumulate (considering low conductivity of ATF) and would be unsafe. Do you experience such problems? If so, how you prevent or correct the layering problem? What method and precautions are taken? Please confirm whether use of a jet mixer in the tank for ATF circulation would be wise. (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)
24/07/2007 Q: With several recent refinery incidents resulting in unexpected plant shutdowns and even fatalities, more attention is being focused on safety and reliability programs. In this regard, how often should gas-monitoring instruments be tested and calibrated? (2)