Eh, "destroyed" implies, to me, that the item is damaged to the point of being unusable. So, if there is still functional need for the equipment then a replacement would be appropriate. However, that doesn't mean the replacement has to be new, it just has to be suitable for the application.
If you're asking about steps that can be taken to determine if a fire damaged vessel can be put back into service the answer is yes. I don't know the its specifics but API-RP 579, Fitness-for-Service, may provide some criteria to go by. At the ABSOLUTE minimum an MAWP based pressure test should be performed.
Depending on your circumstances, it you do it "right" you could easily spend more time and money performing the evaluations than going with a new/undamaged vessel. Then there's always the liability factor to consider.
Review the 2004 Edition/2005 Addendum of the National Board Inspection Code, NB-23, RB-9250. You will need to work closely with your Insurance Agency and Jurisdiction or Regulatory body regarding salvage and operability.
I'd be surprised if the company's underwriters wouldn't insist on new no matter what. It's no money out of their pocket to require it, and it gives them a firm basis for accepting the risks of resumed operations.
As dtn6770 pointed out, you need to define "destroyed". Having spent several years working in an oil refinery we dealt occasionally with vessels and piping which had been exposed to fire. I'd venture to say there isn't a refinery in the world which hasn't been in similar situations. Only the big ones make the news, and not even all of the big ones make it. Keep in mind "Exposed" doesn't mean "destroyed."
My first "big incident" was an explosion which rattled the windows in my apartment 35 miles away... Only one vessel in that refinery was replaced due to damage (I replaced a few others for debottlenecking the units).
Get a copy of API-579 for some guidance; in the mean time, start taking hardness readings of the affected steel. Steel which was protected by insulation will most likely be ok. Piping which had process fluid running through it for the duration of the event will most likely be ok. Replace gaskets and studs on flanges. Check/replace valve packing. Check platforms (ladders tend to not be damaged) for structural warping, especially the compression flange of structural framing.
'Course there's a distinction between being self-insured and having to deal with insurance agencies, as alluded to in some of the above posts.
Assuming that the vessel(s) was exposed to fire but not destroyed, also try to determine the temperature of exposure in addition to the examinations proposed above. This can be done by scale evaluations and visual damage incurred during the fire exposure.
As I have been tracking the various responses to this thread, I decided to jump in again because the various test methods mentioned above like portable hardness, or nondestructive and visual examinations must be performed by qualified individuals.
I absolutely agree with the suggested tests. However, I need to mention that administration and interpretation of these tests must be done by qualified engineering personnel, otherwise misinterpretation of results and bad conclusions will be reported.
If the OP or their company does not have an understanding of portable hardness testing, or a qualified portable hardness testing procedure along with an experienced materials engineer to interpret the results, then one should be brought in from the outside. IMO, evaluating fire damaged components must be done by qualified professionals.
MJCronin;
I should have answered your question above. Exposure of PV steels to elevated temperature like those from a fire may not result in increased hardness. In fact, depending on actual conditions in the field, the properties of the steel could change from over tempering, or could change from increased hardness caused by quenching (direct exposure to water spray at elevated temperatures) or could even remain the same. It all boils down to service temperature and cooling rates. Detailed visual and surface NDT should be performed to assure no permanent deformation or cracks from thermal shocking.
I believe the acceptable level of hardness is under 22 rockwell. We had some propane tanks exposed to a fire and the paint was burned off on one end. We did spot readings on the tank and nozzels.
Sorry, I don't have an answer for you. I always had a qualified metallurgist handling that end of the stick. I skimmed thru API-579 section 11 which is dedicated to FFS of fire exposed equipment and found no guidance for an acceptance criteria.
metengr-
I totally agree. Qualified consultants should be brought in for plants which don't have adequate staff capability. But even those who need consultants can benefit from being familiar with API-579 section 11. Without knowing what the consultant will be looking for, plant personnell will likely clean up the fire damaged area in preparation for rebuilding. This, of course, will destroy much of the visual / physical indicators which the engineers will be looking for to "map out" the extent of the fire zones.
Are there any publications, reports or "white papers" that discuss the technical details on the re-use of fire exposed equipment ?
I would assume that there would be tremendous pressure put on the plant engineering staff by management (hell bent MBAs?) to find some kind of quick evaluation method.
Doe anyone know if there a company that specializes in this kind of inspection ?
MJCronin;
I have some Codes and Standards colleagues who work for Hartford, FM and ACE inspection agencies. I would contact their Boiler/Machinery or Loss Prevention groups to obtain this information.
Here is my personal experience with ASME Code Section VIII, DIV 1 vessels that have been in "fire" damage areas both offshore and onshore:
1) First if possible get a copy of the UIA, you may need it later.
2) Identify the material via the UIA or if not, logic assumptions can be made via the nameplate information, MFG Date, hydrotest pressure, RT-X and etc.
3) I use a vessel design program and plug the information to get the expected material thickness for the head and shell with an assume liguid level.
4) Do in-depth visual inspection of the discoloration areas. Look for the paint in particular, assuming CS, because different paints degrade at different temperatures. Example Inorganic Zinc, above 900 F starts to deterorate quickly. Point is, do we have a vessel that now went over 1100F for P1 material or not.
5) Hardness reading can be useful for P1, but materials like SA-516-70 you will find the hardness goes down. The reason is if at some temperature above 800F the heat for extended periods removes the cold work from rolling the plate and therefore reduces hardness, i.e. BHN.
6) Best advise given above, get a professional that has documented experience working with AI agency to review and make determinations. At the end of the day, re-hydro test and if necessary, request a R-1. I am sure you will find something to fix.
7) No fast assumptions here when you get into these. Best example is like calling a doctor on the phone and saying "I hurt, what is wrong with me?"; lol. To do this properly you must see the patient and know the service the vessel was in and what the fire media was made up of, like burning by-product in a paper mill can have some nasty stuff in it.
Only my opinion and certainly does not apply to all cases.
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