Heat Exchanger Tube Defect Assessment 1

[James01]

I have a Shell & Tube Heat Exchanger that we have just found pitting corrosion in the tubes during an IRIS inspection.

What I am looking for help on is where can I find information on the tube minimum WT for pressure retention calculations that I should apply in this situation.

For information the tubes are CS 25.4mm OD; 12 SWG (2.64mm WT) design pressure is 144 barg @ 115 / -7 degC tube side. 14 barg @ 150 degC shell side.

Thanks in advance
Jim

 

[LuizSouza]

By the way. What's the pitting corrosion location? Near the tubesheet?

 

[James01]

The pitting is random throughout the bundle. I suspect it is underdeposit corrosion as the exchanger was only in intermittent use for the last 8 years.

There was random pitting detected on the outside surface of the tubes also, but this is not to the same level.

 

[metengr]

James01;
The code that typically governs in-service inspection/repair of pressure retaining items is the National Board Inspection Code (NBIC). In-service corrosion evaluation is described in RB-9130 in the 2001 NBIC/2003 Addendum.

However, you do have a second option. If your Jurisdiction permits, you could use API 579 to evaluate the extent of pitting damage and determine if you can leave "as is" or require repair.

 

[EdStainless]

If the pitting depth is light, compare your results to the minimum allowed wall thickness in the original tubing specification.
Eventhough IRIS is very reliable I would still suggest that you remove a tube for destructive evaluation. This will not only verify the IRIS results but also let you see if there are any other conditions htat you should be concerned about.

= = = = = = = = = = = = = = = = = = = =
Corrosion never sleeps, but it can be managed.

http://www.trenttube.com/Trent/tech_form.htm

 

[rmw]

Alternatively, if you fear for the life of the Hx, there are companies that can hydro test each tube individually, to a test pressure that you select, max, min, or anything in between, and force the weak ones to fail before they do so in service.

It could either confirm your worst fears, or give you a fair degree of confidence that it might live in service.

Tube sampling as recommended by edstainless is an excellent suggestion.

Oh, the joys of CS tubing. Something tells me that you did not nitrogen blanket this Hx while it was out of service. But I could be wrong.

rmw

 

[jte]

James01-

Most of the time a wall thickness isn't even calculated... But you have a pretty high pressure. Based on a simple P*R/S calculation (a variation of which you'll find in PV and piping and FFS codes and standards) using allowable stress S=20000 psi you need 0.052" or 1.3mm wall thickness for circumferential stress due to internal pressure. Less than that might be acceptible for pitting (see API-579). However... you need to also check the longitudinal stress. The long stress due to pressure will be half of the circumferential (so req'd wall is about 0.026" or 0.65mm) but you need to add the stress (and thus req'd wall) due to the weight of the tube and its contents (though the shell side fluid might help it float a bit). Take the spacing between supports (baffles) and run a simple beam calc: Fb=MC/I. You might find that the combined pressure + weight longitudinal stress governs.

jt

 

[James01]

The bundle did not have a Nitrogen blanket when not in use, our production colleagues assumed that because we were injecting corrosion inhibitor this would provide protection even when stagnant.

Thanks for all your help, we are now off to do the analysis and see if we need a new bundle and a change of material.

Thanks
Jim

 

[van11]

Hi James
I've got the same problem. I would like to found out how to calculate the maximum corrosion allowable of tube of heat exchanger.
Have you found how to calculate it.

Thanks for your help

Vanessa

 

[James01]

Hi Vanessa

I used a the advice from JTE listed above and then used API579 to carry out the full FFP assessment.

The MAWT was calculated using the P*D/S gave me 1.3mm for the conditions.

You

 

[RNDguy]

James01,
Your woes sound familiar. We make small firetube boilers with CS pipe (yes, schedule 40, A 105 pipe, not tube) as part of one of our products. The shell side is sealed and under vacuum (closed circuit). There is a corrosion inhibitor on the shell side. Most of these boilers never have any problems after long years of service. But very occassionally, a few boilers have been returned with heavy corrosion of the pipe on the shell side near pipe-to-tubesheet joint. We were not sure, and suspected galvanic corrosion, but after spending a few grand in preparing representative samples and having them tested for corrosion in specialised testing labs, no evidence of galvanic corrosion was found. It is very difficult to assess a unit's life-style after many years of service in possibly different hands, but after obtaining such info it leads us to suspect that these units may have been stagnant with shell side water (& corrosion inhibitor) sitting there sealed and under vacuum and this might have something to do with the resulting corrosion.
However, my question is, why should it be so? What can happen under stagnant conditions which is different from operating conditions that it may cause such corrosion? Or are we on the wrong track?

 

[EdStainless]

RNDguy,
A lot of things chande when conditions are stagnant. The biggest is that there can be local differences in the surface chemical reactions. There might be air bubbles, fouling, or just local material variations (surface finish) that give rise to small electrochemical differences.
When things are flowing very small EMF will not cause and issue. But in static systems the damage can add up. And of course once corrosion starts the corrosion products only make the local conditions even more different, usually accelerating the damage.

= = = = = = = = = = = = = = = = = = = =
Corrosion never sleeps, but it can be managed.

http://www.trenttube.com/Trent/tech_form.htm

 

[metengr]

RNDguy;
Under certain conditions where you have stagnant condensate in boiler tubing or heat exchangers, surface corrosion can occur from oxygen concentration cell corrosion. This is a very common corrosion mechanism, and results in corrosion pits that are rounded in shape. The areas that have reduced oxygen content can become anodic in behavior resulting in small corrosion cells on the surface of the steel.

Typically, you are better off using a nitrogen blanket in lieu of vacuum to protect steel surfaces. The nitrogen will saturate the condensate to reduce exposure to oxygen cell corrosion. We have installed nitrogen taps in certain locations on our Power boilers and heat exchangers to provide a source for nitrogen blanketing during off line conditions.

 

[James01]

RNDguy / Edstainless / metengr

When we did further investigations of our heating medium (shell side) we found that the corrosion inhibition was out of control, there had been regular checkss on its quality but the feedback loop to the operations department just wasnt there. The chemists would say that the CI levels were down, but would not advise on how much to ad to bring the system back to full spec. The ops guys would just put in what they thought would be sufficient and so it went on.

In the oil on the tube side it was determined that to be effective the CI had to be in a turbulent flow regime and when stagnant for a period of a few days the CI would cease to be effective. This unit would stand idle in stagnant conditions for periods of up to 3 weeks at a time.

The Root Cause Analysis we carried out certainly identified a lot of areas for improvement.

 

[unclesyd]

In all Hx's that have experienced stagnate conditions at any time, with or without corrosion inhibitor, the chief suspect should be Microbiological Induced Corrosion (MIC).

These fellows are everywhere and affect either CS or SS with equal vigor.

You might want to get MIC test kit and checkout the corroded area as per instructions.

 

[RNDguy]

unclesyd:
Any references to read up about MIC? Thanks.

 

[James01]

Their are SRB's in the oil system and we instigated a regular monitoring and biociding programme a couple of years ago.

 

[unclesyd]

Test kits and some information under downloads.

http://www.bti-labs.com/home.cfm

Some very excellent links to information on ‘bugs’.

http://www.mic-testing.com/links.htm

This is good source of information from Iraly/China. It is focused on Chlorine Dioxide but there is a lot of general information on ‘bugs’ also.

http://www.clo2.net/en/thesis/once.phtml

You might want to look at these material for use during periods of inactivity. There is a good manual.

http://www.cortecvci.com/Publications/Lay-Up/lay-up.html

 

[RNDguy]

Thanks unclesyd.