Heat Exchanger Tube Failure 1

[Cor123]

Dear All,
We recently had tube pitting failure on Incolloy 800 tubes with incoloy 800 clad tubesheet. The pitting occurred inside out and upon ECI inspection widespread pitting was found with upto 60% wall thickness loss. Black adherent solid was also found in the tubes. We were lucky to get sample which showed corrosion products (26% FeS and higher percentage of Iron Carbonate )
The cooler is downstream of a compressor with 130 degree Celsius inlet temperature and 22 degree Celsius outlet. The pipework upstream of the cooler is CS. The gas is considered slightly wet (it's been scrubbed) but not dehydrated (as it's upstream of dehydration tower). Composition of the gas is 3 mol% CO2 and up to 3 ppm H2S. No chemicals are added.The cooling medium is inhibited MEG and water.
My theory has been that the pitting is a result of crevice corrosion as incoloy 800 doesn't contain Moleybdenum and therefore susceptible to Crevice under the fouling although I doubt other factors which support this mechanism are not available (chloride and Oxygen. Of course except the high temperatures). The presence of the corrosion products points to corrosion rather than erosion.
I would be grateful to hear your valuable opinions.
Many thanks for your help.

 

[metengr]

Your conclusion seems reasonable without viewing lab results.

 

[EdStainless]

Yes it sounds like under deposit pitting corrosion.
Look very carefully for Cl in the residue.
Why was 800 selected? The water that condenses will have a pH of about 3-3.5, way too low for 800. And under the deposits there will be no oxygen.
For this temp service you could have used 2205, or AL-6XN or Sea-Cure, any of which have much better corrosion resistance.
And the 2205 and Sea-Cure would be a lot less expensive, and the Sea-Cure would have a lot higher corrosion resistance.

On another note, what ECT standard was used? If it was a regular ASME standard then your reading are way off (maybe by a factor of 3).
You need to pull one leaking tube, but a clean part of it off to keep, then split the rest open.
Find some pits that have not gone through wall and measure them. My guess is that they are small, maybe 0.030" in diameter.
Then make a new reference standard that had ID pits (EDM them) that are 0.030" diam and 25%, 50%, 75%, and through wall.
Use that as a cal std and retest.
My hunch is that you will find a lot of small shallow pits, but few really big ones.

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P.E. Metallurgy, Plymouth Tube

 

[Cor123]

Many thanks to EdStainless and metengr for your valuable inputs. The materials were selected prior to my arrival and I have to deal with the consequences.
What intrigues me is whether the corrosion products have originated from the upstream CS pipework leading to subsequent under deposit corrosion or has it originated from the Incoloy 800? The Incolloy contains decent amount of chromium which should provide adequate protection against general CO2 corrosion.
Also, is it usual to find high content of FeS in a CO2 dominated corrosion (we have max 3 ppm H2S )? Does the FeS scale become cathodic to the Incolloy 800 at the high operating temperature leading to even more severe pitting? Anyone with an approximate rate of corrosion or literature case studies on similar systems?
Ed you were spot on regarding the sensitivity as the same tubes were inspected few months before the failure (30% of the tubes by ECI) with no defects picked up! !! When the failure occurred, another contractor was able to detect substantial pitting which raises alot of questions to the Inspection Engineers involved.

 

[EdStainless]

The corrosion products are mostly from upstream, and they settle out as the temperature drops and solubility change.
It is interesting because some deposits (or scales, they are all minerals) are more soluble at high temp, and some more soluble at low temp.
The FeS does not surprise me.
This could be a case of differential oxygen cells, with any H2S this will be a nearly oxygen free environment, but under the deposits there it will be highly reducing, and the 800 will not be able to re-passivate under those conditions.

The ECT standard must resemble the actual defects. An ASME standard is not suitable for use in a heat exchanger, unless you only goal is to identify tubes to pull for inspection. If you are doing ECT you must plan on pulling tubes, if you don't verify the test with actual samples your 30% reading could be 99%, or your 'all tubes over 60%' result which triggers a replacement could actually be some tubes in the 30% range.
In SS and Ni alloys there is no wall loss, there is no general corrosion, everything is pitting. So the ref standard must contain small diameter pit-like indications. Anything over 0.062" diameter is not useful at all.
This only changes when you are looking for external mechanical damage.

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P.E. Metallurgy, Plymouth Tube

 

[Cor123]

Thanks EdStainless for the fantastic contributions. Any idea on the rate of pitting degradation under thsee conditions? Given how thin the tubes are and the observed defects already observed, my fear is that the degradation rate will be rapid leading to another failure before the next shutdown.
Many thanks.

 

[SJones]

1. Could the iron sulphide and carbonate be depositing as a black powder coming through from the carbon steel system?
2. At the pressure and temperature of the process, what is the water dewpoint and where is it predicted to start dropping out as liquid water within the cooler and does that coincide with the zone of corrosion?

It is an unusual choice of alloy

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Cor123]

Hi Steve,
1. Yes, I agree that the scales are presumably from the upstream CS.
2. The perforation was observed near the tubesheet inlet. The pitting were widespread both on inlet and outlet ends. The gas is essentially wet at this stage.
I really don't understand on the alloy choice as I presume to be either poor judgement or worse. This more so as the upstream coolers are DSS. What's also intrigued me is that all other pipework (including downstream of this cooler) are duplex with the exception of upstream of this cooler (btw the compressor and the cooler which distance wise isn't too long either). My only guess is that beside cost,they probably wanted to avoid CSCC but surely duplex with robust coating (perhaps TSA) on the insulated line could have saved them all the headache? This shows what poor material selection can lead to.
Thanks

 

[EdStainless]

To avoid CSCC look at Sea-Cure, it is a superferritic.

Corrosion rate?, once pitting starts it will only take a few days to create a leak.
And once pitting starts you can't stop it by cleaning and treating, maybe slow it down a little is all.
At 130C you may have wet gas, but little condensation. As soon as you hit the HX things start condensing and corrosion takes over.

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P.E. Metallurgy, Plymouth Tube