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CO2 Removal Unit Recurrent Leakages

CO2 Removal Unit Recurrent Leakages

CO2 Removal Unit Recurrent Leakages

Dear Experts,

Over the last 1 month we have observed 02 leakages from our CO2 removal unit piping. Request your expert advice on what are the likely cause(s) for these leakages and what can be done to prevent any further leakages. Given below are brief details of the process and respective leakage events.

Plant: Urea Fertilizer Manufacturing Plant
Unit: CO2 Removal Unit
Piping Loop Age: 30 years
Material: Carbon Steel
Service: Rich Solution (Hot Potassium Carbonate)
Temperature: 250 oF
Pressure (Absorber Outlet): 400 psig
Pressure (Stripper Inlet): 15 psig

Corrosion Rate: As per licenser the thickness loss for CS piping without passivation layer is estimated as 0.29 corrosion year/0.1 inch thickness loss. While with a passivation layer intact, it is estimated to be 1000 corrosion years/0.1 inch thickness loss. Hence it will not take more than a few months for our piping to corrode away in absence of a passivation layer.

Passivation Layer: Passivation layer is being achieved via introduction of Vanadium in process steam. Site has a practice of achieving passivation layer on piping loop for 12 hours in case service circulation is stopped for more than a few hours or any new component is added to the system. Additionally post plant turnaround interventions passivation layer is achieved for 24-36 hours. There is no reported instance of site not being able to achieve passivation layer as per aforementioned guideline.

Flow Rate: Piping loop design has been verified to confirm that piping flow rates through different pipe diameters is under maximum allowable flow rate recommended by licenser, with the piping flow rate being maximum of 9.1 ft/s through 20” absorber outlet line.

1st Leakage
1st leakage was observed from an elbow butt weld joint in pressure let down valves bypass line. This is the first elbow in immediate downstream of 8” branch line (bypass line of pressure let down valves). Elbow was removed and replaced with new one. No thickness loss was observed on base metal of elbow and piping, however upon internal inspection of elbow, damaged passivation layer was observed at upstream side of the elbow however passivation layer was found to be intact at downstream side of the elbow. Severe corrosion was also observed on HAZ area of leaking weld joint.

2nd Leakage:
2nd leakage was observed from a thermowell branch connection welding joint. Welding joint is fillet weld type. No thickness loss was observed in base metal adjacent to weld joint. Internal inspection could not be performed as box up was installed and plant was taken back in service.

In light of the above your expert opinion is requested on what could be the possible cause(s) of such leakages from weld joint only, with no detectable thickness loss on base metal. With plant being in service of 9 months since last Turnaround and piping age of 30 years, why is passivation layer only being damaged at weld joint and its HAZ.

Please refer to attachment for leakage pictures and P&ID.

RE: CO2 Removal Unit Recurrent Leakages

As you are hinting yourself it sound like erosion corrosion in both cases.

Welds may contain contaminants and thus be more susceptible tp corrosion but i would still think erosion corrosion when considering the location on the "back-side" of the thermowell (from photo).

Lowering velocity is one way of preventing erosion-corrosion.

Bestregrads, Morten

--- Best regards, Morten Andersen

RE: CO2 Removal Unit Recurrent Leakages

Dear Andersen,

Thank you for your feedback. We are struggling with why the HAZ is being attacked and that too of only upstream weld joint. Additionally with passivation layer intact, shouldn't corrosion become insignificant? Or is there any reason to believe that passivation layer can not form properly on weld joints and associated HAZ area.

RE: CO2 Removal Unit Recurrent Leakages

The local turbulence at a weld bead can be significant. You only to damage the passive film in a small area to set up corrosion, once started it can undercut the passive film.
There may also be an issue with the welding.
If all of the damage in in HAZs then perhaps you should weld procedures with regard to pre-heat, power, speed, and PWHT.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, consulting work welcomed

RE: CO2 Removal Unit Recurrent Leakages

I'm not sure how you can really identify failure mechanism without taking longitudinal cross-sections through both leaks. Erosion-corrosion can be confirmed looking at thinning wall geometry adjacent to the leak while welding and corrosion issues can be viewed as well.

RE: CO2 Removal Unit Recurrent Leakages

I am a newbie regarding Urea Plant corrosion, so forgive me if I re-state the obvious or misunderstand something ...

This student paper promotes the specification and usage of stainless steel . It contains this paragraph:


The corrosion behaviour of A106 carbon steel absorber for CO2 removal in amine is promoted
hot potassium carbonate solution (Benfield solution). A typical Benfield solution contains hot
potassium carbonate K2CO3, potassium bicarbonate KHCO3, diethanol amine (DEA) as a
promoter and potassium metavanadate KVO3 as corrosion inhibitor. K2CO3 with CO2 purging
showed that stress corrosion cracking readily occurred in this system. The stress corrosion
cracking of carbon steels in carbonate solutions occurred by the dissolution process of metal at
the crack tips. Magnetite passivity, however, may be vulnerable to process conditions such as loss
of inhibitor, flow accelerated corrosion and chemical breakdown in the presence of aggressive
ions, particularly chlorides. Magnetite films may also have a duplex structure and thick scales
which may form when corrosion inhibitor management practices are poor.

Additionally, I found this paper on Urea System Piping Revamp .... might be useful to discuss ...


Perhaps I am missing the obvious here, but,....

Was your Urea plant "upgraded" or "debottlenecked" thereby increasing the flow velocity in several piping systems ? This was done in many third-world Urea plants as MBA plant managers ran their equipment into the ground ....

Is it reasonable to state that these accelerated corrosion problems are the result of plant management (MBAs) "debottlenecking" or running carbon steel piping systems at flow rates far beyond the original design ? (Commonly, these destructive decisions, of course, maximize profits at the cost of capital plant destruction)

Perhaps, even though you state that there are no reports that plant staff has missed adding corrosion inhibitor. ... the plant staff may have missed things a few times ?

Is it also reasonable to assume that a particular grade of stainless steel piping would solve the corrosion issue if this were a brand new plant ?

Is there a lot more to this story ......?

Sr. Process Engineer

RE: CO2 Removal Unit Recurrent Leakages

MJC, Many of the new plants are still being built in CS, but with very careful attention to flow velocities, material specification, and weld procedures.
I have heard people tell me that they find it no more expensive (life cycle costs) to build in SS because even though the material is much more expensive; the fab is easier, operations can be more flexible, they don't have to worry about inhibition, and the plant lasts longer with less maintenance.
Pay me now or pay me latter.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, consulting work welcomed

RE: CO2 Removal Unit Recurrent Leakages

Thank You Ed for keeping me straight and providing the "rest of the story"....!!!

Yes, the eternal...."pay me now or pay me later !"

Why is it the original poster does not give us that fluid velocity at the points of failure ?


Sr. Process Engineer

RE: CO2 Removal Unit Recurrent Leakages


Ed explained it better than I did wrt. erosion corrosion, but of course it dosnt explain why you only see it at one place. But maybe velocity is not the same in the other places? Velocity has a big impact on this since the "energy" is tied to the velocity square.

--- Best regards, Morten Andersen

RE: CO2 Removal Unit Recurrent Leakages

I just noticed from the photo that for the pipe that you called "1st leak" the pattern is either top-of-pipe" or "bottom of pipe" (the other photo shows the pipe as horizontal). Is this pipe in non-stop operation or is there periods with no flow where a part of the pipe might drain? I realize that it dosnt explain why its at the weld but it might be a clue - especially if the pipe is turned upside-down compared to when it was installed?

--- Best regards, Morten Andersen

RE: CO2 Removal Unit Recurrent Leakages

MortenA, are you thinking about either fluid resting in the bottom during a down period or gas trapped in the top during a slow start up?
Both of those can cause real issues, and a slight bump of a weld can create a small trap that makes them worse.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, consulting work welcomed

RE: CO2 Removal Unit Recurrent Leakages

More information:

Some major steel producers have formulated a 316 SS blend specifically suited for corrosive UREA Carbonate service:





These are the majors, there are several other smaller wannabee SS vendors hoping to get into the market ....

Anybody have other comments about the correct material selection for a brand new plant ?

Are there any research papers out there evaluating the maximum acceptable fluid velocities for various materials in this service ..???

Anyone ???

Sr. Process Engineer

RE: CO2 Removal Unit Recurrent Leakages

The 'new' 316L Urea grades are a reflection of modern 316L being very lean in alloying.
Mills pushing elements down causes issues.
Low Mo reduced corrosion resistance and low Ni increases delta ferrite content.
Both of these hurt in Urea service.
But bumping up Ni and Mo quickly adds 20% to cost of raw materials.
And those of you that have welded 904L or alloy20 or a 6%Mo grade know the issues with welding ferrite free stainless.
In light gage it isn't bad, but nearly impossible in heavy sections.
But getting welds with low residual ferrite is one of the keys to improved performance.
Different sections of the plant have different alloy selection criteria.
Much of this is dictated in documents when you license a process (from the guys that you are buying catalyst from).
There are very few environments where SS is very velocity sensitive.
I would expect pumping issues to limit flow before erosion does.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, consulting work welcomed

RE: CO2 Removal Unit Recurrent Leakages

Dear Experts,

Got our process engineer to model the flow rate at different zones of the piping and as per flow simulation velocities are not higher than licenser recommended flowrate at different pipe sizes. I have attached the flow rate simulation model and licenser recommended max fluid velocities chart. Meanwhile I do believe localized flowrates at tees, elbows etc. must be higher than straight pipe lengths. Key questions are:

Irrespective of licenser recommendation what are the allowable flow rates for magnetite passivation layer to survive. Any independent guideline that stipulates the same
Any reason to believe passivation layer is not able to form properly at weld joint or HAZ area


RE: CO2 Removal Unit Recurrent Leakages

I know nothing about CO2, I'm a saltwater guy. Can you confirm that the erosion is happen in the HAZ or in the filler metal of the weld? In our experience the weld filler is sacrificial to the base metal under galvanic corrosion conditions. Due to the large ratio of surface areas the corrosion rate if the weld is quite rapid. The weld bead itself is affected and not the HAZ. I don't know if this is your case as I don't know if your process fluid is conductive enough to support galvanic corrosion.

RE: CO2 Removal Unit Recurrent Leakages


Did you consider the "top of pipe" (or bottom of pipe" issue? I think there might be a clue here. Especially of gas could get trapped here.

--- Best regards, Morten Andersen

RE: CO2 Removal Unit Recurrent Leakages

Lot of discussion here: Link

Steve Jones
Corrosion Management Consultant


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

RE: CO2 Removal Unit Recurrent Leakages

Dear Morten,

Attached is a close up of elbow cut at its weld joint area. Point of leakage in the elbow is 9 o clock position. Most of the weld joint on elbow was removed during welding joint removal however as you can see the HAZ area at both top and bottoms side is eroded. Depth and concentration of corrosion at bottom side is slightly higher than top side.

Any thoughts after the pictures review.

RE: CO2 Removal Unit Recurrent Leakages

Just an update on subject issue, over the course of this week we have been conducting in-service PAUT of butt weld joints in said piping. Weld joints have been carefully selected in immediate vicinity of both leakages and areas of relatively higher flowrate than running pipe length. So far out of the 12 inspected joints (weld as well as HAZ area) we have not detected any loss of thickness (localized or general).

My own hypothesis was that weld beads & pipe bends were causing flow induced erosion-corrosion which was resultantly damaging passivation layer and exposing vulnerable CS material. However so far we have not observed any weld joint with any loss of thickness that may indicate that this is a widespread phenomena.

In light of the above any thoughts on anything else that may be responsible for earlier observed leakages. I am not willing to put this down to any fabrication defect as this should have resulted in any issue much earlier in its 30 years of service.

RE: CO2 Removal Unit Recurrent Leakages

for ressembling-but-not-similar services (rich amine) we are used to limit fluid velocity below 1.5m/s whatever the diameter is. your velocity is @2.7 m/s and this may be too high vs. erosion-corrosion in this aqueous alkaline service.

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