Conversion of Carbides to Graphite in Carbon Steel Pipe at High Temps 3

[NozzleTwister]

I'm currently reviewing an existing FCC Reactor Overhead Vapor line that was installed in 1950 and operating since then. The material is 20" Sch. 30 (.500") A106, Gr. A. The original line has never been replaced. Recent inspection reports show this line still is very close to the originally specified wall thickness. The pipe is 'hot wall' with external heat conservation insulation.

I've recommended that this line be replaced with A335-P11 which is the norm for this service but the client is reluctant to replacing the line (due to the significant costs) and would rather continue using the existing line so long as pipe wall, the current support arrangement and flexibility are adequate at the higher temperature. If not, what minimal changes will be required?

The closest code that I’ve found to that era is a 1943 Unfired Pressure Vessel Code although the correct code would be the ASA B31.1, American Standard Code for Pressure Piping that was in effect in 1949 or 1950. In that 1943 Vessel Code there are two rows of allowable stresses for A106, Gr. A, the row with the highest allowables refers to a note that says, “These stresses permitted only if 0.10 per cent minimum silicon is expressly specified.” Which at this point is unknown so I’ve opted to use the lower values which result in the hot allowables of:

921 deg. F. Current operating temp. Sh = 3644 psi
950 deg. F. New operating temp. Sh = 2600 psi
1000 deg. F. New design temp. Sh = 1350 psi I have requested a review of the design temp.

Maybe this is too much back ground but that’s what I’m dealing with. I’m not asking for help with supports or flexibility but am very interested to know the risks of increasing the temperature of this carbon steel line that has already been operating in excess of 900 deg. F. for the last 55 years and how can those risks be evaluated? What are the risks of graphitization?

"Conversion of carbides to graphite MAY OCCUR after prolonged exposure....." isn't very strong language when trying to convince a client to replace the line. Can you direct me to any references that expand on this phenomena? Can a failure be predicted? Can a pipe be tested to determine if the conversion has occurred?

Also, can you direct me on how to know if I am in the creep range at higher temperatures and what extra precautions that I need to consider?

Any advice you can spare will be most helpful.

Thanks,


NozzleTwister
Houston, Texas

 

[metengr]

NozzleTwister;
Based on the information that you provided, the SA-106 Grade A pipe material can still remain in service or can be fit for service provided the following information is obtained with suggested recommendation for condition assessment;

What is the current and past operating temperature of the line?

If it is below 850 deg F metal temperature, and given that the steel was killed with silicon and not aluminum, I would expect that the risk of graphitization would be low to medium risk at circumferential (girth) welds in this line. Most likely you will have a spheroidized microstructure, which is not unexpected. If the line was operating above 900 deg F, the condition assessment recommendations in step 3) below are highly recommended;

What I would do to assess the steam line before suggesting replacement is to do the following;

1. Locate as many circumferential weld joints (as possible) and strip the insulation back to expose a 6" wide band on either side of each weld joint.

2. Grit blast the surface and perform a wet fluorescent MT, and measure the circumference of the various pipe spools using pi tape.

3. Depending on the results from step 2), do the following;

a). Perform a surface replication on the pipe base metal that was exposed either side of the girth weld to evaluate the microstructure at the various locations along the steam line. If the microstructure is heavily spheroidized or shows signs of graphitization, I would proceed to step b) below

or

b) commit to removing one or more 1" diameter plug samples for thru thickness metallographic examination. Frankly, performing b) would arm you with thru thickness information that would be valuable for the condition assessment.

The holes where the plugs were removed can be tapped for RT plugs, and seal welded.


Either a) or b) above will provide you with the necessary information regarding the metallurgical condition of the steam line.

You might be surprised that the steam line is still in relatively decent condition or fit for service.

 

[metengr]

As a continuation of the above (sorry about the lengthy dissertation) recommendations, determination of current and past operating temperature is critical information for a proper condition assessment. One other question - have there been any leaks or weld repair from leaks to this line over the 55 years of service?

Future operating temperature should remain below 850 deg F, meaning potential derating which may or may not economically justify replacement of the line. The fact that the line is seamless material is definitely a plus with leak before break at girth weld locations, provided there is no graphitization.

 

[NozzleTwister]

metengr,

Thank you very much for your detailed response!

Some comments: This line is not a steam line but is a hydrocarbon line in a refinery process. It has operated in the 900-925 deg. F. range for it's entire life. The nature of the process would not allow a reduction in temperature.

Today I was told the temperature for the line may not increase and the review of the system may be deleted from our scope (we'll have to wait on that). The revamp is basically for EPA requirements with some additional modifications to improve efficiency and yield.

Besides the possible graphitization issue, I'm concerned because the slight increase in temperature reduces my allowable stresses dramatically and will require additional supports. Also the existing support attachments will need to be re-evaluated. Increased thermal expansion and reduced allowables also brings the thermal stresses above code allowables.

While there is reluctance to replace the line due to installed cost, there is willingness inspect this line to prove it still has life left, even at a higher temp.

Back to Graphitization, from your reply, I understand the graphitization is only a risk at the welded joints?

Also, in your item 2) with the wet fluorescent MT, are we looking for cracks? And measuring the circumference, we're checking for bulging in the heat affected zone?

Again, thank you for your valuable input! Stars for you.

Best regards,


NozzleTwister
Houston, Texas

 

[metengr]

NozzleTwister;
Sorry about the steam line reference, it is what I deal with day in and day out and is second nature.

I would recommend a rigorous monitoring of this process line every 2-3 years or 25,000 operating hours if you intend not to derate current process temperatures. I agree that the pipe should be re-evaluated for adequate support especially if the owner intends keep the line in service under present operating conditions.

Regarding graphitization, this damage mechanism is driven by both stress and metal temperature. The reason for my recommending to inspect girth welds first is to look for cracks along the toes of the girth welds, and if graphitization does occur, it would tend to manifest itself in pipe spools at highly stressed locations, like girth welds or at terminal points.

The measurement of the circumference is to check for obvious creep swell from past service, and baseline data for future monitoring as discussed above.

Based on your last post, I would strongly recommend removal of several pipe plugs for detailed metallographic examination, and some possible isostress creep testing, if necessary.

 

[stanweld]

The comments provided by metengr would essentially satisfy API 510, 8.3 together with engineering calculations supporting the Rerate. Increasing operating temperature could prove highly detrimental to remaining service life. I would shorten my interval time to one year for inspection for the initial inspection, assuming creep damage is not readily evident.

 

[stanweld]

Correction; change API 510 to API 570.

 

[NozzleTwister]

metengr & stanweld,

Thanks for your valuable advice and sharing your knowledge. I'll review API 570, 8.3 and pass on these inspection recommendations. I know our client doesn't want to continue with a system that is unsafe, but they also don't want to spend that much money without knowing how much life it has left.

NozzleTwister
Houston, Texas

 

[stanweld]

One other item to look for; check the remaining wall at the circumferential weld seams. Oft times the weld will preferentially corrode and there have been more than a few catastrophic failures resulting there from.

 

[robsalv]

Would love an update on this one!

Great posts Metengr.

I'd be surprised to find no metallurgical degradation after that long in service at those temperatures.

My bet would be that spheroidisation will be found.

My questions are though:
* How does one relate the degree of spheroidisation / graphitisation to remaining life?
* Is it even meaningful to think of remaining life with this degradation mechanism in play?

Graphitisation effectively weakens the structure right - so code allowable stress values are meaningless and continued operation just eats into the code FOS's so replacement within a convenient time frame would be mandatory. Thoughts?

Thanks in advance.

Rob

 

[metengr]

robsalv;
Graphitization in itself may not appreciably weaken the tube metal until you develop "eyebrows" or "chains" which provide a plane or zone of weakness. Weld heat affected zones and remnant cold work in tubes and pipe are preferred sites for graphite nodules to develop in service. I have seen many C-Mn, C-Mn-Si and C-Mo boiler tubes contain random graphite nodules that were left in service until a scheduled change-out with no failures or impact on boiler reliability.

Once the carbon forms nodules, the surrounding ferrite becomes essentially pure iron and is quite brittle. Random distribution of nodules is not enough to result in brittle fracture because you still have remnant ferrite and iron carbide to provide strength and ductility. However, once a preferred path of graphite chains or eyebrows forms in tube or pipe, any sudden operating transients that create thermal or mechanical tensile stresses can result in failure of the tube or pipe.

There have been studies and several papers dating back to the 1950’s where correlations were developed based on the degree of spheroidization and exposure to service temperature. However, once graphitization has developed you need to consider a scheduled replacement of the material especially if it concerns safety outside the boiler setting (like drain lines or piping links), and if internal to the boiler like tubes or piping to assure future boiler reliability. I have not seen any reputable correlation with severity of graphitization and remaining service life for the reasons stated above.

 

[SMF1964]

metengr - is it the 'pure' iron that is brittle or the graphite and the graphite/iron interface that has no strength? Or is it that iron is pretty ductile on its own, but may have a lower yield than the surrounding material and so plastic deformation may concentrate in the carbon-depleted iron, resulting in failure by ductility exhaustion?

 

[metengr]

It is the pure iron surrounding the graphite nodules that increases susceptibility to failure in service. I have seen reports that indicate creep and tensile strength are reduced from carbon depletion. Certainly, the interface between the low strength ferrite and graphite will act as sites for creep cavitation.

The enhanced susceptibility to brittle fracture has more to do with the increase in volume fraction of ferrite phase over time, which under certain conditions, can provide a preferred path for cleavage below a certain service temperature (most likely during start-up).

 

[kenvlach]

I suggest also considering the effects of the contents at higher temperature.
Might carburizing conditions be created by partial decomposition of the HC at higher temperature?
Or, is oxygen or water present to passivate the surface?

 

[metengr]

kenvlach;
Interesting point. Even if one were to have potential carburizing conditions from fluidized catalytic cracking, the increase in carbon along the surface of the line would not necessarily be detrimental. At the stated temperatures, carbon diffusion would be limited at best and would not affect the overall structural integrity of the line. This would be no different than local decarburization I have seen with superheater boiler tubes that have been exposed to steam service for hundreds of thousands of hours. The ID surface of reheater and superheater tubes can develop ID surface decarburization for up to 0.030" in depth with no deleterious effects on the performance of the tube.