Material Selection for CO2 service 3

[devaxrayz]

Dear all,

Like you all know that for H2S service there is a NACE MR-0175 that will determine the requirement of NACE approved material for Sour Service (H2S) depends on H2S partial pressure.

My question: is there any similar kind of NACE standard/requirement or else for vapor flow contain CO2.?

What is the criteria (limit) of CO2 (concentration or partial pressure) use for selection of corrosion resistance material rather than using usual carbon steel?

Thanks for any comment before...

regards,

Rayz

 

[0707]

Carbon dioxide (CO2) corrosion results when CO2 dissolves in water to form carbonic acid (H2CO3). The acid may lower the pH and sufficient quantities may promote general corrosion and/or pitting corrosion of carbon steel.

The partial pressure of CO2, pH and temperature are critical factors.

Increasing partial pressures of CO2 result in lower pH condensate and higher rates of corrosion.

Corrosion occurs in the liquid phase, often at locations where CO2 condenses from the vapor phase.

Increasing temperatures increase corrosion rate up to the point where CO2 is vaporized.
Increasing the level of chromium in steels offers no major improvement in resistance until a minimum of 12% is reached.

The 300 Series SS are highly resistant to corrosion in most applications. Selective upgrading to stainless steels is usually required in operating units designed to produce and/or remove CO2 (such as hydrogen plants and CO2 removal units). 400 Series SS and duplex SS are also resistant.

Luis

 

[EdStainless]

There is no firm requirement. Often you see straight Cr grades (9% or 12%) used for this service. It can be difficult to predict the conditions.

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Rust never sleeps
Neither should your protection

http://www.trent-tube.com/contact/Tech_Assist.cfm

 

[0707]

EdStainless

Yes, but chromium in steels offers no major improvement in resistance until a minimum of 12% is reached.

 

[dcasto]

Nace MR0175 also does the same for CO2 as H2S. The partial press of CO2 over 25 psia is considered the break over point for 304L SS. EXCEPT if there is no water present, then CS is fine no matter what the partial pressure is.

 

[EdStainless]

It depends a lot on temp, press, pPress, and so on, but 9%Cr or 9%Cr1%Mo is clearly better than CS in many cases where lower flow velocities are involved. At high velocity then you really do need a more robust alloy.

= = = = = = = = = = = = = = = = = = = =
Rust never sleeps
Neither should your protection

http://www.trent-tube.com/contact/Tech_Assist.cfm

 

[gr2vessels]

Since the threshold limit for the formation of chromium oxide is around 12%, most of the cheap, poor man's stainless steel like 3CR12 and the likes are suitable for environment with limited carbonic acidic condensation, but usually higher than saturation temperature, design with no crevices, perhaps accepting some erosive flow, restoring quickly the protective chromium oxide layer. As said above, anything below 12% Cr is waste of money, same goes for anything above 12%. Long list of materials with 12-12.5%Cr, starting with Columbus 3CR12 or 5CR12.

Cheers,

gr2vessels

 

[devaxrayz]

All... thanks for your post... there is always some knowledge i got everytime i start a thread

dcasto... The 25 psia partial pressure of CO2 is what i'm searching for. However if it not bother you, could you refer me to some document regarding to that value. Anyway thanks for the tips.

cheers,

-Rayz-

 

[Xeros]

De waard-Milliams nomograph could be used to estimate the rate of aqueous CO2 corrosion for carbon steel.

Critical factors are CO2 Partial pressure and temperature.

If the corrosion rate for CS is satified, you can apply CS. If not, ASS is recommended.

Ref.
1. C.de Waard and U. Lotz, Prediction of CO2 corrosion of carbon steel, CORROSION/93, Paper No. 69, NACE International
2. CO2 Corrosion nomograph or De waard-Milliams nomograph in website


Cheers,

- Xeros -

 

[devaxrayz]

Xeros..

Thanks for the information. However i find Norsok M-506 standard that could be useful for CO2 corrosion rate calculation. They offer the calculation spreadsheet too Just follow this link..

http://www.standard.no/imaker.exe?id=1369

Thanks for all comments...

-Rayz

 

[TomEun]

There is still no NACE standard (MR, RP/SP, TM) for CO2 Corroison. However NACE has a good publication below.

; CO2 Corrosion in Oil and Gas Production, NACE TASK Group T-1-3, 1984

 

[Oxidised]

Try this book, CO2 Corrosion Control in Oil and Gas Production - Design Considerations (EFC 23) available from Maney publishing.

http://www.maney.co.uk

It goes through the thought process required when choosing materials for CO2 (sweet) service. Often carbon steel and corrosion inhibition can be a cost effective alternative to CRA materials.

 

[strider6]

You have to use the DeWaard-Milliams model for CO2 corrosion, and all the improvement to the base formula. The first was written in 1991, and then during the years there have been a lot of changes to include all the factors that have an influences on the corrosion rate.
There is not a standard but you can find in NACE website all the articles on this issue and there are also commercial Software dedicated to this type of Corrosion.
Norsok is useful but have some limitations if H2S is contained in the fluid.
Hope this help

regards

Vitt

http://www.corrosionist.com

 

[zdas04]

One thing that hasn't been mentioned above is that CO2 can react with water to form either an acid (as was mentioned above) or a base. The base is carbonate and it is pretty benign in mild steel. I've sampled standing water in flow lines hundreds of times and the vast majority of the samples were condensed water vapor with a basic pH (very low TDS). At pipeline temperatures the reaction seems to drive toward carbonate instead of towards an acid, but I've never been able to find a predictive model to explain this preference (the energy requirements for the formation of the two compounds is very similar).

I've seen a lot of people use non-metallic and stainless flow lines because of fear of CO2 corrosion, and I've rarely seen CO2 corrosion in upstream Oil & Gas operations. It definitely happens, but it is less common than the literature would seem to indicate.

David

 

[SJones]

David,

I'll show you my library of CO2 related failures. Not pretty viewing. What you will also need to account for are:

Any bicarbonates around in produced water

or

Elevation of the pH owing to gas flashing during sampling.

When you say 'at pipeline temperatures the reaction tends to drive towards carbonate instead of acid', do you mean that the reaction product of the carbonic acid, and its dissociation products, with the iron of the steel pipe tends to form a carbonate corrosion product?

Kermani & Morshed's review: Corrosion, Vol 8, 2003, pp659-683 makes good reading on the subject.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[zdas04]

I'm talking about the reaction between dissolved CO2 and basically distilled water (condensed water vapor), I've run pH on many pools of standing water in pipelines when I've cut the lines for modifications and probably 3/4 of the time the pH was between 7.2 and 8.0 and the TDS was under 300 mg/L (produced water in this field does have bicarbonates in it, but the TDS is closer to 10,000 mg/L).

I certainly don't doubt that CO2 corrosion is a significant problem, I've seen it up close and personal and I believe the literature. My point is that the presence of CO2 is a necessary but not sufficient condition for CO2 corrosion. There are other possible reactions, and many people have over reacted to the possibility of carbonic acid.

David

 

[dcasto]

If there is no free water, then plain ol carbon steel.

 

[strider6]

Usually is not easy to determine if there will be no free water. It can be condensing water from a gas phase and then you'll have CO2 corrosion. CO2 corrosion is the first issue when you are in upstream, oil & gas, and if you have CO2 you're not sure to have corrosion but an assessment using the Corrosion Model of DeWaard or similar is necessary in my personal opinion.

regards

Vitt

http://www.corrosionist.com

 

[dcasto]

In midstream oil and gas we assume freewater until dehydration, however we risk base when to switch to SS. At presuures under 500 psig, no problem, over we look at where freewater could be and add SS to that area. On CO2 injection, once the pressure gets over 1000 psig, CO2 becomes hydroscopic and no freewater., However I've seen a major company install a 8" SS line on the amine vent system, heck with 25 ppm H2S in the CO2/water system, the H2S sets up a protective layer and the CO2/H2O cannot get to the CS pipe.