CO2 Corrosion - Pipeline Materials

[RandomAxe]

I'm looking at options for an oil and gas production pipeline (feasibility stage), the produced fluids have a high CO2 content (circa 18-20 mol%) and the reservoir conditions are close to dew point, no H2S. Its safe to say carbon steel will not work as a pipeline material, is there a guide or rule of thumb for what grade CRA material (or a lined/clad pipeline) would be required? Temperatures are also high at up to 110degC. I don't think 13cr would work either at that CO2 / water levels. So assume would be looking at 316L, 904L, super duplex etc?

 

[EdStainless]

What about salinity?
What is the pressure?

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P.E. Metallurgy, consulting work welcomed

 

[SJones]

NiDI CRA Materials Selection

Did corrosion modelling work rule out inhibition?

The pipe dimensions will be helpful to assess the choice between clad pipe and mechanically lined pipe.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/in/drstevejones

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

 

[RandomAxe]

Thanks for the replies. Looking at 6" to 10" pipeline. No corrosion modelling done yet, but OPEX concerns and its a subsea tie-back to subsea manifold, no CI injection currently. Reservoir pressure approx 5K. I'll review info for salinity.

 

[SJones]

The dimensions will favour MLP for any reasonable length of straight pipe. The rest of the pipeline components will probably be weld overlaid, or solid CRA for small diameter, say 2-inch. One of the factors in selecting the CRA will be exposure to seawater (or the ability to not have it).

If you have continuous MEG injection for hydrates, that could be a useful vehicle for inhibition.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/in/drstevejones

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

 

[LittleInch]

I would do something to see if you can get the temperature down as it will mess up your stability design for the pipeline and your coating choice.

How long is this line?
What's its design life?
Are you thinking of reeling it?

You have so many inputs to consider here that I don't think there are any ROTs that work for you.

If you can get the temperature down even to say 60 or 70C then other options start to become feasible.

Get a good metallurgist on the case for sure but also consider some of the RTP pipes if you're down at 6". Even two compared to a 10" Duplex or Super Duplex might be economic.

You may find you need to do some trials and tests on different materials to see if the cheaper options are man enough for 20 mol% CO2, high temp and high pressure.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[RandomAxe]

ROTs?

Its approx 12km, 15yr design life. Just at feasibility stage so nothing too detailed has been done yet - I'm reviewing well test data and running some economics. That NiDI CRA Materials Selection document is very useful, thanks. There was an 12 ion analysis done of water samples and it states high levels of sodium cations (10000mg/l) and chlorids anions (60000mg/l), so NaCl is present. Is the CO2 partial pressure on the graphs calculated from the mol% and the CITHP or the FWHP?

Yes it would most likely be reeled - may need to be pressurised for MLP at 8" or 10".

At this stage it looks like I'm best to assume super duplex, or maybe inconel lined. It could potentially be cooled down to those levels via a loop in a manifold structure but I think there would be hydrate concerns - requiring continuous chemical injection.

 

[EdStainless]

With that much CO2 and pressure you are talking about pH 3.5 or so.
Any Cl will rule out a 300 SS, and how much will guide if 2205 would work.
With those Cl you are looking at Ni lined (C276?).

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

 

[RandomAxe]

Thanks, much appreciated.

 

[LittleInch]

ROT = " ...is there a guide or [highlight #FCE94F]rule of thumb[/highlight] for "

That's fairly nasty set of conditions.

The issue with no continuous injection of Hydrate Inhibitor is what happens when your pipeline stops flowing without warning and then cools down. On restart you can create a blockage pretty easily. Then you end up with needing to heat the pipeline but 12kms long is quite long for that subsea.

Interesting little study you have there, but no easy answers.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[RandomAxe]

Thanks LittleInch, yeah from what i've read so far the existing development has not used methanol - but has spare cores in the umbilical so I think we'd need the ability to inject at least some of the time for the reasons you stated. Thanks again

 

[SJones]

Use design pressure to give the pCO2 at this stage of your evaluation. As the design progresses you can get smarter with better data. Butting will have GluBi pipe for reeling without pressurisation, if single source pipe supply is still economical. At first sight, it looks like an 825 liner which will be a lot of cash for a 15 year design life. But, we are only armchair commentators. Nevertheless, let us know how you are getting along.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/in/drstevejones

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

 

[RandomAxe]

Thanks Steve