You can get galvanic corrosion even with similar metals. The weld on carbon steel is typically anodic to the base metal.

The key in your case is to have a large ratio of CS to more noble metals. The large amount of CS will share the burden of loss over a large area which will prolong the life of the system.

Coatings complicate things because a defect in the coating concentrates the galvanic corrosion in that area which can lead to pitting.

Thank TugboatEng

As per API 571, for galvanic corrosion to occur, it must have all three factors available:

1. Metals with different potential
2. Electron path (connection between the two metals)
3. Conductive electrolyte solution

So for crude oil or gas services, the 3rd factor is missing (conductive electrolyte).

Didn't you say that salty brine water was present along with the Crude? If so the electrolyte is preseent.

Yes brine is present, but is it enough to make the whole fluid conductive? My question is just to understand the regulation and go-by practices required when joining dissimilar metals. For water services such as firewater services they will use Cu-Ni flanges with insulating gasket for connection with the FBE coated CS header. Is it the same with crude and gas piping?

Water cut of 30% is the break line between the crude not allowing free water to exist and having a water layer on the bottom of the pipe.

As water cut tends to increase over time, assume the is a water film there and with that much salt, it will be quite conductive.

But if you can coat the weld area you might be OK. Coating as noted above can act to concentrate the effect in a small area.

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

So if we have gas or dry crude services welding dissimilar metals is allowed as galvanic corrosion is not possible to occur? Is this a general practice is the oil and gas industries?

If you have dry service and full flow 100% of the time then you should be OK. But if flow ever slows or stops you will get moisture in the bottom of the line and can get severe localized attack.
If you are connecting CRA (625 in your case) to CS (even coated) it is wise to use much thicker CS near the connection.
Since this where galvanic effects would be concentrated having more of the less noble material is a good practice.
Internally coated lines are a real risk. There must be a very active monitoring and inspection program in place.
Any coating defect (and they are there from day 1) will become a site for localized attack.
Is there any CO2 in your crude?
That will lower the pH and make everything worse.

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

If you are going to put a dissimilar metal weld into sour service, how will the requirements of ISO 15156-2/3/NACE MR0175 be met?

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

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

"So if we have gas or dry crude services welding dissimilar metals is allowed as galvanic corrosion is not possible to occur? Is this a general practice is the oil and gas industries?"

Essentially yes, but in those circumstances you would be very unlikely to use coated pipe or a CRA.

You've got this issue because of the corrosive nature of the fluid lead you to a certain material choice. Benign fluid = carbon steel.

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

"If you are going to put a dissimilar metal weld into sour service, how will the requirements of ISO 15156-2/3/NACE MR0175 be met?"

Thank you for your respond Dr.

What are the requirements of ISO 15156?

ISO 15156-3/NACE MR0175 does NOT address the H2S cracking resistance of deposited weld metal at all. Thus, if you are asked to demonstrate how the dissimilar metal weld will be resistant to H2S cracking, how will you do it?

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

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

"ISO 15156-3/NACE MR0175 does NOT address the H2S cracking resistance of deposited weld metal at all. Thus, if you are asked to demonstrate how the dissimilar metal weld will be resistant to H2S cracking, how will you do it?"

But Dr. does this mean that weld overlay on cladded fittings are not meeting the ISO 15156 requirements?

Here is an official exchange that I have had with the committee responsible for interpretations after I submitted inquiry #2021-05:

Question
Further to the interpretation responses given to MP Inquiry #2013-02, is it to be taken that the heat treatment condition of the as deposited weld metal, that will also not comply with heat treatment requirements for certain materials listed in A.2 to A.11, will result in the same response, i.e. the cracking resistance is not addressed in the standard? If this is the case, should a note not be added to the standard to suggest to users that, if they are also seeking cracking resistance for the deposited weld overlay, then they should be looking to an Annex B methodology, or a documented field experience basis, to qualify the cracking performance?

Response
“It is correct that NACE MR0175 / ISO 15156-3 does not address the cracking resistance for as-deposited materials, including impact of heat treatments.

If the Inquirer wishes to consider the overlay as a barrier for cracking resistance, a ballot is required to define cracking limits for a specific as-deposited composition for a defined location within the weld. Testing according to Annex B or the use of documented field experience according to NACE MR0175 / ISO 15156-1 clause 8.2 should be performed.
The addition of a note to the standard will require a ballot. The ballot form and instructions can be found at MR0175 / ISO 15156 Ballot Proposal Form.”

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

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