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Delayed Coking - Under Deposit Corrosion - LKGO
2

Delayed Coking - Under Deposit Corrosion - LKGO

Delayed Coking - Under Deposit Corrosion - LKGO

(OP)
We recently experienced through wall failure due to what appears to be under deposit corrosion in the light coker gas oil fraction. The draw temperature on this cut is right at 400F so I would consider run conditions to be too cool for high temperature corrosion mechanisms (sulfidation, naphthenic acid corrosion) and above the temperature for aqueous mechanisms. Site corrosion documentation reference the potential for various mechanisms of both types in this cut but assign a low likelihood of occurrence.

Corrosion resembles a trough along the bottom of the pipe. Multiple failures have occurred at bottom dead center. Initial AUT scans show consistent damage ranging from very thin to mid-wall thinning along the trough that has formed. We're early in the scope of inspection so we have limited data, there will be much more inspection to come in the form of GUL and AUT.

The fractionator tower top was replaced last year due to salt corrosion, both ammonia and amine salts. We have since been better sampling our overhead water chemistry and using an ionic model to observe salt and dew point limitations. All process and pressure drop monitoring indicates that this has been working. Because of this history with salts and being out of range for high temp mechanisms, ammonium/amine chloride salt corrosion is the leading mechanism I'm considering right now.

One piece I question is the operating temperature. At 400F and low pressure we are well above dew point. Any salts present should be dry. All the literature search I've turned up discuss the mechanism with an aqueous component, wet salt corrosion. This would limit the corrosion to downtime. From talking with different folks I've come across two claims that I haven't been able to turn up much literature on, 1. "molten" salts or mobile salts 2. Amine salts that have an OH component that don't necessarily need any water to be corrosive.

What am I missing? Any literature that may fill gaps?

RE: Delayed Coking - Under Deposit Corrosion - LKGO

What is the material?
At 400F many salts are molten, and not 100% dry either.
Being on the bottom raises some possibilities, either under deposit once they formed or during a shutdown when residue sat in the bottom of the tubes (and maybe picked up moisture).

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, Plymouth Tube

RE: Delayed Coking - Under Deposit Corrosion - LKGO

(OP)
Carbon steel. All the literature I've found on molten salts is very high temperature, but this is the type of information I'm looking for. Any literature or further information on molten salts at intermediate temperatures would be helpful. I'm not able to turf anything up.

We recently came out of an unplanned outage so the shutdown piece may play a role. Thanks

RE: Delayed Coking - Under Deposit Corrosion - LKGO

2
I'd definitely get a sample from a low point if possible for analysis.

Have seen liquid MEA chloride salts in a lcgo draw so bad that the line was eventually upgraded to inco 825 and eventually c276.

Nathan Brink

RE: Delayed Coking - Under Deposit Corrosion - LKGO

(OP)
@NBrink, we got a sample from a low point and performed a water extraction and we got corrosion scale after a portion of the pipe was cut for metallurgical analysis. Both confirmed the presence of MEA and chlorides in great quantities. We should be getting the full metallurgical report soon.

Thanks everyone for your input.

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