gearteeth
Materials
- Jul 24, 2014
- 17
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?
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?
