Squeezing the Most Out of Your Materials Specialist

Experienced material specialists are in short supply and high demand these days. So if you are lucky enough to have one at your disposal, how can you squeeze the most out of that opportunity? (Okay, I am a materials specialist so I chose the word “lucky.” I know not all of you would use that adjective…)

Imagine you are inspecting an exchanger and you find what looks like some internal corrosion that you weren’t expecting to find. You look at the drum history and there is little of significant corrosion in previous inspection reports. You call the materials specialist to get their input and what usually happens is the 20 questions routine. You know what I’m talking about... What unit is it? What drum is it? What’s the material of construction? What temperature does it operate at? Where is the corrosion? Is it localized? How localized? How much wall loss did you measure? What does the metal surface look like? Is there any deposit? Is the surface clean and shiny? Was it steamed out before you inspected it? Do you see any similar corrosion in adjacent or associated equipment? What kind of corrosive elements are present in the process stream? Is there Sulfur, H₂S, hydrogen; and how much of each? At the end of the conversation you both set out to collect the necessary additional information before you can answer all of the questions to arrive at a conclusion.

Now let’s look at the same situation, but this time you have API RP 571 (“Damage Mechanisms Affecting Fixed Equipment in the Refining Industry”) available to you with some experience about how to use the information in it. You are called to do an inspection on the feed/effluent exchangers of the Naphtha Hydrotreating Unit in the plant. The effluent is on the tubeside and when the channel is opened for inspection, the channel surfaces are smooth but appear to be significantly thinner than the section near the flange. When you measure the channel wall thickness, wall loss from the last inspection done 5 years ago is 0.055 inches on the inlet side. Previous thickness measurements were essentially the same as the prior inspection. The hot end of the exchanger operates at an inlet temperature of approximately 655°F. The Hydrotreating/Hydroprocessing unit PFD in API RP 571 shows that Hydrotreating reactor effluent exchangers are potentially susceptible to the following mechanisms:

• 1 – Sulfidation
• 4 – High Temperature H₂/H₂S Corrosion
• 5 – Polythionic Acid Cracking
• 8 – Ammonia Chloride Corrosion
• 10 – High Temperature Hydrogen Attack
• 16 – Temper Embrittlement
• 25 – Hydrogen Embrittlement
• 32 – Sigma Phase/Chi Embrittlement

You already know that the material of construction is 5 Cr – 1 Mo and it operates at a temperature of 655°F. Since the damage occurring is wall thinning and in consideration for the fabrication material and high temperature exposure, the list of possible mechanisms is reduced to just two mechanisms:

• 1 – Sulfidation
• 4 – High Temperature H₂/H₂S Corrosion
• 5 – Polythionic Acid Cracking
• 8 – Ammonia Chloride Corrosion
• 10 – High Temperature Hydrogen Attack
• 16 – Temper Embrittlement
• 25 – Hydrogen Embrittlement
• 32 – Sigma Phase/Chi Embrittlement

But let’s go a little bit further in this analysis by using another industry tool, API RP 581 (“Risk-Based Inspection Technology”), which contains helpful but conservative corrosion calculators for the most common damage mechanisms. Part 2, Annex B is a section of the document that contains some fairly simple calculators for thinning damage types. Using these calculators, you find you need a few pieces of information from operations to evaluate the potential damage. You go talk to the operations engineer for the units to gather the necessary information for your analysis. In the process of your discussion you also find that the operating temperature in the effluent system has increased by about 80°F in recent years due to increased throughput requirements. The additional information you collected from your discussion is:

• 1 – Sulfidation
  • Naphthenic acid content – only applicable in hydroprocessing feed systems.
  • Operating temperature 655°F, increased from about 580°F in recent years.
  • % Sulfur is 0.4 wt. %

Estimated corrosion rate: 8 mpy for current operating temperatures, but 3-4 mpy for earlier operating temperatures.

• 4 – High Temperature H₂/H₂S Corrosion
  • Operating temperature 655°F, increased from about 580°F in recent years.
  • H₂S is 0.08 mole %

Estimated corrosion rate: 8.5 mpy for current operating temperatures, but 4 mpy for earlier operating temperatures.

With this information you go to your materials specialist and walk them through your logic to get validation on your conclusion. Since High Temperature H₂/H₂S Corrosion is the higher of the two potential mechanisms, you can assume that it is the dominant mechanism and the likely cause of the increased corrosion rates observed. You and the materials specialist determine that a maximum operating temperature of 600°F is appropriate for the material of construction unless an upgrade is possible at the next opportunity.

This approach saved a lot of time in determining the cause of corrosion and recommendations for safe operation in the future. You’ll learn more every time you do it and I promise it will get easier with time. I bet people will think you are really smart too!