Seasoned and knowledgeable inspectors are becoming harder and harder to keep. But using some of the industry documents in a smart way, inspectors with less experience can perform like an inspector with many more years of experience and even develop a great materials specialty with practice.
Developing comprehensive equipment inspection plans is an important part of assuring the ongoing safety and reliability of plant fixed equipment. If you don’t have an experienced materials specialist to help identify potential damage mechanisms, the information provided in API RP 571 can serve as a systematic process for identifying potential damage mechanisms. This is essential for creating effective inspection strategies. Let’s walk through a couple of examples to demonstrate.
Your supervisor gives you a list of equipment for you to write a detailed inspection plan. The first is a crude column and associated equipment:
- Crude column
- Overhead exchangers, reflux drum and piping
- Pumparound systems and piping
- Reboiler system and piping
- Bottoms product and piping to the pump
One of the first things you will probably do is review the inspection history for the equipment over the last 10 or more years with an eye for the potential damage mechanisms above. The histories will indicate whether any of these types of damage have been observed in the past. The inspection history should include thickness data looking for indications of corrosion, particularly localized thinning.
Potential Damage Mechanisms for all the pumparound systems, column bottom and associated piping and equipment:
- 1 – Sulfidation
- 6 – Naphthenic Acid
As API RP 571 shows, a large portion of the corrosion loops and equipment are susceptible to sulfidation, possibly in combination with naphthenic acid corrosion. Sulfidation is most often generalized in nature but naphthenic is most often localized. The localization is dependent on the concentration of sulfur, naphthenic acid and process stream velocity at temperatures from approximately 350OF and 750OF. Type 317L stainless steel is used to minimize or eliminate corrosion. With this in mind, the inspection plan should be concentrated on areas with carbon and low alloy, low chromium, high chromium steels and stainless steels operating at temperatures > 350OF. The areas most vulnerable are high velocity areas such as turbulence and mixed phase streams. These areas are typically near inlet nozzles and at tray downcomers or demister pads in pressure vessels. For piping, velocities are highest near pumps and process flow changes such as elbows, tees and reducers. The damage descriptions for sulfidation and naphthenic acid will provide insights into where inspection should concentrate. All of this information is in API RP 571 and important for making inspection and NDE decisions, where and how to look for the corrosion.
Without operating data to more accurately predict the presence of mechanisms and susceptibilities, the inspection plan will be conservative. However, if the information required to fine tune the damage prediction and even calculate the potential corrosion rates (reference API RP 581 Part 2, Annex B to identify operating data needed) are known, optimized inspection plans may be developed.
The overhead system is a little more complex. Potential Damage Mechanisms for column overhead and reflux equipment (per API RP 571):
- 2 – Wet H2S
- 5 – Polythionic Acid Cracking
- 8 – Ammonium Chloride
- 9 – HCl Corrosion
- 20 – Erosion/Erosion Corrosion
- 42 – CO2 Corrosion
- 48 – Ammonia Stress Corrosion Cracking
- 52 – Liquid Metal Embrittlement
- 66 – Organic Acid Corrosion
The difficulty in this corrosion loop is that the potential damage mechanisms that will actually occur are dependent on the materials of construction, operating temperature and other process conditions such as pH. Since that is more than most inspectors are going to try to define let’s do a little bit of screening to get a feel for the advantages of using API RP 571.
Polythionic Acid Cracking and Liquid Metal Embrittlement present potential problems with Type 300 series stainless steels. If Type 300 series stainless steels are not used in the overhead, these mechanisms are not active. Wet H2S damage and Ammonia Stress Corrosion Cracking may occur in carbon steels in alkaline conditions. Most often, atmospheric column overheads are neutral or slightly acidic due to chlorides. For this corrosion loop, the primary concern is internal thinning and corrosion at and below the dew point (where water condenses). The corrosion is likely to be localized due to chlorides forming other corrosive products in aqueous conditions. The damage descriptions for the thinning mechanisms will provide insights into where inspection should concentrate. Finally, cracking is a potential damage type with H2S damage being the most likely. Including some weld related inspection or for possible hydrogen blisters of primarily non-PWHT’d pressure vessels may be included in the plan.
API RP 571 includes a fairly conservative list of possible damage mechanisms, even if they are not highly likely to occur. Having an experienced materials specialist to consult with can help you screen out inactive mechanisms and focus the plan on active mechanisms. If you don’t have a materials specialist available, the most effective method is to concentrate on the materials of construction, operating temperatures and damage types (thinning, cracking, etc.) to identify the active mechanisms, group the mechanisms by damage type for each material of construction and develop the inspection plan based on methods for detecting and sizing those specific types of damage. Most corrosion loops will be relatively simple and not nearly as complex as an atmospheric column overhead. You’ll learn more every time you do it and it will get easier with practice.