Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

ANSI/API RECOMMENDED PRACTICE 571 THIRD EDITION, MARCH 2020

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Foreword

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Contents

Page

1. Scope 1

2. Terms and Definitions 2

   1. Definitions 2

   2. Acronyms and Abbreviations 4

3. Damage Mechanisms 9

   1. 885 °F (475 °C) Embrittlement 9

   2. Amine Corrosion 12

   3. Amine Stress Corrosion Cracking 18

   4. Ammonia Stress Corrosion Cracking 24

   5. Ammonium Bisulfide Corrosion (Alkaline Sour Water) 28

   6. Ammonium Chloride and Amine Hydrochloride Corrosion 33

   7. Aqueous Organic Acid Corrosion 36

   8. Atmospheric Corrosion 39

   9. Boiler Water and Steam Condensate Corrosion 42

   10. Brine Corrosion 45

   11. Brittle Fracture 49

   12. Carbonate Stress Corrosion Cracking 55

   13. Carburization 65

   14. Caustic Corrosion 69

   15. Caustic Stress Corrosion Cracking 72

   16. Cavitation 81

   17. Chloride Stress Corrosion Cracking 86

   18. CO2 Corrosion 93

   19. Concentration Cell Corrosion 98

   20. Cooling Water Corrosion 101

   21. Corrosion Fatigue 105

   22. Corrosion Under Insulation 111

   23. Creep and Stress Rupture 120

   24. Dealloying [See Graphitic Corrosion (3.33) for Dealloying of Cast Iron] 126

   25. Decarburization 130

   26. Dissimilar Metal Weld Cracking 133

   27. Erosion/Erosion-Corrosion 144

   28. Ethanol Stress Corrosion Cracking 149

   29. Flue Gas Dew Point Corrosion 157

   30. Fuel Ash Corrosion 159

   31. Galvanic Corrosion 164

   32. Gaseous Oxygen-enhanced Ignition and Combustion 168

   33. Graphitic Corrosion of Cast Irons 175

   34. Graphitization 181

   35. High-temperature H2/H2S Corrosion 186

   36. High-temperature Hydrogen Attack 189

   37. Hydrochloric Acid Corrosion 197

   38. Hydrofluoric Acid Corrosion 200

   39. Hydrofluoric Acid Stress Corrosion Cracking of Nickel Alloys 210

   40. Hydrogen Embrittlement 213

   41. Hydrogen Stress Cracking in Hydrofluoric Acid 219

   42. Liquid Metal Embrittlement 221

   43. Mechanical Fatigue (Including Vibration-induced Fatigue) 225

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       Contents

       Page

   44. Metal Dusting 234

   45. Microbiologically Influenced Corrosion 238

   46. Naphthenic Acid Corrosion 244

   47. Nitriding 248

   48. Oxidation 252

   49. Oxygenated Process Water Corrosion 258

   50. Phenol (Carbolic Acid) Corrosion 261

   51. Phosphoric Acid Corrosion 263

   52. Polythionic Acid Stress Corrosion Cracking 265

   53. Refractory Degradation 272

   54. Stress Relaxation Cracking (Reheat Cracking) 274

   55. Short-term Overheating-Stress Rupture (Including Steam Blanketing) 281

   56. Sigma Phase Embrittlement 286

   57. Soil Corrosion 293

   58. Sour Water Corrosion (Acidic) 297

   59. Spheroidization (Softening) 300

   60. Strain Aging 303

   61. Sulfidation 305

   62. Sulfuric Acid Corrosion 312

   63. Temper Embrittlement 316

   64. Thermal Fatigue 320

   65. Thermal Shock 327

   66. Titanium Hydriding 329

   67. Wet H2S Damage (Blistering/HIC/SOHIC/SSC) 334

4. Process Unit Process Flow Diagrams 345

Annex A (informative) Useful Standards and References Relevant to this Recommended Practice 363

Annex B (informative) Technical Inquiries 367

Introduction

While ASME and API design codes and standards provide rules for the design, fabrication, inspection, and testing of new pressure vessels, piping systems, and storage tanks, they do not address equipment deterioration while in service, nor do they account for original fabrication defects not discovered during construction but found during subsequent inspections.

The interactions between the materials of construction and the environmental conditions to which they are exposed, including process conditions and external conditions, are extremely varied within an operating oil refinery. Oil refineries contain many different processing units, each having its own combination of process streams and temperature/pressure conditions. The purpose of this recommended practice is to describe the wide variety of service-induced damage and deterioration mechanisms, including corrosion and other types of metallurgical damage, that are most likely to affect the condition of the materials of construction commonly used in refinery equipment.

This document incorporates information gathered from major incidents in the refining industry and is intended to be consistent with applicable API documents as well as other related industry standards and practices. It is meant to provide guidance to pressure equipment integrity personnel but should not be considered the final technical basis for damage mechanism assessment and analysis or inspection and monitoring. The damage mechanism descriptions herein are not intended to provide a definitive guideline for every possible situation that may be encountered, and the reader may need to consult with an engineer or other corrosion specialist familiar with applicable degradation modes and failure mechanisms, particularly those that apply in special cases.

Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

1 Scope

This recommended practice discusses damage mechanisms applicable to oil refineries; however, much of the information herein can also be applied to petrochemical and other industrial applications, as the user deems appropriate. It is up to the user to determine the applicability and appropriateness of the information contained herein as it applies to their facility.

API 571 is a reference document that provides useful information by itself and also complements other API standards and recommended practices. The document should be utilized as a reference to other integrity related documents. It is intended to contribute to the overall management of pressure equipment integrity and is a useful resource for many mechanical integrity program activities including:

1. identification of existing damage or deterioration and anticipated rates of degradation,

   
   

2. identification of future damage mechanism susceptibilities,

   
   

3. development and maintenance of inspection and monitoring strategies, programs, and plans (e.g. per API 510, API 570, and API 653),

   
   

4. implementation and monitoring of integrity operating windows (IOWs) (see API 584),

   
   

5. development of corrosion control documents (CCDs) (see API 970),

   
   

6. implementation of Risk-Based Inspection (RBI) programs (see API 580 and API 581),

   
   

7. conducting Fitness-For-Service (FFS) assessments (see API 579-1/ASME FFS-1),

   
   

8. application of proper examination techniques, and

   
   

9. conducting pressure equipment integrity incident investigations (see API 585).

The information for each damage mechanism is provided in a set format as shown below.

• Name of the Mechanism—The term commonly used to describe or name the mechanism.

  
  

• Description of Damage—A basic description of the damage mechanism.

  
  

• Affected Materials—A list of the materials prone to the damage mechanism.

  
  

• Critical Factors—A list of factors that affect the damage mechanism (i.e. rate of damage).

  
  

• Affected Units or Equipment—A list of the affected equipment and/or units where the damage mechanism commonly occurs. This information is also shown on generic process flow diagrams (PFDs) for typical process units.

  
  

• Appearance or Morphology of Damage—A description of the damage mechanism, with pictures in some cases, to assist with recognition of the damage.

  
  

• Prevention/Mitigation—Methods to prevent or mitigate the damage and in some cases to evaluate by engineering analysis.

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