Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

RECOMMENDED PRACTICE 571 FIRST EDITION, DECEMBER 2003

Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

Downstream Segment

RECOMMENDED PRACTICE 571 FIRST EDITION, DECEMBER 2003

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SPECIAL NOTES

(December, 2003)

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API is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions, nor undertaking their obligations under local, state, or federal laws.

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Copyright © 2003 American Petroleum Institute

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FOREWORD

(December, 2003)

This publication is a result of a need for a document that describes damage mechanisms affecting equipment in the refining and petrochemical industries. A key first step in safely and reliably managing equipment is identifying and understanding the relevant damage mechanisms. Proper identification of damage mechanisms is important when implementing the API Inspection Codes (API 510, API 570, API 653) and in conducting risk based inspection per API 580 and API 581. When performing a fitness-for- service assessment using API 579, the damage mechanisms need to be understood and need to be considered when evaluating the remaining life.

This publication contains guidance for the combined considerations of:

• Practical information on damage mechanisms that can affect process equipment,

• Assistance regarding the type and extent of damage that can be expected, and

• How this knowledge can be applied to the selection of effective inspection methods to detect size and characterize damage.

The overall purpose of this document is to present information on equipment damage mechanisms in a set format to assist the reader in applying the information in the inspection and assessment of equipment from a safety and reliability standpoint.

This document reflects industry information, but it is not a mandatory standard or code. In this regard, the terms shall and must are only used to state mandatory requirements with respect to the assessment procedures which may not otherwise be correct unless followed explicitly. The term should is used to state that which is considered good practice and is recommended but is not absolutely mandatory. The term may is used to state that which is considered optional.

This publication was prepared by an API Task Group that included representatives of the American Petroleum Institute and the Pressure Vessel Research Council, as well as individuals associated with related industries.

It is the intent of the American Petroleum Institute to periodically revise this publication. All owners and operators of pressure vessels, piping, and tanks are invited to report their experiences in utilizing this document.

API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any federal, state, or municipal regulation with which this publication may conflict.

Suggested revisions are invited and should be submitted to API, Standards department, 1220 L Street, NW, Washington, DC 20005.

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TABLE OF CONTENTS

1.0 INTRODUCTION AND SCOPE

1. Introduction. 1-1

2. Scope 1-1

3. Organization and Use 1-2

4. References 1-2

5. Definition of Terms. 1-2

6. Technical Inquiries 1-2

2.0 REFERENCES

1. Standards 2-1

2. Other References 2-2

3.0 DEFINITION OF TERMS AND ABBREVIATIONS

1. Terms 3-1

2. Symbols and Abbreviations 3-2

4.0 GENERAL DAMAGE MECHANISMS – ALL INDUSTRIES

1. General 4-1

2. Mechanical and Metallurgical Failure Mechanisms 4-1

   1. Graphitization 4-1

   2. Softening (Spheroidization) 4-5

   3. Temper Embrittlement 4-8

   4. Strain Aging 4-12

   5. 885oF Embrittlement 4-14

   6. Sigma Phase Embrittlement 4-16

   7. Brittle Fracture 4-19

   8. Creep / Stress Rupture 4-23

   9. Thermal Fatigue 4-27

   10. Short Term Overheating – Stress Rupture 4-32

   11. Steam Blanketing 4-35

   12. Dissimilar Metal Weld (DMW) Cracking 4-38

   13. Thermal Shock 4-42

   14. Erosion / Erosion-Corrosion 4-44

   15. Cavitation 4-49

   16. Mechanical Fatigue 4-53

   17. Vibration-Induced Fatigue 4-59

   18. Refractory Degradation 4-62

   19. Reheat Cracking 4-63

3. Uniform or Localized Loss of Thickness 4-65

   1. Galvanic Corrosion 4-65

   2. Atmospheric Corrosion 4-69

   3. Corrosion Under Insulation (CUI) 4-71

   4. Cooling Water Corrosion 4-75

   5. Boiler Water Condensate Corrosion 4-78

   6. CO2 Corrosion 4-80

   7. Flue Gas Dew Point Corrosion 4-84

   8. Microbiologically Induced Corrosion (MIC) 4-86

   9. Soil Corrosion 4-91

   10. Caustic Corrosion 4-95

   11. Dealloying 4-98

   12. Graphitic Corrosion 4-101

4. High Temperature Corrosion [400oF (204oC)] 4-105

   1. Oxidation 4-105

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   2. Sulfidation 4-109

   3. Carburization 4-113

   4. Decarburization 4-116

   5. Metal Dusting 4-118

   6. Fuel Ash Corrosion 4-121

   7. Nitriding 4-126

5. Environment – Assisted Cracking 4-130

   1. Chloride Stress Corrosion Cracking (CI–SCC) 4-130

   2. Corrosion Fatigue 4-135

   3. Caustic Stress Corrosion Cracking (Caustic Embrittlement) 4-138

   4. Ammonia Stress Corrosion Cracking 4-144

   5. Liquid Metal Embrittlement (LME) 4-148

   6. Hydrogen Embrittlement (HE) 4-152

5.0 REFINING INDUSTRY DAMAGE MECHANISMS

1. General 5-1

   1. Uniform or Localized Loss in Thickness Phenomena 5-1

      1. Amine Corrosion 5-1

      2. Ammonium Bisulfide Corrosion (Alkaline Sour Water) 5-4

      3. Ammonium Chloride Corrosion 5-8

      4. Hydrochloric Acid (HCl) Corrosion 5-10

      5. High Temp H2/H2S Corrosion 5-13

      6. Hydrofluoric (HF) Acid Corrosion 5-16

      7. Naphthenic Acid Corrosion (NAC) 5-19

      8. Phenol (Carbonic Acid) Corrosion 5-23

      9. Phosphoric Acid Corrosion 5-24

      10. Sour Water Corrosion (Acidic) 5-25

      11. Sulfuric Acid Corrosion 5-27

   2. Environment–Assisted Cracking 5-31

      1. Polythionic Acid Stress Corrosion Cracking (PASCC) 5-31

      2. Amine Stress Corrosion Cracking 5-37

      3. Wet H2S Damage (Blistering / HIC / SOHIC / SCC) 5-41

      4. Hydrogen Stress Cracking – HF 5-50

      5. Carbonate Stress Corrosion Cracking 5-52

   3. Other Mechanisms. 5-56

      1. High Temperature Hydrogen Attack (HTHA) 5-56

      2. Titanium Hydriding 5-61

2. Process Unit PFD’s 5-65

   1. Crude Unit / Vacuum 5-65

   2. Delayed Coker 5-65

   3. Fluid Catalytic Cracking 5-65

   4. FCC Light Ends Recovery 5-65

   5. Catalytic Reforming – CCR 5-65

   6. Catalytic Reforming – Fixed Bed 5-65

   7. Hydroprocessing Units – Hydrotreating, Hydrocracking 5-65

   8. Sulfuric Acid Alkylation 5-65

   9. HF Alkylation 5-65

   10. Amine Treating 5-65

   11. Sulfur Recovery 5-65

   12. Sour Water Stripper 5-65

   13. Isomerization 5-65

   14. Hydrogen Reforming 5-65

APPENDIX A – TECHNICAL INQUIRIES

A.1 Introduction ..........................................................................................................................A-1

A.2 Inquiry Format......................................................................................................................A-1

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SECTION 1.0 INTRODUCTION AND SCOPE

1. Introduction 1

2. Scope 1

3. Organization and Use 2

4. References 2

5. Definitions of Terms 2

6. Technical Inquires 2

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December 2003 API Recommended Practice 571 1-1

1. Introduction

   The ASME and API design codes and standards for pressurized equipment provide rules for the design, fabrication, inspection, and testing of new pressure vessels, piping systems, and storage tanks. These codes do not address equipment deterioration while in service and that deficiencies due to degradation or from original fabrication may be found during subsequent inspections. Fitness-For-Service (FFS) assessments are quantitative engineering evaluations that are performed to demonstrate the structural integrity of an in-service component containing a flaw or damage. The first step in a fitness-for-service assessment performed in accordance with API RP 579 is to identify the flaw type and the cause of damage. Proper identification of damage mechanisms for components containing flaws or other forms of deterioration is also the first step in performing a Risk-Based Inspection (RBI) in accordance with API RP 580.

   
   

   When conducting a FFS assessment or RBI study, it is important to determine the cause(s) of the damage or deterioration observed, or anticipated, and the likelihood and degree of further damage that might occur in the future. Flaws and damage that are discovered during an in-service inspection can be the result of a pre- existing condition before the component entered service and/or could be service-induced. The root causes of deterioration could be due to inadequate design considerations including materials selection and design details, or the interaction with aggressive environments/conditions that the equipment is subjected to during normal service or during transient periods.

   
   

   One factor that complicates a FFS assessment or RBI study for refining and petrochemical equipment is that material/environmental condition interactions are extremely varied. Refineries and chemical plants contain many different processing units, each having its own combination of aggressive process streams and temperature/pressure conditions. In general, the following types of damage are encountered in petrochemical equipment:

   1. General and local metal loss due to corrosion and/or erosion

   2. Surface connected cracking

   3. Subsurface cracking

   4. Microfissuring/microvoid formation

   5. Metallurgical changes

   
   

   Each of these general types of damage may be caused by a single or multiple damage mechanisms. In addition, each of the damage mechanisms occurs under very specific combinations of materials, process environments, and operating conditions.

   
   

2. Scope

General guidance as to the most likely damage mechanisms for common alloys used in the refining and petrochemical industry is provided in this recommended practice. These guidelines provide information that can be utilized by plant inspection personnel to assist in identifying likely causes of damage, and are intended to introduce the concepts of service-induced deterioration and failure modes.

The summary provided for each damage mechanism provides the fundamental information required for a FFS assessment performed in accordance with API RP 579 or an RBI study performed in accordance with API RP 580.

The damage mechanisms in this recommended practice cover situations encountered in the refining and petrochemical industry in pressure vessels, piping, and tankage. The damage mechanism descriptions 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 familiar with applicable degradation modes and failure mechanisms, particularly those that apply in special cases.